Nuclear Power in the United Kingdom
(Updated 25 November 2016)
- The UK has 15 reactors generating about 21% of its electricity but almost half of this capacity is to be retired by 2025.
- The country has full fuel cycle facilities including major reprocessing plants.
- The UK has implemented a very 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.
- The first of some 19 GWe of new-generation plants is expected to be on line by 2025. The government aims to have 16 GWe of new nuclear capacity operating by 2030, with no restriction on foreign equity.
- Two of the three major projects involved in new nuclear build has a reactor vendor involved – with 60% and 100% of equity respectively.
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. Total capacity at the end of 2014 was 97 GWe (according to International Energy Agency data).
In 2015, 338 TWh of electricity was produced in the UK (DECC data). This comprised 70 TWh (21%) nuclear, 100 TWh (29.5%) from gas, 76 TWh (23%) from coal, 2 TWh from oil, and 25% from renewables: 40 TWh (12%) from wind, 7.5 TWh from solar, 9 TWh hydro and pumped storage, 29 TWh from biofuels and 4 TWh from wastes. Net electricity imports – mostly nuclear – were 21 TWh, comprising 13.8 TWh from France, 8.0 TWh from the Netherlands, and 0.9 TWh net was exported to Ireland.
There is a 2000 MW high-voltage DC connection with France and a 1000 MW one with Netherlands; also a 1000 MW one with Belgium is under construction for 2018, and a 1400 MWe link over 750 km with Norway is under construction for 2021 commissioning. A further 2000 MW connection to Normandy was approved in September 2016 to enable the import of French nuclear power from 2022. In 2015 the France link ran at 81% capacity and the Netherlands one at 91%. Per capita UK electricity consumption was about 4700 kWh in 2014.
In 2009, half of British gas was supplied from imports (compared with 32% in 2007), and this is expected to increase to at least 75% by 2015, as domestic reserves are depleted.
North Sea oil has been a major energy and revenue source for the UK, but the resources are now depleted and the looming decommissioning cost is about £30 billion, with the government liable for 60% of this.
UK energy policy since the 2008 Energy Act through to July 2015 has been built around reducing CO2 emissions rather than security of supply or cost. In 2010-11 the price of renewable energy certificates doubled the price or electricity from those sources – an increasing proportion, including imports – more than one-quarter. Hence energy poverty is an issue in the UK (as elsewhere), and in the winter of 2012-13 some 31,000 excess deaths – mostly people over 75 – were reported by the Office of National Statistics, the highest figure since 2008. Since wind is intermittent, it displaces CCGT power and compromises the economics of that. From August 2015 renewables no longer receive climate change levy exemption certificates, saving £3.9 billion over five years. In 2013-14, 18.6 TWh was involved and 67.2 million certificates were issued or redeemed, 57% for wind, 17% for biomass and 12.6% for hydro.
The power supply implication of the EU Renewable Energy Directive mandating 15% of all energy, is that 30% of UK electricity should come from renewables by 2020.
One manifestation of the focus on renewables has been the conversion of one 645 MWe unit of the Drax coal-fired power plant to burn biomass, mainly imported wood pellets, for a guaranteed power price of £105/MWh. However, in April 2014 the second unit converted to biomass was denied similar investment contract support, leaving it to recoup costs from Renewables Obligation Certificates (at 0.9 ROC/MWh; the average ROC price in May 2014 was about £41.70) plus the wholesale power price – about £50/MWh. A court appeal failed. However, the government has offered an investment contract with price guarantee for the third Drax unit. (See also UK section in Energy Subsidies paper.) Each Drax unit burning biomass uses about 4 million tonnes of imported wood pellets per year. Drax is seen to be the biggest single loser from removal of Climate Change Levy exemption for renewables in August 2015.
In November 2015 the government articulated new policy priorities for UK energy, involving possibly phasing out coal-fired generation without CO2 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. There are plans for a new fleet of nuclear power stations, including at Wylfa and Moorside. It also means exploring new opportunities like small modular reactors, which hold the promise of low cost, low carbon energy."
