Nuclear Power in the United Kingdom

(Updated September 2020)

The UK generates about 20% of its electricity from nuclear, but almost half of current capacity is to be retired by 2025.

The UK has implemented a thorough assessment process for new reactor designs and their siting.

The UK has privatized power generation and liberalized its electricity market, which together make major capital investments problematic.

Construction has commenced on the first of a new generation of nuclear plants.

Operable nuclear power capacity

Electricity sector

Total generation (in 2017): 338 TWh

Generation mix: natural gas 137 TWh (40%); nuclear 70.3 TWh (21%); wind 50.0 TWh (15%); biofuels & waste 36.0 TWh (11%); coal 23.3 TWh (7%): solar 11.5 TWh (3%); hydro 8.8 TWh (3%); oil 1.6 TWh.

Import/export balance: 14.8 TWh net import

Total consumption: 301 TWh

Per capita consumption: c. 4600 kWh in 2017

Source: International Energy Agency, Electricity Information 2019. Data for year 2017

2017 electricity generating capacity was 103 GWe: 33.9 GWe natural gas, 19.8 GWe wind, 15.8 GWe coal, 12.8 GWe solar, 9.4 GWe nuclear, 4.6 GWe hydro, 5.0 GWe biofuels & waste and 4.4 GWe oil.

In the late 1990s, nuclear power plants contributed around 25% of total annual electricity generation in the UK, but this has gradually declined as old plants have been shut down and ageing-related problems affect plant availability.

There is a 2000 MW high-voltage DC connection with France, a 1000 MW one with the Netherlands and a 1000 MW one with Belgium. A final investment decision on a 1400 MW link – 'Northconnect' – over 750 km between Scotland and Norway is expected in 2020. A further 2000 MW connection to Normandy is planned.

Energy policy

UK energy policy since the 2008 Energy Act has largely been built around reducing carbon dioxide emissions rather than security of supply or cost. The 2008 Climate Change Act (CCA) set a goal to reduce greenhouse gas emissions by at least 80% by 2050 from 1990s levels. In May 2011, a target of 51% reduction from 1990 levels for 2022-2027 was added. In 2016 the government adopted the fifth carbon budget (covering the period 2028-2032), which targets a 57% reduction in greenhouse gas emissions relative to 1990 levels. Figures for 2018 show a 43% reduction from 1990 levels. In June 2019, following the Intergovernmental Panel on Climate Change's (IPCC's) Special Report on Global Warming of 1.5°C, the CCA was amended to commit the UK to bringing all greenhouse gas emissions to "net zero" by 2050.

The UK used to be a large producer of oil and gas from the North Sea, but production has declined signficantly since its peak in 2000. In 2004 the country became a net importer of natural gas and in 2005 a net importer of crude oil. The drop in production has increased the country's import dependency significantly. During the decade 2007-2017 natural gas and oil net imports more than doubled.

Due to a policy of coal to gas switching, gas is a key pillar of the UK energy mix and is particularly important for electricity generation. In 2019, domestic production was sufficient to meet about 50% of demand. Since 2000, domestic production has declined by 65%. Most imports come via pipeline from Norway. In recent years, the proportion of gas imported as LNG has risen substantially, with Qatar the UK's largest supplier.

In November 2015 the government articulated new policy priorities for UK energy, involving possibly phasing out coal-fired generation without carbon dioxide abatement in 2025, building new gas-fired plants, and much greater reliance on nuclear power and offshore wind to grapple with “a legacy of ageing, often unreliable plant” and undue reliance on coal. The energy secretary said: "Opponents of nuclear misread the science. It is safe and reliable. The challenge, as with other low carbon technologies, is to deliver nuclear power which is low cost as well. Green energy must be cheap energy.

“We are dealing with a legacy of under-investment and with Hinkley Point C planning to start generating in the mid-2020s, this is already changing. It is imperative we do not make the mistakes of the past and just build one nuclear power station. " This was reinforced in July 2017 with the National Grid’s update of Future Energy Scenarios. In the light of projected peak demand of 85 GWe by 2050, its main scenario called for 14.5 GWe of new nuclear plant online by 2035, and nuclear supplying 31% of demand in 2050. Different scenarios concerning electric vehicles increase peak demand by 6 GWe, 11 GWe or 18 GWe by 2050 depending on when the majority are charged, and assuming 7 kW charging (30 amps). The corresponding increases in annual demand range from 15 to 45 TWh.

Electricity market reform

In its July 2006 energy review report, the government said that the European Union Emissions Trading Scheme (ETS, now referred to as the Emissions Trading System) must be strengthened in its Phase III (2013-2020) in order to "ensure that the EU ETS develops into a credible long-term international framework for pricing carbon."22 Should it be necessary to provide more certainty to investors, the government said it would "keep open the option of further measures to reinforce the operation of the EU ETS in the UK."

In July 2011 the government issued a new white paper on electricity market reform (EMR).35 Its four main proposals were: a carbon floor price; long-term contracts (involving feed-in tariffs with a 'contract for difference') to stabilise financial returns from low-carbon generation; a mechanism to ensure the provision of sufficient generating capacity nationwide; and an 'emissions performance standard' to prohibit the construction of high-carbon generation.

The Energy Bill introduced into parliament at the end of November 2012 was in line with the above principles and designed to attract investment to bring about a transformation of the electricity market, moving from predominantly a fossil-fuel to a diverse low-carbon generation mix. The Energy Act passed into law in December 2013, along with new provisions including the supplier obligation. It included:

Contracts for difference (CfDs) to stabilise revenues for investors in low-carbon electricity generation projects – renewables, new nuclear or carbon capture and storage (CCS) – helping developers secure the large upfront capital costs for low-carbon infrastructure while protecting consumers from rising energy bills. The feed-in tariff with CfD means that if the market price is lower than the agreed ‘strike price’, the government pays that difference per kWh, passing that cost onto electricity consumers. If the market is above the strike price the generator pays the difference to electricity consumers by reducing average tariffs. CfDs are long-term contracts which can be capped regarding quantity of power. The idea is that the carbon floor price will drive the market towards any feed-in tariff or strike price level applied to clean sources. The CfD strike prices for Hinkley Point C nuclear plant are set out below. The Czech Republic, Hungary, Poland and Slovakia are considering the UK CfD model for their own nuclear projects.

(CfDs) to stabilise revenues for investors in low-carbon electricity generation projects – renewables, new nuclear or carbon capture and storage (CCS) – helping developers secure the large upfront capital costs for low-carbon infrastructure while protecting consumers from rising energy bills. The feed-in tariff with CfD means that if the market price is lower than the agreed ‘strike price’, the government pays that difference per kWh, passing that cost onto electricity consumers. If the market is above the strike price the generator pays the difference to electricity consumers by reducing average tariffs. CfDs are long-term contracts which can be capped regarding quantity of power. The idea is that the carbon floor price will drive the market towards any feed-in tariff or strike price level applied to clean sources. The CfD strike prices for Hinkley Point C nuclear plant are set out below. The Czech Republic, Hungary, Poland and Slovakia are considering the UK CfD model for their own nuclear projects. A new government-owned company to act as a single counterparty to the CfDs with eligible generators, and to be central to industry cash flow. A two-stage process means projects are able to apply to the company for a CfD contract once they have cleared meaningful hurdles such as planning permission and a grid connection agreement, and then a small number of hurdles post-CfD award in order to retain the contract.

Introduction of a capacity market (CM), allowing for capacity auctions, at the minister's discretion. The capacity market involves retainer payments for dispatchable capacity to be built and maintained to ensure that demand can be met regardless of short-term conditions affecting other generators. It is to provide an insurance policy against future supply shortages, helping to ensure reliable electricity supplies at affordable cost. See subsection below.

(CM), allowing for capacity auctions, at the minister's discretion. The capacity market involves retainer payments for dispatchable capacity to be built and maintained to ensure that demand can be met regardless of short-term conditions affecting other generators. It is to provide an insurance policy against future supply shortages, helping to ensure reliable electricity supplies at affordable cost. See subsection below. A final investment decision (FID) process will enable investment in low-carbon projects to come forward for early projects, guarding against delays to investment in energy infrastructure.

Transitional measures will allow renewables investors to choose between the new system and the renewables obligation, which was closed to new capacity in March 2017.

The government had legislated to establish a carbon price floor (CPF) from April 2013, to underpin the move to a low-carbon energy future. The carbon price support (CPS) tax is the difference between the UK floor price and the ETS traded price. Per tonne of CO 2 , the CPS cap was set at £18 to 2021. (It was planned to rise to £21.20 for 2016-17 and £24.62 for 2017-18, but these rates were abandoned due to public pressure).

(CPF) from April 2013, to underpin the move to a low-carbon energy future. The carbon price support (CPS) tax is the difference between the UK floor price and the ETS traded price. Per tonne of CO , the CPS cap was set at £18 to 2021. (It was planned to rise to £21.20 for 2016-17 and £24.62 for 2017-18, but these rates were abandoned due to public pressure). The supplier obligation is a compulsory levy enforceable by the government-owned CfD counterparty company as if it were a licence condition. It is collected on a unit cost fixed rate (£/MWh). Each supplier collects it in line with its market share and pays it to the counterparty for passing onto the generators. The supplier obligation needs to be funded by the suppliers so that payments under CfDs can be made regardless of collections from customers, which started in December 2014.

As well as price per MWh, the question of guaranteed load factor arises so that output is sufficient to amortise the investment, in the face of renewables’ preferential grid access. For Hinkley Point C, the agreement provides protection from being curtailed without appropriate compensation.

The UK Guarantees scheme was established in October 2012 to support infrastructure projects seeking finance and investment, and this is being applied to the initial nuclear power projects. The offer of a £2 billion loan guarantee for Hinkley Point C was announced in September 2015, and a Treasury statement then said that the government guarantee "is also expected to open the door to unprecedented collaboration in the UK and China on the construction of new nuclear power stations." It added: "The agreement also boosts work being carried out under a memorandum of understanding on fuel cycle collaboration signed with China in 2014, which has the potential to leverage UK expertise in waste management and decommissioning as well as support UK growth."

In June 2017 a report from the government’s National Audit Office (NAO) said that other funding options for Hinkley Point C should be considered besides the CfD model. It also called for the government to look in more detail at alternative funding methods to the CfD, such as direct state funding or loans, for future new nuclear construction in the UK.