UK generating capacity (2013) was 91.5 GWe, comprising 35 GWe gas, 21 GWe coal, 9.9 GWe nuclear, 11 GWe wind (21.7% load factor in 2010), 4.2 GWe hydro including pumped storage, 3.4 GWe oil, 2 GWe biofuel & wastes. Peak demand in 2013 was 53.4 GWe.
The history and development of the UK nuclear industry is covered in Appendix 1 to this paper, Nuclear Development in the United Kingdom. Currently, there are 15 operating reactors in the UK totalling 9.5 GWe capacity. 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.
Power reactors operating in the UK
||Present capacity (MWe net)
|Dungeness B 1&2
||2 x 520
||1983 & 1985
||1983 & 1984
|Heysham I 1&2
||1983 & 1984
|Heysham II 1&2
||2 x 610
|Hinkley Point B 1&2
|Hunterston B 1&2
||1976 & 1977
||1988 & 1989
|Total: 15 units
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, which in any case will shut down any plant considered unsafe.
EDF Energy is planning life extensions averaging eight years for the AGR units and 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. The company confirmed it in January 2015. 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 and Hinkley Point, the two oldest power stations, age cracking of graphite bricks comprising the moderator is carefully monitored, and is nowhere near any level of concern or likely to limit operational lifetime. 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.
New nuclear policy and procedure
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. Since then, the question of new nuclear build was 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 of Business, Energy and 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.
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).
Nuclear site 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 CO2 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.
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 for a nuclear site license for two Areva EPRs at Hinkley Point C. ONR assessed the company's "suitability, capability and competence to install, operate and decommission a nuclear facility" and issued a licence in November 2012. Local government had given permission to prepare the site.
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 will 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.
- 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 its Office for Nuclear Regulation (ONR), was on course to completed 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 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 on design acceptability (iSODA) for the two designs in mid-December 2011. A full DAC and SODA may be issued for the UK EPR by the end of 2012, but Westinghouse requested a pause in the GDA process pending customer input to finalizing it. As Westinghouse became part of NuGen due to the Toshiba 60% stake in that project, the process for AP1000 resumed, and is scheduled to be completed in March 2017 with issuance of the DAC and SODA. To March 2016, the cost of the GDA for the AP1000 was £30 million.
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 control and instrumentation among ONR, US NRC, France's ASN and Finland's STUK. For the AP1000, the ONR is drawing upon experience with the eight AP1000 units under construction in China and USA. More broadly it relates to the Multinational Design Evaluation Programme and will help improve the harmonization of regulatory requirements internationally.
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 said the GDA process was on schedule to be completed by the end of 2017. There are four operable ABWR units in Japan, while two more are under construction. Two more are partly built in Taiwan and one is planned for Lithuania. The design is already licensed in Japan and the USA. It can run on a full-core of mixed-oxide (MOX) nuclear fuel. To March 2016, the cost of the GDA for the ABWR was £17.5 million.
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 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. Rolls-Royce will undertake engineering and safety assessment work on the VVER technology. Fortum operates two early but westernised VVER units in Finland.
In 2015, China General Nuclear Power Group (CGN) said it intended to apply in mid-2016 for GDA for the 1150 MWe Hualong One (HPR1000) reactor design, with a view to building it at Bradwell. A joint venture with EDF Energy holding 33.5% and CGN 66.5% will be formed for progressing the GDA. The ONR said it is ready to commence the GDA for the HPR1000, and is advising EDF and CGN meanwhile.
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 expects to apply for GDA in the UK in 2016.
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.
Emissions reductions for CO2
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."
A range of measures aimed at reducing greenhouse gas emissions were introduced in the Climate Change Act 2008, which provided for legally binding greenhouse gas emissions reduction targets of 80% by 2050 (compared with 1990 levels) and 34% by 2020. In May 2011, a target of 51% reduction from 1990 levels for 2022-2027 was added. The fifth carbon budget set in June 2016 for 2028-2032 aims to cut CO2 emissions from 1990 levels by 56.9%. Provisional figures for 2015 show a 38% reduction from 1990 levels.