In 2018 the UK government announced that it was considering a regulated asset base (RAB) model for future nuclear power plant projects as an alternative to CfDs. Under a RAB model, the UK government would provide a plant owner with regulated rates that can be adjusted to guarantee its costs are covered. The RAB model allows the owner of a regulated operation to collect an authorised return on the asset's value that includes operating costs and profit. It protects the operator of a facility by ensuring that the operator has sufficient revenue to maintain its financial capability over a period. It is similar to the US rate base model but with greater flexibility on the part of the UK market regulator to determine what is 'reasonable'.

In July 2019 the UK government published its assessment of the RAB model, which concluded that it has the potential to reduce the cost of raising finance for new nuclear projects, thereby maximising value for money for consumers.

For more information, see information page on Financing Nuclear Energy.

Capacity market

In March 2014 the government announced the design of the capacity market to provide security of supply from 2018 by encouraging investment in reliable generating capacity.* The UK is the first country in Europe to establish a reserve capacity market to ensure supplies when intermittent renewables sources fail to produce. This is a pioneering concept and likely of great interest internationally. Agreements for new dispatchable capacity are for 15 years, and agreements for existing capacity are for one or three years. A provider of reserve capacity will receive a warning of at least four hours from the National Grid that the electricity system is under stress. Penalties for unreliable capacity will be capped at 200% of a provider’s monthly income and 100% of their annual income. The capacity market does not affect dispatch rules when the power is needed.

* A capacity market normally works by producers bidding in their capacity at cost of production, and the grid operator accepts the lowest bids up to the capacity it thinks will be required to meet demand, with a little reserve. The highest bids accepted represent the clearing price, set by the most expensive plant needed to meet demand, and this is what all accepted bidders are paid. The UK system is a variant of this, and with the uncertainties of forecasting demand and the four years lead time between auction and delivery, supplementary auctions are held one year ahead (especially for demand-side response) or private trading can adjust for contingencies. Successful bidders for new capacity are able to write up to 15-year contracts at the auction clearing price, those with existing capacity, rolling one-year contracts.

An auction for pre-qualified capacity is held every year, for delivery four years ahead. A demand curve for the year is published before the auctions and is based around a target capacity level together with an estimate of the reasonable cost of new capacity (referred to as the net cost of new entry, or ‘net-CONE’). The auction can include demand-side response, but excludes capacity receiving support under the renewables obligation (RO), feed-in tariff (FIT) or contract for difference (CfD).

The capacity auction is capped at £75/kW, which relates to the cost of building a new combined cycle gas turbine. Following EC state aid clearance in July, the first auction in December 2014 for 2018-19 delivery was for a total of 49.26 GWe. Almost 65 GWe was bid, and it cleared at £19.40/kW/yr, well below expectations. Most of the capacity already exists and was signed up under one-year contracts. A further 3 GWe of existing capacity was signed for three-year contracts, 2.4 GWe was for new capacity under 15-year contracts. Regarding technology, 45% was CCGT, 19% coal/biomass, and 16% nuclear.

The net cost of new entry (net-CONE) was put at £49/kW. Capacity providers successful in the auction are paid by retail suppliers in the year of delivery. Payments are administered by Elexon, as settlement agent. They are included in the levy control framework (LCF) with renewables obligation, CfDs, and small-scale FITs paid for in energy bills. The LCF budget cap is expected to increase from £3.184 billion in 2013-14 to £7.6 billion in 2020-21.

In December 2019 the capacity auction secured 43.75 GWe at £15.97 for 2023-24. Included in the total were 27.3 GWe of gas-fired plant, 4.0 GWe of nuclear and 2.6 GWe of battery and pumped hydro storage.

The Department of Energy & Climate Change (DECC) estimated that the operation of the capacity market would add about £15 per year to the average domestic bill to 2030.

Nuclear power industry

Reactors operating in the United Kingdom

The history and development of the UK nuclear industry is covered in Appendix 1 to this paper, Nuclear Development in the United Kingdom.

The last operating Magnox reactor – Wylfa 1 – shut down in December 2015. This left seven twin-unit AGR stations and one PWR, all owned and operated by a subsidiary of France's EDF called EDF Energy.

Most AGR units are running at significantly less than original or design capacity.

Reactor life extensions

In the UK reactor life extensions are decided on commercial grounds by the owners in the context of 10-year safety reviews of all reactors undertaken by the Office for Nuclear Regulation (ONR).

EDF Energy announced a seven-year life extension for Hinkley Point and Hunterston in November 2012 and a five-year extension for Hartlepool in November 2013. It spent £150 million to prepare Dungeness for a 10-year licence extension, to 2028, and this was agreed by the ONR in mid-2014. In February 2016 it announced five-year life extensions for Heysham I and Hartlepool, to 2024, and seven-year life extensions for Heysham II and Torness, to 2030.

At Hunterston, Dungeness and Hinkley Point, age cracking of graphite bricks comprising the moderator is being carefully monitored. Other reactors are checked less frequently.

EDF Energy spends about £600 million per year on upgrades to eight plants (15 reactors) to enable ongoing operation, this investment being supported by the new capacity market operating from 2014.

The company expects a 20-year life extension for Sizewell B, taking it to 60 years as for similar US PWR plants. In January 2015 the ONR approved a ten-year extension to 2025.

Nuclear policy and procedure from 2006

It was originally intended that the Sizewell B reactor would be the first of a fleet of PWRs but these plans were abandoned in the 1990s. The question of new nuclear build was then effectively ruled out until 2006, when a review of energy policy reversed the government's opposition to building new nuclear capacitya. Government policy in England and Walesb has since been supportive of new nuclear plants, which should be financed and built by the private sector – with internalised waste and decommissioning costs as per the industry norm internationally. To facilitate new nuclear build, from 2006 the Labour government implemented several measures, in particular:

Streamlining the planning process.

Carrying out strategic siting assessment and strategic environmental assessment processes to identify and assess suitable sites for new nuclear plants.

Ensuring that the regulators are equipped to pre-license designs for new build proposals (the Generic Design Assessment process).

Electricity market reform to provide long-term sales contracts for power, and a capacity market.

Legislating to ensure decommissioning and waste management liabilities will be met from operational revenue.

Strengthening or supplementing the EU Emissions Trading Scheme to build investor confidence in long-term carbon pricing.

The Conservative and Liberal Democrat coalition government elected in May 2010, followed by the Conservative government elected in May 2015, continued to support nuclear power as a high priority and followed through with these initiatives, with minor exceptions noted below.

Following the referendum vote in mid-2016 to leave the EU, the Department of Energy and Climate Change (DECC) was abolished and UK energy policy was transferred to the new Department for Business, Energy, & Industrial Strategy (BEIS), with the priority of building new nuclear capacity affirmed.

Soon after this and in connection with final government approval for the Hinkley Point C project, the government introduced a legal requirement that it holds a controlling ‘special share’ in all major infrastructure projects, including nuclear power, “in line with other major economies”. This was welcomed by proponents of other new nuclear projects.

Planning

A new planning regime was introduced to aid the installation of nuclear reactors as well as other significant new infrastructure projects such as railways, large wind farms, reservoirs, harbours, airports and sewage treatment works. Under the Planning Act 2008, the need for new infrastructure would be addressed through a National Policy Statement (NPS, see next section on Nuclear site licensing and authorisation). Then, it was intended that the local impacts of a particular development would be handled by an independent Infrastructure Planning Commission (IPC) rather than by Ministers or local planning authorities. The IPC was formed in October 2009, but the new coalition government that took office following the 2010 general election replaced the IPC with an advisory body and returned decision-making power to the responsible Ministerc. Under the Localism Act 2011, the IPC was abolished and in April 2012 its staff and functions were transferred to a new national infrastructure directorate created within the Planning Inspectorate (PINS).

A development consent order issued by the UK Planning Inspectorate is required for nationally significant infrastructure projects, and represents permission granted by the UK government for such developments, including nuclear power plants.

Nuclear sites: selection, licensing and authorisation

Between July and November 2008, a consultation was carried out on a proposed strategic siting assessment (SSA) process for identifying sites which are suitable for new nuclear power stations to be built by the end of 2025.11 Sites found to be strategically suitable for new nuclear plants through the SSA would be listed in the Nuclear National Policy Statement (Nuclear NPS).

In its January 2009 response to the consultation12, the government invited nominations for sites to be assessed for their suitability for the deployment of new nuclear power stations by 2025. Eleven sites were nominated and, following assessment of these sites, the government formed the "preliminary conclusion" that all of the nominated sites, with the exception of Dungeness, were potentially suitabled. Three alternative sites – Druridge Bay in Northumberland, Kingsnorth in Kent and Owston Ferry in South Yorkshire – were not considered to be suitable for nuclear development before the end of 2025, although they were said to be worthy of further investigation. The ten sites included in the draft Nuclear National Policy Statement are: Hinkley Point, Oldbury, Sellafield, Sizewell and Wylfa, all of which were the subject of existing proposals (see below); as well as Bradwell, Braystones, Hartlepool, Heysham, and Kirksanton. In October 2010, the two greenfield sites near Sellafield – Braystones and Kirksanton – were removed from the list, and the other eight confirmed.

A consultation on six draft National Policy Statements for energy infrastructure, including the draft Nuclear NPS, ran from November 2009 to February 2010. Following the May 2010 general election, the new coalition government required all National Policy Statements to be ratified by parliament, confirming selection of the above eight sites in July 2011 and introducing planning reforms to allow plant construction to be expedited.

The minister also announced regulatory justification of the AP1000 and EPR reactor designs according to EU law, due to their potential for increasing energy security and decreasing CO 2 emissions outweighing any detrimente. Hitachi-GE’s ABWR reactor design for Wylfa Newydd was justified in December 2014 and confirmed by Parliament in January 2015.

The ONR grants a nuclear site licence under the Nuclear Installations Act 1965 for the installation and operation of a nuclear reactor. This covers the full lifecycle from construction to operation and through to decommissioning. A standard set of 36 licence conditions is attached to each licence that requires site licence companies to implement adequate arrangements to ensure compliance. Prior to a nuclear site licence being granted, a site licence company has to demonstrate it is a suitable legal entity that is able to discharge its regulatory obligations.

A nuclear site licence was issued for Hinkley Point C in November 2012 after 16 months of consideration by the ONR. An application was made for Wylfa Newydd in April 2017, but in January 2019 Hitachi announced it was suspending work on the project. In September 2020 Hitachi announced its decision to withdraw from the UK nuclear business.

Generic design assessment

In June 2006, the UK's Health & Safety Executive (HSE), which licenses nuclear reactors through its Office for Nuclear Regulation (ONR), suggested a two-phase licensing process similar to that in the USAf. The first phase, developed in conjunction with the Environment Agency (EA), is the generic design assessment (GDA) processg. Considering third-generation reactors, a generic design authorisation for each type would be followed by site- and operator-specific licences. Phase 1 would focus on design safety and take around three years to complete; phase 2 is site- and operator-specific and would take around 6-12 months.

Initial guidance on the GDA process was issued by the HSE and EA in January 2007, and in July of that year, applications for four reactor designs were made: UK EPR, submitted by Areva and EDF; Westinghouse's AP1000; GE Hitachi Nuclear Energy's ESBWR; and AECL's ACR-1000. Although the initial assessments of the four designs found no shortfalls, AECL withdrew its design from the GDA process in April 2008. Later, in September 2008, assessment of the ESBWR was halted after GE Hitachi requested a temporary suspension.

The HSE, through ONR, was on course to complete the initial GDA assessment for the two remaining designs by July 2011, although further processing was delayed pending an HSE evaluation of lessons from the March 2011 Fukushima accident and approval of the reactor vendors' responses to those. The ONR and EA jointly issued interim design acceptance confirmations (iDAC), and interim statements of design acceptability (iSODA) for the two designs in mid-December 2011.

Westinghouse AP1000

The process of obtaining a full DAC and SODA for the AP1000 resumed in January 2015 when Westinghouse became part of NuGen due to the Toshiba 60% stake in that project. It was completed in March 2017. Westinghouse said the milestone "expands the global regulatory pedigree of the AP1000 plant design and further confirms Westinghouse's innovative safety technology.” As the GDA proceeded, issues arose which were in common with new capacity being built elsewhere, particularly the EPR units in Finland and France. This led to international collaboration and a joint regulatory statement on the EPR instrumentation and control among the ONR, US NRC, France's ASN and Finland's STUK. For the AP1000, the ONR drew upon experience with the eight AP1000 units under construction in China and the USA. More broadly it relates to the Multinational Design Evaluation Programme and will help improve the harmonization of regulatory requirements internationally.

Hitachi-GE ABWR

Early in 2013 Hitachi-GE applied for GDA for its Advanced Boiling Water Reactor (ABWR), and in October 2014 the ONR and EA completed the third stage of this, and cleared it to proceed to the final stage. In 2015 the ONR and EA had raised an issue regarding reactor chemistry, and then another regarding safety analysis. The company completed the GDA process on schedule in December 2017. There are four operable ABWR units in Japan, while two more are under construction.

Rosatom VVER-TOI

In 2012 Rosatom announced that it intended to apply for design certification for its VVER-TOI reactor design of 1200 MWe, with a view to Rusatom Overseas building them in the UK. In June 2013 an intergovernmental agreement set up a working group to explore possible Rosatom involvement in UK nuclear power projects. This led to a nuclear cooperation agreement in September 2013, immediately following which Rosatom, Rolls-Royce and Fortum agreed to prepare for submitting an application for GDA for the VVER-TOI reactor, possibly in 2015, though this did not proceed. There have been no further developments regarding VVER reactors.

CGN Hualong One

In 2015, China General Nuclear Power Group (CGN) said it intended to apply for GDA for its version of the 1150 MWe Hualong One (HPR1000) reactor design, with a view to building it at Bradwell. Fangchenggang 3 is the reference plant. General Nuclear Systems (GNS), the joint venture of EDF Energy and CGN formed to progress the GDA, wrote to the government in October 2016 saying it was ready to start the GDA process, and in January 2017 the Department for Business, Enterprise and Industrial Strategy (BEIS) requested the ONR to commence it. The ONR had been advising EDF and CGN meanwhile. This GDA commenced in January 2017, moved to stage 4 in January 2020, and is expected to be completed in 2022.

GDAs completed: Areva UK EPR (December 2012); Westinghouse AP1000 (March 2017); Hitachi-GE ABWR (December 2017).

GDAs under way: CGN HPR1000 (due late 2021).

Small modular reactors (SMRs) are a further GDA task for the ONR. The National Nuclear Laboratory in 2014 undertook a feasibility study on SMR concepts, with its report published by the government in July 2015. Following this, a second phase of work is intended to provide the technical, financial and economic evidence base required to support a policy decision on SMRs. If a future decision is to proceed with UK development and deployment of SMRs, then further work on the policy and commercial approach to delivering them would need to be undertaken. NuScale expected to apply for GDA in the UK in 2016, but this has not yet proceeded.

In March 2016 the Department of Energy & Climate Change (DECC) called for expressions of interest in a competition to identify the best value SMR for the UK. All proposals will require proceeding through the GDA process in the UK – see later section.

Funded decommissioning programme

The Energy Act 2008 stipulates that plant operators are required to submit a Funded Decommissioning Programme (FDP) before construction on a new nuclear power station is allowed to commenceh. The Funded Decommissioning Programme must contain detailed and costed plans for decommissioning, waste management and disposal. The government will set a fixed unit price for disposal of intermediate-level wastes and used fuel, which will include a significant risk premium and escalate with inflation. During plant operation, operators will need to set aside funds progressively into a secure and independent fund. Ownership of wastes will transfer to the government according to a schedule to be agreed as part of the FDPi.

Relationship with the European Union and Euratom

Following a referendum and parliamentary vote, the UK left the European Union on 31 January 2020. As part of the Withdrawal Bill, the UK left the European Atomic Energy Community (Euratom) on 31 January 2020. However, for the agreed transition period to the end of 2020, Euratom rules and arrangements continue to apply.

Euratom is a separate legal entity from the EU and governed by the 1957 Euratom Treaty, preceding the EU, but it is closely linked to its institutions. Nuclear power generates almost 30% of the EU’s electricity, and Euratom establishes a common market in nuclear goods, services, capital and people within Europe as well as arrangements for safeguards related to the Nuclear Non-Proliferation Treaty.

The UK government passed the Nuclear Safeguards Act 2018, which makes provisions for the goverment to pass regulations on and implement safeguards agreements, covering some of the 'gaps' created by leaving Euratom. The government has also rolled over agreements with Australia, the USA, Canada, as well as the International Atomic Energy Agency (IAEA) to ensure supply of nuclear material for electricity generation and medical use.

Earlier in May 2017 the NIA published a paper setting out priority areas for negotiations with the European Commission. It listed six key steps for the government to take, and suggested how it might address them:

Agreeing a replacement voluntary offer agreement with the IAEA for a new UK safeguards regime.

Replacing the nuclear cooperation agreements (NCAs) with key nuclear markets – Australia, Canada, Kazakhstan, South Korea and the USA – as well as establishing one with Euratom.

Clarifying the validation of the UK's current bilateral NCAs with Japan and other nuclear states.

Setting out the process for the movement of nuclear material, goods, people and services.

Agreeing a new funding arrangement for the UK's involvement in Fusion for Energy and wider EU nuclear R&D programs.

Maintaining confidence in the industry and securing crucial investment.

Building new nuclear capacity: Hinkley Point C

EDF Energy is constructing two EPR nuclear reactors at Hinkley Point in Somerset.

The company applied for consent to construct and operate the two reactors (3260 MWe) at Hinkley Point in October 2011, though the generic design assessment (GDA) process on reactor design was not concluded (see section above on generic design assessment). At that time, EDF envisaged having the first new reactor online by 2018. By mid-September 2010 EDF Energy had let £50 million in contracts for site works at Hinkley Point, and by February 2013 pre-development costs there had reached almost £1 billion. In March 2013 environmental permits were granted for plant operation, and planning permission was received.

Late in July 2011 NNB Generation (then EDF Energy 80%, Centrica 20%) submitted an application to the UK Health and Safety Executive's Office for Nuclear Regulation (ONR) for a nuclear site licence for two Areva EPRs at Hinkley Point C. The ONR assessed the company's "suitability, capability and competence to install, operate and decommission a nuclear facility," and issued a site licence in November 2012. The local government had given permission to prepare the site.

EDF announced in October 2013 that while it would retain 45-50% of the Hinkley Point C project, two Chinese companies, CGN and CNNC, would take 30-40% of it between them, Areva would take 10%, and other interested parties might take up to 15%.* The French government held 85% of EDF and 80% of Areva, the Chinese companies are wholly government-owned. In September 2015, following Areva’s financial losses, EDF confirmed that Areva’s 10% share was “no longer on the agenda.”

* By the end of 2012 Centrica had expressed reservations about its investment in the new plant and EDF was discussing with China General Nuclear Power Holdings (CGNPC, now CGN) about buying out Centrica or in some other way taking equity in Hinkley Point. The two companies are partners in the Taishan nuclear plant being built in China, using EPR technology. Then in February 2013 Centrica said it would not proceed to invest in the new units, citing uncertainty re project costs and schedule. (It remains a 20% shareholder in EDF Energy's current nuclear generation capacity at eight plants.) In August 2013 CGN confirmed that talks with EDF continued regarding equity in Hinkley Point C.

Through 2012 and most of 2013 EDF, parent company of EDF Energy, was locked into negotiations with the UK government to obtain "the correct market framework [to] allow an appropriate return on the massive investment required." A £1.2 billion civil engineering contract was deferred. In June 2013 the government announced that it would guarantee up to £10 billion in loans for the plant under the 2012 UK Guarantees scheme for infrastructure (and that CfD rates for wind power would be at least £100 per MWh, and £155/MWh for offshore wind). In September 2015 the government announced a £2 billion loan guarantee offer for the project, and said more would be available if EDF met certain conditions. EDF said that this would “pave the way for a final investment decision by energy company EDF, supported by China General Nuclear (CGN) and China National Nuclear Corporation (CNNC), later this year."

In October 2013 the government announced that initial agreement had been reached with EDF Group on the key terms of a proposed £16 billion* investment contract for the Hinkley Point C nuclear power station. These include a 35-year contract for difference (CfD)**, the 'strike price' of £89.50/MWh being fully indexed to the Consumer Price Index and conditional upon the Sizewell C project proceeding. If it does not for any reason, and the developer cannot share first-of-a-kind costs across both, the strike price is to be £92.50/MWh. The terms include compensation if output is curtailed by the National Grid. EDF said that the agreement in principle was not legally binding, and depended on a positive decision from the European Commission in relation to state aid, following which it would make a final investment decision on the project. It said that following EC approval, first concrete would be 30 months on, with construction time 75+ months.