Following the 2010 general election, the new coalition government announced a floor price for carbon emissions, and this was introduced in April 2013 as the Carbon Price Floor (CPF) tax. It taxes the fossil fuels used for generating electricity to achieve a minimum total rate for CO2 emissions, considering both EU and domestic measures. The total rate escalates to give a rising price curve. For coal, the rate started off at £0.82 per GJ and doubled in April 2015, then rose slightly to £1.55/GJ in April 2016. This amounts to £18 per tonne of CO2 on top of the much lower ETS figure, resulting in significant disincentive to using coal. The 2016 Autumn Statement from the government maintained this £18/t cap level to 2020 (instead of the earlier intention to raise it to almost £25/t).
Electricity market reform
In July 2011 the government issued a new white paper on Electricity Market Reform (EMR). 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 carbon floor price has long been seen as fundamental to the economics of new UK nuclear power, with the EU's Emissions Trading System (ETS) not producing high enough prices to steer markets towards low-carbon power. Having legislated this in 2011, the UK government set a minimum of £16 per tonne CO2 from 2013, rising steadily to £30 per tonne in 2020 and accelerating to £70 per tonne in 2030. This then is essentially a carbon tax, with a longer timeframe and higher level than the UK Climate Change Levy on fossil fuel and nuclear sources, which continues to 2023.
Draft legislation was published in May 2012 to reform the UK's electricity market and thus secure the necessary investment for a low-carbon energy mix including new nuclear. The government estimates that £110 billion of new investment needs to be attracted to develop the low-carbon generating capacity required in the next ten years while meeting the country's climate change goals. New nuclear capacity, along with renewables and fossil fuels abated by carbon capture and storage (CCS) are recognised in the document as the three families of low-carbon generation with roles to play. All have high capital cost, so investors must have some assurance of commercial, or at least stable, returns. The EMR bill elaborates the policy instruments in the 2011 white paper. The main elements are:
- Feed-in tariffs (FIT), relatively common in several countries, give particular low-carbon producers a predictable return per kWh over a set period regardless of prevailing market prices. The FIT here will replace the UK Renewables Obligation which requires retailers to buy a certain proportion of power from renewable sources, excluding nuclear, in 2017 (RO certificates in mid-2012 traded at 5.5 p/kWh). In UK the FIT will be effected through contracts for difference (CfD) which remove long-term exposure to electricity price volatility.
- Capacity market measures will involve retainer payments for dispatchable capacity. They will work through penalties and availability payments to provide an incentive for generators to be available when needed.
- The Emissions Performance Standard is a 'regulatory backstop' to the other measures, setting 450 g/kWh CO2 as a limit under which new fossil-fuel plants must operate. This will allow gas but not coal without carbon capture & storage.
The UK National Grid is the independent system operator to be the delivery body for EMR and will administer the CfDs and the capacity market, with some involvement of the government regulator, Ofgem. The bill will be introduced into parliament at the end of November. The minimum prices new renewables sources can receive for selling into the grid were published in June 2013 and will apply until 2017, when prices will be subject to revision.
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 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 FIT or strike price level applied to clean sources. Government consulted on the first set of CfD strike prices for renewables in mid-2013 and expected to be able to announce the 2014-2018 prices by the end of 2013. Draft strike prices for renewables include £155/MWh for offshore wind, £100/MWh for onshore wind and £125/MWh for large solar PV. In 2014 a 15-year CfD for the 300 MWe Tees biomass plant was issued at £125/MWh. By the end of 2015 the government had 34 CfDs for renewables projects averaging £120-130/MWh. (The CfD strike prices for Hinkley Point C nuclear plant are set out below.) EC state aid clearance was granted in October 2014. 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 will involve 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. The first capacity auction is scheduled for December 2014, for delivery during winter 2018-19. See subsection below.
- A final investment decision (FID) enabling 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 renewable investors to choose between the new system and the existing renewables obligation which will remain stable up to 2017.
- Government had legislated to establish a carbon price floor from April 2013, to underpin the move to a low-carbon energy future. The carbon price support (CPS) tax will be the difference between the UK floor price and the ETS traded price. Per tonne of CO2, this CPS cap rises from an original £4.94 to £18 from 2015 to 2020. (It was to rise to £21.20 for 2016-17 and £24.62 for 2017-18, but these rates were abandoned due to public pressure.) Hence from 2015 the CPS costs a coal-fired plant about £16-18/MWh.