* This is the overnight capital cost in 2012 £, including some owner’s costs. A £24.5 billion figure has been mentioned on the basis of including financing (interest charges during construction) and inflation.

** The 35 years run from start-up during 2025-2029. After 2029 the CfD is shortened by one year of delay up to 2033, after which it would be cancelled. EdF Energy would be able to get revenues from the market, but not top-up revenues from the CfD. In much of November 2016 the UK base-load price was over £75/MWh.

In October 2014 the EC decided that revised UK plans to support the construction and operation of the project were in line with EU state aid rules. The price support for electricity from the plant over 35 years was found to address a genuine market failure. In the process of the investigation the UK agreed to modify significantly the terms of the project financing, by raising the guarantee fee paid by the developer to the UK Treasury. Also as soon as the operator's overall return on equity exceeds the rate estimated at the time of the decision, any gain will be shared with the public entity supporting the long-term wholesale electricity price through the CfD. This gain-share mechanism will be in place not only for the 35-year support duration as initially envisaged, but for the entire 60-year lifetime of the project. Moreover, if the construction costs turn out to be lower than expected, the gains will also be shared.

In October 2015 a strategic investment agreement was signed committing China General Nuclear Corporation (CGN) to take 33.5% of the project, and EDF initially being responsible for 66.5%, with a view to selling this down to near 50%. CGN’s holding would be through its new company, General Nuclear International. In December 2016 the Chinese coal mining company Wintime Energy agreed to take about 2% of the project, through CGN. The EDF-CGN joint venture is NNB Generation Company Limited, which holds the site licence issued in 2012.

After prolonged consultation with French unions, in July 2016 EDF made its decision to proceed with the project, with full construction then expected to begin in mid-2019. UK trade unions expressed “100% support”. However, the UK government unexpectedly said that it would take until September for the new leadership to make a final decision on the project. The Chinese ambassador then urged the government to decide as soon as possible, pointing out that the project "is the considered outcome of a mutually beneficial tripartite partnership between Britain, France and China," and that the UK "could not have a better partner" than CGN. After seven weeks of uncertainty the government gave approval, after reaching a new agreement in principle with EDF, which means that the government will be able to prevent the sale of EDF’s controlling stake prior to completion of construction. The agreement was signed at the end of September, as was a €5 billion contract between NNB and Areva for two EPR nuclear steam supply systems, from design and supply to commissioning, and two I&C systems. A long-term fuel supply agreement with Areva was also signed.

EDF expected the first reactor to be operational 115 months after the investment decision and government approval, hence early 2026. In May 2016 it put the cost at £18 billion including normal contingencies, of which £2.4 billion had already been spent. In July 2017 the cost estimate was raised to £19.6 billion. By November 2017 about £9 billion of supply chain contracts had been awarded. In September 2019 EDF again raised the estimated cost of construction by £1.9-2.9 billion, taking the cost estimate to £21.5-22.5 billion.

EDF is acting as architect-engineer. Contractors include Areva (now Framatome) for the reactor system, its fuel, and instrumentation and control, worth £1.7 billion; Bouyges and Laing O'Rourke for civil engineering, worth over £2 billion; GE and Alstom for the conventional islands with two 1770 MWe Arabelle turbines, worth $1.9 billion; and Costain for cooling water intake tunnels (seven metres in diameter with a total length of 11 km). Rolls-Royce will provide some manufacturing of nuclear components. The government and EDF said UK companies could take up to 57% of the construction work. The total number of workers on the project could reach as high as 25,000, with a peak of 5600 onsite at one time, and EDF estimating 900 permanent jobs when the units are operational. In September 2016 EDF said that the project would not use the offered government loan guarantee.

In March 2017 the ONR issued a licence for placement of the first structural concrete for the 'technical galleries' of the plant. These are a series of underground reinforced concrete structures located beneath the site, and some above-ground structures. In November the ONR approved construction of the 'common raft' reactor foundation, which was poured in four stages from December 2018 to mid-2019. First concrete for the nuclear island was poured on 11 December 2018, and construction of the basemat for the first unit was completed by June 2019. First concrete for unit 2 was poured in December 2019.

In February 2017 the House of Lords Economic Affairs committee said in a report on the UK electricity market that a backup plan for the project should be provided "in the light of the significant and ongoing concerns about the deal" and possible delays, since the plant would provide 7% of the UK's electricity once it is fully operational.

National Grid will build 56 km of new 400 kV connections (8 km of which will be underground) and upgrade an existing 132 kV network. About 67 km of overhead lines will be replaced, with 10 km underground.

In China, EDF in joint venture has built two EPR units at Taishan, the components are from Japan and China, and the project is close to schedule and budget. For Hinkley Point C, all construction risks will remain with EDF and its partners. As noted above, the Chinese investment is seen as a foothold in the UK, with a view to Chinese reactors being built in future. In connection with the Hinkley Point agreement, EDF and CGN have also signed heads of agreement for a wider partnership in developing new power plants at Sizewell and Bradwell.

See also EDF Energy webpage on Hinkley Point C.

Power reactors under construction

Reactor Type MWe gross Construction start Grid connection Hinkley Point C1 EPR 1720 December 2018 2025 Hinkley Point C2 EPR 1720 December 2019 2026

Building new nuclear capacity: other proposals

The government assumed there would be a requirement of 60 GWe of net new generating capacity by 2025, of which 35 GWe is to come from renewables, which have priority access to the electricity grid as part of the EU’s 2009 renewable energy directive. The Draft National Policy Statement for Nuclear Power Generation stated that the expectation is for "a significant proportion" of the remaining 25 GWe to come from nuclear, although the government has not set a fixed target for nuclear capacityk. Government ministers have consistently said that 16 GWe of new nuclear capacity should be built at five sites by 2025, though this target date has slipped.

Since the government reversed its unfavourable policy towards nuclear in 2006, several utilities have begun planning to build new nuclear plants. The initial concern was that the most promising sites were owned by only two organizations: British Energy – which had recently completed restructuring following its financial collapse in 2002 (see section on British Energy in Appendix 1, Nuclear Development in the United Kingdom); and the government-owned Nuclear Decommissioning Authority (NDA) – which had recently taken ownership of BNFL's and the UKAEA's nuclear sites in order to decommission theml. Utilities wishing to build new nuclear plants in the UK therefore had to either acquire British Energy, or its sites; or acquire land from the NDA.

There has been substantial international interest in the UK’s 21st century nuclear program. France’s EDF, 85% owned by the French government, successfully bid for British Energy, completing the £12.5 billion acquisition in January 2009. Later in 2009, Centrica bought a 20% stake in British Energy for £2.3 billion. Conditions attached to the acquisition of British Energy included the sale of land at Wylfa, Bradwell and either Dungeness or Heysham, as well as to relinquish one of the three grid connection agreements it held for Hinkley Point. British Energy became part of EDF Energy.

Major European utilities have shown considerable interest in nuclear prospects, as described below. Also Rosatom, owned by the Russian government, had proposed taking equity in Horizon before it was bought by Hitachi.

Several Chinese government-owned companies, principally China General Nuclear Group (CGN) have discussed taking equity in each of the proposed nuclear developments. It was reported that CGN would only proceed with taking a share of Hinkley Point it had significant operational control of any further nuclear plants, notably Sizewell C. Government concern was reported about Chinese government control through CGN, compared with French government control through EDF.

When CGN showed interest in buying Horizon, the government said it could only have a minority interest. China’s State Nuclear Power Technology Corporation (SNPTC) with Toshiba expressed interest in buying Horizon (SNPTC brokered the acceptance of the Westinghouse AP1000 reactor in China) and this became a Westinghouse - SNPTC bid with Exelon. An Areva-CGN bid followed but was withdrawn.

In October 2013, following the signing of a memorandum of understanding on nuclear power cooperation by the two countries, the Chancellor announced that the government approved Chinese companies taking equity – including potential future majority stakes – in the development of UK’s nuclear power projects. UK companies would have access to business opportunities in China’s nuclear program. Immediately after this, EDF Group announced that it had agreement in principle with both CGN and China National Nuclear Corporation (CNNC) to take substantial equity in the Hinkley Point C project.

In January 2014 CGN said that would be a minority shareholder in Hinkley Point C “to lay the foundation for further development in CGN-led projects in the UK.” It then planned to acquire a site, and along with local and Chinese partners, to build and operate nuclear power plants in the UK. No particular reactor technology was mentioned, but the UK government confirmed that Chinese companies could own and operate Chinese-designed nuclear plants subject to normal approvals. See section on Bradwell B, below.

EDF Energy – Sizewell C

EDF Energy plans to build two further EPR units at Sizewell, in Suffolk. EDF and CGN agreed in October 2015 to develop the Sizewell C project to the point where a final investment decision can be made, with a view to building and operating two EPR reactors there. During this development phase, EDF will take an 80% share while CGN will take a 20% share.

The RAB funding model (see Electricity Market Reform section above, and information page on Financing Nuclear Energy) may be used for Sizewell C. In June 2019, EDF indicated that its own provisional forecasts suggest that the associated upfront cost would be about £6 annually per household. EDF submitted a development consent order (a planning application) for the plant in May 2020.

NuGeneration – Moorside

NuGeneration* was set up early in 2009, and then comprised a 50:50 joint venture of Iberdrola (which owns Scottish Power) with GDF Suez (now Engie). NuGeneration in October 2009 bought the 190 ha Moorside site on the north side of Sellafield from the NDA for £70 million. In December 2013 Iberdrola agreed to sell its 50% share to Toshiba for £85 million, after having been in discussion since early in the year regarding building its Westinghouse AP1000 reactors and taking equity in the project. Toshiba then bought one-fifth of GDF Suez’s stake at the same price, to give it majority (60%) ownership for about £102 million, from June 2014. Following Westinghouse’s Chapter 11 bankruptcy petition, in April 2017 Engie announced that it required Toshiba to buy its 40% share in NuGen, and this transaction was completed in July 2017 for £109 million. Engie said it "remains willing to put its know-how and expertise at the service of NuGen and help any restructuring with new potential partners for the development, construction and operation of the project."

* Originally this was owned 37.5% each by Iberdrola and GDF Suez, and 25% by Scottish & Southern Energy, though SSE decided to sell out of it in 2011, giving the other partners 50% each. Before the Toshiba acquisition, China’s State Nuclear Power Technology Corporation (SNPTC) was reported to be interested in a share in NuGen.

In December 2017, it was announced that Korea Electric Power Corporation (Kepco) had been named as the preferred bidder to acquire 100% of the shares in NuGen. Subject to completion of the acquisition and UK government approval, two of Kepco's APR1400 reactors would be used at the site, replacing earlier plans for three AP1000 units. However in July 2018, it was announced that Kepco had lost its status as preferred bidder. In September 2018, NuGen announced it was reducing its staff by 60% due to the "prolonged time" it had taken to agree a sale. In November 2018, Toshiba announced that it had decided that NuGen would be wound up from January 2019 after failing to find a buyer.

Earlier, in November 2016 and prior to Westinghouse's filing for bankruptcy, NuGen announced that it expected the cost of the project to be £13-15 billion. The UK government said that it expected the CfD strike price would be significantly lower than that for Hinkley Point.

National Grid would need to build 400 kV lines both north and south, and there are grid connection agreements for 1600 MWe by October 2023 and another 1600 MWe by October 2025. In October 2016 it announced plans to invest £2.8 billion in these new transmission links over 164 km and upgrading old ones. More than a quarter of the new links could be underground, including 23.4 km through the Lake District National Park, which also involves placing existing transmission lines underground and removing obtrusive pylons. Putting cables through a 22 km tunnel under Morecambe Bay to avoid the south part of the national park would cost £1.2 billion, the major part of £1.9 billion to put transmission lines out of sight. The timing of work on the transmission links would be aligned with that for the plant itself.

In July 2020, Moorside Clean Energy Hub – a consortium of 15 companies, unions and individuals, including EDF – called for a “package of nuclear projects at Moorside, including a 3.2 GW UK EPR power station, small modular reactors and advanced modular reactors.”

Horizon – Wylfa Newydd and Oldbury

Early in 2009, a 50:50 new-build joint venture of RWE npower with E.ON UK was established: Horizon Nuclear Power. Horizon bid for NDA land alongside old Magnox plants at Oldbury, Wylfa and Bradwell. Other bidders included EDF Energy and Vattenfall. The winning bids for Oldbury and Wylfa were from Horizon. Including bids from EDF and NuGeneration, the auction raised £387 million for the NDA28.

By 2025, Horizon planned to have around 6000 MWe of new nuclear capacity in operationm. For its site at Wylfa in Wales, Horizon was proposing constructing up to four AP1000 reactors or three EPR units. For its Oldbury site, it was considering either three AP1000 reactors or two EPRs. The planning application for Wylfa was envisaged in 2012, that for Oldbury in 2014. But early in 2012 German-based RWE and E.ON announced that they wanted to withdraw from Horizon.

Following this there were several expressions of interest in buying Horizon: first was Rosatom directly with a view to using VVER-1200 reactors, then China's State Nuclear Power Technology Corporation (SNPTC) with Toshiba, which became a Westinghouse-SNPTC bid with Exelon. An Areva-CGNPC bid was announced, using the EPR, but then withdrawn, and finally Hitachi Ltd bid with a view to building the GE-Hitachi Advanced Boiling Water Reactor (ABWR). Rosatom subsequently said that it was prepared to build western-design reactors in UK initially, pending design certification of VVER types. Meanwhile some work continued on the two sites.

In October 2012 the £696 million Hitachi bid was accepted, making Horizon a 100% subsidiary of Hitachi. It planned to build two or three of the 1380 MWe (gross) ABWR units at each site, and in April 2013 applied to the ONR for generic design assessment (GDA). In December 2017 the regulator cleared the design for use in the UK. As with the EPR design, the ONR worked with overseas regulators on the assessment of the UK ABWR. (Several ABWR units have been operating in Japan.)

In May 2013 Horizon signed an engineering and design contract with Hitachi-GE Nuclear Energy Ltd (HGNE, 80% owned by Hitachi), which was progressing the GDA for Wylfa Newydd with the ONR. In 2015 Hitachi incorporated in UK a new company Hitachi Nuclear Energy Europe Ltd (HNEE) which will represent the parent company in the Menter Newydd joint venture with Bechtel Management Co and JGC Corporation (based in Japan) which is set up for the engineering, procurement and construction (EPC) of the project. HGNE will operate under contract to the Menter Newydd JV.

In July 2016 Horizon and Hitachi signed a technical services contract with Japan Atomic Power Co (JAPC) to support Horizon in construction, costing, licensing and commissioning the ABWR units. In February 2017 Horizon announced an operating partnership with the major US utility Exelon, which has 19,460 MWe of nuclear capacity from 21 units, including 14 BWRs. In April 2017 Exelon and JAPC formed a 50:50 joint venture, JExel Nuclear, "to leverage Exelon's expertise in operational excellence and safety among international operators using Japanese reactor technologies."

In April 2017 Horizon Nuclear Power Wylfa Ltd applied to the ONR for a site licence for Wylfa Newydd. This was expected to take 19 months to process and establish “the applicant's organisation capability, governance arrangements and competence to be a nuclear site-licence holder." It must “demonstrate it is capable and competent to install, operate and decommission a nuclear facility. If licensed, Horizon will then be regulated by the ONR for the full lifecycle of the site from construction to decommissioning." The site licence had not been granted by the time work was suspended in January 2019. Horizon has submitted an application for a development consent order to the Planning Inspectorate. A decision was initally expected in October 2019, but this was delayed until September 2020.

Earlier in December 2013 the government signed a cooperation agreement with Hitachi and Horizon “to promote external financing” for the Wylfa Newydd project under the 2012 UK Guarantees scheme for infrastructure, with a view to a guarantee by the end of 2016 similar to that for Hinkley Point. Horizon said in November 2016 that Hitachi had spent £1.5 billion already on “on engineering and preliminary site work to date at Wylfa Newydd” and expected a final investment decision in 2019. In March 2017 Hitachi said that it would focus on controlling construction costs and accordingly planned to involve Bechtel, to help attract investors.

In June 2017 Hitachi said that a decision to proceed with the project was contingent on finding an investment partner, without which it would suspend the project. Both the government and the company had said that they expect the CfD strike price to be significantly lower than that for Hinkley Point.

In June 2018, Hitachi and the UK government commenced negotiations on the project. The UK's Business and Energy Secretary stated that the discussions focused on achieving lower cost electricity for consumers. He also told parliament on 4 June 2018, that a "long-term pipeline" of support would be provided for new nuclear projects in the UK.

Later in June, it was announced that Hitachi was also in discussions with Japanese banks and utilities regarding investment in Horizon.

In January 2019 Hitachi announced that it was suspending work at Wylfa Newydd and Oldbury, having failed to agree terms on funding with the UK government. The Business and Energy Secretary told parliament that the government was willing to consider a one-third equity stake in the Wylfa project, alongside investment from Hitachi and Japan government agencies and other strategic partners. It was also willing to consider providing all the required debt financing to complete construction, and it would consider a contract for difference agreement to the project with a strike price of no more than £75/MWh – somewhat less than for EDF's Hinkley Point C now under construction.

In September 2020 Hitachi withdrew from the project announcing that it will "end business operations on nuclear power plant construction project in the United Kingdom."

General Nuclear Systems – Bradwell B

Bradwell in Essex, close to London, is the site of a Magnox plant, with both reactors shut down in 2002. Under the strategic siting assessment process it was approved in 2011 as a site for new build. General Nuclear Systems (GNS) is a joint venture in which CGN has a 66.5% share and EDF 33.5% set up to undertake the Bradwell B project and bring it to a final investment decision. Bradwell B, as planned, will comprise two Hualong One units, each with a capacity of 1150 MWe.

In connection with the Hinkley Point agreement in October 2015, EDF and CGN agreed to form this joint venture company to advance plans for a new plant at Bradwell and seek regulatory approval – through the generic design assessment (GDA) process – for a UK version of the Chinese-designed Hualong One reactor. GNS wrote to the government in October 2016 applying to start the GDA process, and in November 2017 the assessment moved to the intensive stage 2. In October 2015 CGN had submitted the HPR1000 for certification of compliance with European Utility Requirements (EUR).

While the Bradwell project was expected to follow others, with the withdrawal of Toshiba from NuGen and Moorside, CGN said it was ready to bring forward its plans for Bradwell to have the first unit in commercial operation there from 2030.

In July 2020 the UK government announced a review of the national security impact of all Chinese investments in UK infrastructure, including Bradwell B. This followed its decision to block telecommunications company Huawei from participating in the development of the country's 5G mobile network.

Power reactors planned and proposed

Proponent Reactor/site Locality Type Capacity

(MWe gross) Construction start EDF Energyn Sizewell C1 Suffolk EPR 1670? Sizewell C2 Suffolk EPR 1670? Total planned 2 units 3340 MWe China General Nuclear Bradwell B1 Essex Hualong One 1150 China General Nuclear Bradwell B2 Essex Hualong One 1150 Total proposed 2 units 2300 MWe Horizon Wylfa Newydd 1&2 Wales ABWR 2760 Horizon Oldbury B1&B2 Gloucestershire ABWR 2760 GE Hitachi Sellafield Cumbria 2 x PRISM 2 x 311 Cancelled Candu Energy Sellafield Cumbria 2 x Candu EC6 2 x 740 Cancelled NuGeneration Moorside 1-3 Cumbria 3x AP1000 3 x 1135 Cancelled

The PRISM and EC6 options for Sellafield are alternatives for plutonium disposition.

Small reactors

The 2015 programme to "revive the UK's nuclear expertise" especially through developing small modular reactors (SMRs) has been accompanied by expressions of interest from various quarters. The government plans a competition to identify the best value SMR design for the UK. The Nuclear Advanced Manufacturing Research Centre (Nuclear AMRC) is focused on engineering capacity in the UK.

Since October 2015 NuScale, a 55% Fluor subsidiary, aims to deploy its 50 MWe SMR in the UK by in the 2020s, and seeks partners for this in addition to Sheffield Forgemasters. In January 2016 National Nuclear Laboratory (NNL) confirmed that the NuScale reactor can run on MOX fuel, and said that a 12-module NuScale plant with full MOX cores could consume 100 tonnes of reactor-grade plutonium in about 40 years, generating 200 TWh from it. This comment addresses a UK agenda for plutonium disposal – see section below. NuScale announced in March 2016 that it would put its SMR forward as part of the UK government's competition to identify the best value design for the UK. In September 2017, following acceptance of the company's design certification application by the US Nuclear Regulatory Commission (NRC) earlier in the year, NuScale released a five-point UK SMR action plan. On release the company re-stated its hope that it will build an SMR in the UK within a decade.

Also in October 2015 Westinghouse submitted an unsolicited proposal to partner with the UK government to license and deploy its 225 MW light water reactor, an integral PWR. The Westinghouse proposal involved a “shared design and development model” under which the company would contribute its SMR conceptual design and then partner with the UK government and industry to complete, license and deploy it. This would engage UK companies in the reactor supply chain such as Sheffield Forgemasters. In April 2016 Westinghouse confirmed that the UK had the manufacturing capability to build its SMRs, and reiterated its “commitment to developing SMR technology in the UK,” but it has since put development of this reactor design on hold.

Early in 2016 Rolls-Royce said it had submitted a detailed design to the government for a 220 MWe SMR unit, an SMR of fairly conventional design. It then submitted a paper to the Department of Business, Energy and Industrial Strategy, outlining its plan to develop a fleet of 7 GWe of SMRs with a new consortium. It said: "We firmly believe a UK SMR program presents a once in a lifetime opportunity for UK nuclear companies to be involved in the design, manufacture and building of next generation reactors for our needs at home and to access a huge global opportunity.” In January 2017 Rolls-Royce identified Amec Foster Wheeler, Nuvia and Arup, together with the Nuclear Advanced Manufacturing Research Centre, as partners. In July 2017 Laing O’Rourke joined the consortium.

In June 2016 GE Hitachi said it would be entering its PRISM fast reactor in the competition. See also mention of PRISM under Civil plutonium disposition below.

The Moltex stable salt reactor is another contender, the fast version of which the company plans to submit for GDA. Its fuel is plutonium-239 chloride with minor actinides and lanthanides, recovered from LWR fuel or from its 'global workhorse reactor'. A 300 MWe demonstration plant – the SSR-W300 wasteburner – is envisaged with conventional fuel tubes running on plutonium and uranium chlorides. It will have increased relevance if the UK government decides to use fast reactors for plutonium disposition. Moltex has submitted this and another 40 MWe thermal version of its design – the 'global workhorse' – in the SMR competition.

Other participants in the UK's SMR competition include EDF Energy and its Chinese partner CNNC. In 2016 CNNC subsidiary China Nuclear Engineering & Construction Corp (CNECC) submitted an expression of interest based on its ACP100+ design.

In July 2016 a UK parliamentary committee called for construction of an SMR at the brownfield Trawsfynydd site in Wales where a Magnox plant is being decommissioned.

In September 2016 the Energy Technologies Institute (ETI) released a report, Preparing for Deployment of a UK Small Modular Reactor by 2030. It examines the steps that will need to be taken by government, regulators, reactor vendors and operators in a "credible integrated schedule" to see construction of a first-of-a-kind reactor starting in 2025 with the reactor itself in operation by 2030. UK deployment of SMRs should allow for their use as combined heat and power (CHP) plants, supplying power to district heating systems.

In July 2020 the UK government awarded £40 million in funding to support advanced nuclear development. Three-quarters of the funding will go towards three 'advanced modular reactor’ projects – Westinghouse's lead-cooled fast reactor, Urenco’s U-battery, and Tokamak Energy, which is working with Oxford University to develop fusion reactors – with each receiving £10 million.

Fuel cycle facilities and materials: front end

From the outset, the UK had been self-sufficient in conversion, enrichment, fuel fabrication, reprocessing and waste treatment (see Appendix 1, Nuclear Development in the United Kingdom). Following the closure of the Thermal Oxide Reprocessing Plant (Thorp), the UK no longer has the ability to reprocess used fuel. Uranium is imported, as are conversion services now.

A 6000t/yr conversion plant at the Springfields site was managed by Westinghouse on a long-term lease from the Nuclear Decommissioning Authorityo. Early in 2005, Cameco Corporation bought ten years of toll conversion services from 2006, at 5000 tU/yr, though the agreement was terminated at the end of August 2014 and the plant then shut down finally. Feed was from Cameco's Blind River refinery in Ontario, Canada, and the product was sent to Cameco’s customers.

Enrichment is undertaken by Urenco at Capenhurst in three centrifuge plants, the oldest dating from 1976, and totaling 1.1 million SWU/yr. Urenco’s shares are ultimately held one-third by the UK government, one-third by the Dutch government and one-third by the German utilities RWE and E.ON.

Urenco opened a 7000 t/yr deconversion plant, or Tails Management Facility, at Capenhurst, in June 2019p. The facility will treat UF 6 tails from all three European Urenco sites: Capenhurst, Almelo in the Netherlands and Gronau in Germany. Depleted uranium will then be stored as the more chemically stable U 3 O 8 .

Fuel fabrication of AGR and PWR fuel is at Springfields, and other PWR fuel is bought on the open market. Magnox fuel fabrication, also at Springfields, ended in May 2008 after 53 years of production.

Fuel cycle facilities and materials: back end

Reprocessing activities at Sellafield are undertaken by Sellafield Ltd on behalf of the NDA. International Nuclear Services (INS, a wholly-owned subsidiary of the NDA) manages the contracts on behalf of the NDA. A 1500 t/yr Magnox reprocessing plant which opened in 1964 is due to close by the end of 2020, having reprocessed all of the UK Magnox fuel. The Thermal Oxide Reprocessing Plant (Thorp) was commissioned in 1994 and had a capacity of 600 t/yr. It closed in November 2018 having processed 9331 tonnes of used nuclear fuel from 30 customers in nine countries. About 60% of the processed used fuel was from UK plants. Some AGR used fuel and that discharged in the future will be placed in the Thorp storage pond at Sellafield for eventual disposal.

Sizewell B is running on reprocessed uranium, including blended-down reprocessed submarine reactor fuel from MSZ Elektrostal in Russia, part exchanged for UK reprocessed uranium.

Mixed oxide (MOX) fuel fabrication for export has been at the Sellafield MOX plant (SMP, see section on Sellafield in Appendix 1, Nuclear Development in the United Kingdom). In 2010, the NDA and ten Japanese utilities agreed on a plan to refurbish SMP, and this work was being undertaken over three years by Sellafield Ltd, involving a new MOX fuel fabrication line using Areva technology. However, in August 2011 the NDA said it had reassessed the prospects for the plant following the Fukushima accident, and closed it. About 15 tonnes of reactor-grade plutonium owned by the Japanese utilities is being held at Sellafield awaiting incorporation into about 270 tonnes of MOX fuel, but this may now be done in France or Japan. Consideration was being given to building a new MOX plant in the UK to utilize over 100 tonnes of stored UK plutonium. (MOX fuel costs about five times as much to fabricate as conventional uranium oxide fuel, which doubles the total fuel cost.)

Civil plutonium disposition

A March 2011 report outlined options for using or otherwise dealing with the UK's civil plutoniumq. This comprised some 100 tonnes of separated reactor-grade plutonium in storage that was UK-owned, and also the plutonium in 6000 tonnes of used AGR fuel from UK reactors. In a report on its 2016 inventory, the NDA said that 114 tonnes would be the total of UK-owned plutonium arising from reprocessing. Three of four options involved using the separated plutonium in MOX fuel, the main question being what to do with the AGR fuel – treat as waste, or reprocess. The report suggested that none of the options would be profitable, but some will have more economic and resource benefit than others. In essence, the report showed that it makes sense to produce MOX fuel from the plutonium. After a public consultation in 2011 the government later announced that it preferred a MOX option for as much of the plutonium as possible, rather than disposing of it as waste or continuing indefinite storage.

A novel solution was then proposed by GE-Hitachi: building two 311 MWe units of their PRISM fast reactor at Sellafield and operating them initially so as to bring the material up to the highly-radioactive 'spent fuel standard' of self-protection and proliferation resistance. The whole stockpile could be irradiated thus in five years, with some by-product electricity and the plant would then proceed to re-use that stored fuel over perhaps 55 years solely for 600 MWe of electricity generation. GE-H is starting to develop a supply chain in the UK with Costain, Arup & Poyry to support the proposal and prepare for UK design certification. In April 2012 an agreement was signed with the National Nuclear Laboratory (NNL) at Sellafield to investigate the proposal more closely.* GEH has launched a web p ortal in support of its proposal.

* In November 2011, the NDA wrote to GEH saying that for its proposal to be credible, it had to:

Demonstrate a disposability assessment for the spent fuel similar to the disposability assessment in regard to used MOX, through the usual RWMD processes. Demonstrate licenceability in some proper way, for example an assessment by a credible consulting engineer setting reactor aspects against UK safety assessment principles and demonstrating licenceability in principle. Demonstrate that it had a tie-in with a credible utility/reactor operator, i.e. a utility already established in the UK market and operating a nuclear plant somewhere in the world (like RWE, EON, Iberdrola etc.) who was prepared to own and operate a PRISM reactor. Demonstrate that the total cost of the implementation would be around £2.5 billion discounted and no more than a few hundred million pounds in any one year – i.e. about the same shape as the other options. Commit to a commercial structure that insulated government for technology deployment risk.

An alternative solution is proposed by Candu Energy: building two or four of its EC6 reactors (a 740 MWe modern version of its Candu-6) to burn MOX fuel with about 2% plutonium (CANMOX). At about 100 t fuel each per year, this would use 4 t/yr plutonium in twin units. Four units would draw down the initial inventory in 15 years. The company notes that the reactors could be fully built in the UK domestically.

Another alternative put forward in 2016 is the Moltex stable salt reactor, the fast version of which runs on plutonium-239 chloride in static fuel tubes.

Early in 2012 the NDA invited expression of interest in alternatives to simple MOX use, describing this as "the most credible and technologically mature option" but adding that it "remains open" to other ideas should they "offer better value or less risk for the taxpayer." It said it wanted to "gather more data on other options" and that it was talking with the government and third parties to review "whether alternative technologies may represent credible options" over a timescale of about 25 years. In June 2012 PRISM was shortlisted along with Candu’s EC6 reactor.

In January 2014 the NDA said that while PRISM and EC6 were credible options for most of the inventory, its reference solution was using MOX in light water reactors. However, it would continue to evaluate PRISM and EC6 over the next 1-2 years, as "currently, we believe there is insufficient understanding of the options to confidently move into implementation." A “multi-track approach” may be best, since a small portion (up to 15%) is “contaminated or in the form of residues or MOX scraps”. NDA also intends to work on regulatory and licensing aspects with the technology vendors and UK regulators to "define licensing needs and understand deployment risks such as fuel performance demonstration, noting this is a significant risk area for all options." In July 2014 Iberdrola (owner of Scottish Power utility) signed an agreement with GE Hitachi for cooperation in development of the PRISM option for UK plutonium use, in collaboration with the NDA. In May 2015 GE Hitachi said it was working closely with NDA on the PRISM proposal, stressing its Idaho EBRII provenance. Following a draft in May 2015, the NDA submitted a detailed report to DECC on the three options in December 2015. All three options allow for contaminated and otherwise unsuitable material to be immobilised in some form of Synroc by hot isostatic pressing.

It is assumed that GDA would be required for PRISM or Candu EC6 even if they were deemed to be non-commercial.

At the end of June 2015 Natural Resources Canada and the UK DECC signed a memorandum of understanding on enhancing cooperation in civil nuclear energy. It calls for increased cooperation throughout the nuclear fuel cycle, including: uranium supply; reactor design, construction, operation and decommissioning; adaptation of designs to use alternative and advanced fuel cycles that support the safe and proper disposition of legacy material. NRCan said: "The MOU will reinforce work already under way on feasibility studies related to the disposal of UK plutonium, and it will provide a framework to assess the development of power generation based on alternative nuclear fuels." Candu Energy said that the signing of the MOU "establishes the means and processes by which [its CANMOX] project could be adopted." The MOU “has the potential to unlock a powerful energy source for UK electricity consumers." GE Hitachi Nuclear Energy Canada, which is working with Candu Energy to develop the CANMOX approach, said that the MOU "is a very positive step in bringing heavy water reactor technology back to the UK."

Also in 2015 Areva was promoting its Convert proposal to use the plutonium in about 7000 MOX fuel assemblies, as conventionally done in France, where the EDF plants have more than 400 reactor-years' experience in using it, over 29 years. It said this would save 20,000 tonnes of natural uranium.

In January 2016 National Nuclear Laboratory (NNL) confirmed that the NuScale 50 MWe small modular reactor can run on MOX fuel, and said that a 12-module NuScale plant with full MOX cores could consume 100 tonnes of reactor-grade plutonium in about 40 years, generating 200 TWh from it. Areva is already involved with fuel manufacture for NuScale.

The UK's plutonium stockpile is reported as about 139 tonnes.

In mid-2014 a plan was announced to extract americium-241 from the ageing plutonium stockpile. Am-241 is a decay product of plutonium and can render it too gamma-active to feed through a MOX plant. The Sellafield MOX Plant could not handle plutonium more than six years old, as it then contained more than 3% Am-241. About 250 kg of old civil plutonium (originally with about 10% Pu-241 from AGRs or 14% from PWRs) will yield 10 kg of Am-241, depending on its age – the half-life of Pu-241 is 14 years. Am-241 is used in most household smoke detectors, and here the European Space Agency is paying NNL to produce radioisotope thermoelectric generators (RTGs) using Am-241 extracted from old plutonium, as they are less expensive than those using Pu-238, despite needing shielding.

Radioactive waste

Most UK radioactive waste is a legacy of the pioneering development of nuclear power, rather than being normal operational waste arising from electricity generation – though there is a significant amount of this. Some are from military programs. Until 1982, some low- and intermediate-level waste was disposed of in deep ocean sites. In 1993, the government accepted an international ban on this.

Solid low-level waste is disposed of in the 120 ha Low Level Waste Repository (LLWR) at Drigg in Cumbria, near Sellafield, which has operated since 1959. Dounreay* has vaults for 175,000 m3 of operational and decommissioning low-level waste from the site.

Intermediate-level waste is stored at Sellafield and other source sites, pending disposal. A new store at Harwell, Oxfordshire, for 2500 m3 of decommissioning waste is planned.

High-level waste (HLW) arising from reprocessing is vitrified and stored at Sellafieldr, in stainless steel canisters in silos.

A dry cask storage set-up for used fuel at Sizewell B was commissioned in April 2016, using Holtec's Hi-Storm system. A new type of cask was developed for Sizewell, and the first one was placed in the new building in March 2017. All HLW is to be stored for 50 years before disposal, to allow cooling.

HLW management and disposal

A consultation on regulations relating to waste was carried out from March 2010. The Waste Transfer Pricing Methodology consultation document in light of this was issued by the government in December 2010, setting out how a price will be determined for the transfer to government of new-build higher-activity waste and its disposal in the UK's planned geological disposal facility (GDF). This includes setting a cap on waste transfer price to provide operators with some price certainty. The cap will be high – perhaps £1100 million per 1350 MWe PWR, which is three times current cost estimates, and the actual price – including contribution to disposal facility – will be set 30 years after the reactor starts operation, not earlier. Operators will need to make credible and secure provision for funding the waste transfer. Used fuel will be priced in £/tU, not p/kWh as earlier proposed, and as common elsewhere.

The NDA has set up the Radioactive Waste Management Directorate (RWMD) to develop plans for a deep geological repository for high- and intermediate-level waste and evolve into the entity that builds and operates it. The geological disposal facility (GDF) is expected to cost around £12 billion undiscounteds from conception, through operation from about 2040, to closure in 2100. Site selection was expected to be in around 2025. The government invited communities to volunteer to host the GDF, with three expressions received, representing two areas of Cumbria: Allerdale and Copeland. The next steps were to undertake a four-year geological study; surface research lasting ten years; and finally a 15-year period of underground research, construction and commissioning. In these steps the NDA said it would seek to find an 11-year saving to enable operation from 2029. However, plans were stalled early in 2013 when Cumbria County Council voted to halt the project.

In July 2014 the government published a white paper outlining its plans for a two-year consultation and then establishment of the GDF. The white paper set out a number of actions which the government and the developer RWMD would carry out over the initial two years of the new process. The aim is to provide interested local communities with more information and greater clarity about the nature of a development. The NDA had expected to progress site selection on this basis of volunteered sites in 2017, but this was deferred due to a series of elections which legally precluded concluding the consultation. The two-year consultation was completed at the end of 2018, and in January 2019 the government launched the formal site selection process. The RWMD expects 15-20 years to be required to identify and investigate sites.

Earlier in 2015, the government designated the development of a GDF and deep boreholes as nationally significant infrastructure projects, under the Planning Act 2008, in England. This is expected to expedite planning and permitting.

The government is planning for the GDF to accommodate waste from new build as well as legacy waste (which includes committed waste from existing operational facilities and those undergoing decommissioning). Operators of new plants would be charged a fixed unit price for disposal of intermediate-level wastes and used fuel in the GDF (see section above on Funded decommissioning programme). See also section on Geological disposal facility in Appendix 1, Nuclear Development in the United Kingdom.

Decommissioning

Four consortia bid to take over the decommissioning of ten Magnox power plants* with 22 reactors and two nuclear research facilities at Harwell and Winfrith as the private sector ‘parent body organisation’ (PBO) for the 14-year task. NDA commenced dialogue with them in January 2013 and in March 2014 announced that a joint venture between Cavendish Nuclear and Fluor Corporation had been selected as preferred bidder. The companies Magnox Ltd and Research Sites Restoration Ltd (RSRL) managed all the 12 sites as licensees, and the transition to Cavendish Fluor Partnership (CFP) was completed in September 2014. CFP became the parent body organisation for Magnox and RSRL. In April 2015 Magnox Ltd took over the two RSRL sites in a merger. Cavendish Nuclear is a subsidiary of Babcock International. The contract value was about £6.1 billion over 14 years from September 2014 when work began.

However, as work proceeded it became clear that there was “a significant mismatch between the work that was specified in the contract as tendered in 2012 and awarded in 2014, and the work that actually needs to be done.” The NDA board concluded that the scale of the additional work required "would amount to a material change to the specification" and it therefore decided to terminate the contract with two years' notice, in September 2019. CFP agreed to this. The NDA will establish arrangements for "a replacement contracting structure" to be put in place when the current contract ends.

In 2016 the last of the 68 tonnes of sodium and potassium primary coolant was removed from the Dounreay Fast Reactor which is being decommissioned. This was reacted with water in inert atmosphere and the hydroxide was subject to ion exchange to remove radionuclides. About 1 PBq of Cs-137 was removed and stored as ILW.

The clean-up of legacy nuclear sites is estimated to cost £117 billion over 120 years. The estimate is based on the expected costs of decommissioning, dismantling and demolishing the buildings, managing and disposing of all waste, and remediation of land. Decommissioning work is carried out by site licence companies, working for the NDA. Costs are currently around £3 billion annually. Of this, about two-thirds is met by the government and the remainder from revenue earned through the NDA's commercial activities.

Public opinion and industry support

In the light of developments since 2006, public opinion in UK has remained positive regarding nuclear power, despite the March 2011 accident at Japan's Fukushima Daiichi nuclear plant. Of more significance is that there is strong political support across the two main political parties.

The March 2019 Department for Business, Energy & Industrial Strategy (BEIS) survey (N=4224) showed 35% support for nuclear power and 23% against, with 38% neutral. Support was higher among men (45%, compared with 26% of women).

48% agreed that nuclear energy provides a reliable source of energy for the UK, with just 16% disagreeing; 37% agreed that nuclear energy provides affordable energy for the UK, with 19% disagreeing; 34% agreed that nuclear energy provides a safe source of energy for the UK, with 30% disagreeing; and 33% agreed that nuclear energy will help combat climate change in the UK, with 24% disagreeing.

Industry support

In March 2013 the government published a 90-page industrial strategy document entitled The UK's Nuclear Future which set out the government's "clear expectation that nuclear will play a significant role in the UK energy mix in the future" and outlines its plans to align the UK as a leading civil nuclear energy nation. It covers the nuclear energy industry in its entirety, encompassing new build, waste management and decommissioning, fuel cycle services, and operations and maintenance. More than £45 million of funding was provided to related initiatives.

In July 2013 the Department of Energy & Climate Change (DECC) announced financial incentives for communities in England hosting nuclear power plants, wind farms or shale gas development. It said that local governments would receive a 50% share of business taxes from a new plant for the first ten years of operation, and then £1000 per MWe of installed capacity annually for a further 30 years. Hence for Hinkley Point this could amount to £128 million over 40 years. For wind farms, £5000 per MWe installed is offered, but over 15-20 years.

In October 2015 the Royal Academy of Engineering (RAE) published a report entitled A Critical Time for UK Energy Policy, which details the actions needed to create a secure and affordable low-carbon energy system for 2030 and beyond. It said that a fundamental restructuring of the whole energy system is needed if the UK is to meet the so-called energy 'trilemma' of affordability, security and decarbonisation and that "time is rapidly running out to make the crucial planning decisions and secure investment" to ensure the UK has a secure energy system which meets its emissions targets. "As a secure, base-load source of low-carbon electricity, nuclear power is essential," and anything much less than 15 GWe by 2030 would be a concern.

Research & development

Though the UK was a pioneer of nuclear power development, designing the Magnox and then AGR types along with fuels for them, as well as fast neutron reactors, since the 1980s there has been no significant fuel cycle R&D or reactor design undertaken in the country.

This neglect seems set to change with the announcement in November 2015 of a £250 million nuclear R&D programme to "revive the UK's nuclear expertise" especially through developing small modular reactors (SMRs) and position the country as "a global leader in innovative nuclear technologies." The funding was through the Department of Energy and Climate Change (DECC, now part of Department for Business, Energy & Industrial Strategy). "The government's doubling of investment in DECC's innovation programme will help position the UK as an international leader in small modular nuclear reactors, and deliver commitments on seed funding for promising new renewable energy technologies and smart grids," and is part of government plans to "prioritize energy security, whilst making reforms to meet our climate goals at lower cost." This will include a competition to identify the best value SMR design for the UK, paving the way towards building one of the world's first new-generation SMRs in the country in the 2020s. Plans for an SMR in the UK in the 2020s follow the December 2014 feasibility report by a consortium led by National Nuclear Laboratory (NNL) into the potential impact of SMR technology on the UK energy sector and the UK nuclear supply chain.

Of 36 research and experimental reactors built and operated, only one remains operational, Rolls-Royce’s tiny Neptune critical assembly. Some of the best-known past reactors indicating the breadth of R&D include the 120 MWt Windscale AGR, the 65 MWt Dounreay fast reactor, two 26 MWt heavy water reactors, Pluto and Dido, and the 20 MWt Dragon high-temperature reactor. The Dounreay fast reactor led to the much larger Protoype Fast Reactor which ran for 20 years but was not followed through commercially.

In connection with the government’s offer of a £2 billion loan guarantee for the Hinkley Point C project, it was announced that the UK and China will co-fund a £50 million "cutting-edge" nuclear research centre, to be headquartered in the UK. This Joint Research and Innovation Centre (JRIC) was to be run by the National Nuclear Laboratory (NNL) in conjunction with CNNC, but it has not proceeded.

The UK's R&D programme is covered in more detail in Appendix 1, Nuclear Development in the United Kingdom.

Safety, security and non-proliferation

The principal regulating provision in the UK is the Nuclear Installations Act 1965, which governs the construction and safe operation of nuclear plants. This is administered by the Health and Safety Executive (HSE)u, which regulates the safety of all nuclear installations independently of government departments, and licenses them. Under HSE, nuclear safety regulation is carried out by the Office for Nuclear Regulation (ONR); nuclear security regulation is carried out by the Office for Civil Nuclear Security (OCNS); and nuclear safeguards functions are carried out by the UK Safeguards Office (UKSO)t. Regulatory responsibility for the transport of radioactive materials moved from the Department for Transport to ONR in October 2011. The ONR became an independent public corporation in April 2014, no longer part of the civil service.

The Nuclear Installations Act is supported by the Ionising Radiations Regulations 1999, which require employers to keep radiation exposure of workers and the public as low as practicable and within specified limits. The Nuclear Generating Stations (Security) Regulations 1996 and the Radioactive Material (Road Transport) Act 1991 are also relevant. Waste management and discharges to the environment are regulated by the Radioactive Substances Act 1993.

Regarding nuclear third party liability, in 1994 the limit was increased to £140 million for each major installation, so that the operator is liable for claims up to this amount and must insure accordingly. The government is running a public consultation (finishing at the end of April 2011) that would increase the liability to €1.2 billion (£1 billion), in line with amendments agreed in 2004 to the Paris Convention on nuclear third party liability and Brussels Supplementary Convention34.

Non-proliferation

The UK is a nuclear weapons state, party to the Nuclear Non-Proliferation Treaty (NPT) which it ratified in 1968 and under which a safeguards agreement has been in force since 1972. The Additional Protocol in relation to this was signed in 1998. International Atomic Energy Agency safeguards are applied on all civil nuclear activities. (The UK undertook 45 nuclear weapons tests over 1952-91 – most in the 1950s in Australia).

Notes & references

Notes

a. The Labour government of 1997-2010 and nuclear policy:

Over the three parliamentary terms from 1997 to 2010 that the Labour party was in office, the government went from opposing new nuclear power plants to being in favour of them. The February 2003 energy white paper, Our energy future – creating a low carbon economy1, stated that the government had no current plans to expand the use of nuclear power. According to this white paper, the "current economics" of nuclear power "make new nuclear build an unattractive option and there are important issues of nuclear waste to be resolved." The government therefore did not propose to support new nuclear build, although it added: "But we will keep the option open." The white paper went on to promise that, before any decision to proceed with new nuclear build was made, "there will need to be the fullest public consultation and the publication of a further white paper setting out our proposals." Alongside the rejection of new nuclear build and without any hint of irony, the white paper set out the government's "ambition" to cut greenhouse gases by around 60% by 2050 (compared with 1990 levels).

By 2006, government policy on nuclear had completely changed, with the report of its energy policy review stating: "We have concluded that new nuclear power stations would make a significant contribution to meeting our energy policy goals."2 However, this conclusion was successfully challenged in the High Court by Greenpeace on the basis that the promise made in the 2003 white paper for "the fullest public consultation" had not been kept. In his decision of February 2007, Mr. Justice Sullivan concluded: "There was a breach of the claimant's legitimate expectation to fullest public consultation; that the consultation process was procedurally unfair; and that therefore the decision in the Energy Review that nuclear new build 'has a role to play...' was unlawful."3

Following the High Court decision, in May 2007 the government's Department for Trade and Industry (DTI) published a new white paper, titled Meeting the Energy Challenge4 in which the government stated its "preliminary view that it is in the public interest to give the private sector the option of investing in new nuclear power stations." Alongside the white paper, a new consultation on the future of nuclear power, as well as parallel technical consultations on a justification process and siting, was launched5. This extensive consultation process led to the 10 January 2008 publication of Meeting the Energy Challenge – A White Paper on Nuclear Power, the foreword (by Prime Minister Gordon Brown) of which stated: "The electricity industry should, from now on be allowed to build and operate new nuclear power stations."6 In stark contrast to the 2003 energy white paper, the foreword also acknowledged: "Nuclear power can and will make a real contribution to meeting our commitments to limit damaging climate change."

The target for reducing greenhouse gas emissions was increased to 80% by 2050 (compared with 1990 levels) and made legally binding in the Climate Change Act 2008, which entered into force in November 2008.7 The Act also provides for a reduction of 34% in greenhouse gas emissions by 2020.

The legally binding targets for emissions reductions set out in the Climate Change Act have put nuclear at the centre of national energy strategy. In July 2009, the government set out its policy on nuclear power in a document titled The Road to 2010: Addressing the nuclear question in the twenty first century8. It states that nuclear power is "an essential part of any global solution to the related and serious challenges of climate change and energy security." Furthermore, the document continues: "Nuclear energy is therefore vital to the challenges of sustaining global growth, and tackling poverty." [Back]

b. Legal power to consent onshore electricity generating stations with a capacity of over 50 MWe is devolved to Scotland and Northern Ireland. Given that the Scottish Government "is clear that new nuclear power is not wanted or needed in Scotland," this effectively means that no new nuclear plants are likely to be built in Scotland. The main objective of the Scottish Government's energy policy is "to progressively increase the generation of renewable and clean energy, to migrate Scotland away from a dependence on nuclear energy."9 [Back]

c. The Conservative-led coalition government is expected to introduce legislation to abolish the Infrastructure Planning Commission (IPC) in late 2010. The IPC would be replaced with a Major Infrastructure Planning Unit within the Planning Inspectorate to provide advice on new infrastructure projects to Ministers10. [Back]

d. The 11 sites nominated for the strategic siting assessment (SSA) process were: Bradwell, Braystones, Dungeness, Hartlepool, Hinkley Point, Heysham, Kirksanton, Oldbury, Sellafield, Sizewell and Wylfa. (Braystones and Kirksanton are greenfield sites near Sellafield.) The government came to the preliminary conclusion that all of the nominated sites except Dungeness are potentially suitable for new nuclear power stations by the end of 2025. The government also commissioned Atkins Ltd to identify other possible sites worthy of further consideration13. The government's preliminary conclusion for the three alternative sites identified in this study – Druridge Bay in Northumberland, Kingsnorth in Kent and Owston Ferry in South Yorkshire – was that they are not potentially suitable for the deployment of new nuclear power stations by the end of 2025. The draft Nuclear National Policy Statement (Nuclear NPS) therefore listed ten potentially suitable sites for new nuclear plants to be built by 2025. A consultation on this draft Nuclear NPS, along with five other draft National Policy Statements for energy infrastructure, ran from November 2009 to February 2010.14

Information on the draft Nuclear NPS can be found on the website for the Consultation on draft National Policy Statements for Energy Infrastructure (www.energynpsconsultation.decc.gov.uk) [Back]

e. A consultation on six draft National Policy Statements for energy infrastructure, including the draft Nuclear NPS, ran from November 2009 to February 2010. A formal response, together with the final National Policy Statements, had been expected later in 2010 but, following the May 2010 general election, the new coalition government decided to make changes to the Appraisals of Sustainability of the NPSs. (An Appraisal of Sustainability assesses the environme