- The supplier obligation is a compulsory levy and it will be enforceable by the government-owned counterparty company as if it were a licence condition. It will be collected on a unit cost fixed rate (£/MWh). Each supplier will therefore collect it in line with its market share and pay it to the counterparty for passing onto the generators. The supplier obligation will need 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, the agreement provides protection from being curtailed without appropriate compensation.
A UK guarantee 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 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. Capacity agreements for new dispatchable capacity will be for 15 years, and agreements for existing capacity will be 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 will 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 will be a variant of this, and with the uncertainties of forecasting demand and the four years lead time between auction and delivery, supplementary auctions will be held one year ahead (especially for demand-side response) or private trading can adjust for contingencies. Successful bidders for new capacity will be 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 will be held every year, for delivery four years ahead. A demand curve for the year (eg 2018-19) will be published before the auctions and will be 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 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. Re technology, 45% was CCGT, 19% coal/biomass, and 16% nuclear.
* A further 2.5 GWe will be contracted in late 2017 for one year 2018-19.
The net cost of new entry (net-CONE) is put at £49/kW. Capacity providers successful in the auction will be paid by retail suppliers in the year of delivery. Payments will be administered by Elexon, as settlement agent. They will be 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. About 62 GWe of capacity had pre-qualified in October to bid in the auction, 7.6 GWe of this being new build plant bidding for 15-year contracts, 19 GWe being existing plant in need of refurbishment bidding for three-year contracts – this including all EDF Energy’s nuclear plants – and 35 GWe being existing plant bidding for a one-year contract.
Some interim arrangements including demand side will apply to cover the period to 2018. 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.
Plans for new nuclear plants
The government assumed there will 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 states 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 to 2030.
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.
More recently 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. SNPTC was said to be interested in a share of NuGeneration’s Moorside project, but has not confirmed this since Toshiba bought in.
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 plans 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 has confirmed that Chinese companies can own and operate Chinese-designed nuclear plants subject to normal approvals.
EDF Energy – Hinkley Point C
EDF Energy plans to build two EPR nuclear reactors at Hinkley Point in Somerset, linked to some extent with its plans to build two more at Sizewell in Suffolk. The company applied for consent to construct and operate the first two (3260 MWe) at Hinkley Point in October 2011, though the generic design assessment (GDA) process on reactor designs was not concluded (see section above on generic design assessment). 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 the plant operation, and planning permission was received.
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 Guarantee 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. The key terms include 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 remains 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 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.
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 holds 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.
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 will be through its new company, General Nuclear International. EDF Energy said that the agreement “sets the steps for a final investment decision” expected in September 2016 after prolonged consultation with French unions. UK trade unions expressed “100% support”. The EDF-CGN joint venture is Nuclear New Builds Generation Co (NNB), which holds the site licence issued in 2012.
Late in July 2016 EDF made its decision to proceed with the project, with full construction to begin in mid-2019. However, the UK government then 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 then 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 expects 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.
EDF will act as architect-engineer. Contractors include Areva for the reactor system, its fuel and control and instrumentation, 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 on site 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.
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 is in joint venture with CGN building 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 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.
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.
NuGeneration – Moorside
NuGeneration* was set up early in 2009, and comprised a 50:50 joint venture of Iberdrola (which owns Scottish Power) with GDF Suez. 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. New partners are being sought, and Kepco is reported to be interested.
* 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.
Toshiba and GDF Suez (now Engie) confirmed their intention of building three AP1000 reactors at Moorside, with the first unit to be online in 2024. A site licence application is expected early in 2017, after the GDA for the AP1000 is approved. Following a final investment decision in 2018, at least 18 months will be required for site works before starting construction. Then Westinghouse expects the first unit to take 54 months to build, up to fuel loading.
NuGeneration in October 2009 bought the 190 ha Moorside site on the north side of Sellafield from the NDA for £70 million. Technology choice is the 1200 MWe Westinghouse AP1000 reactors due to Toshiba ownership, and an investment decision is expected by the end of 201829.
In December 2014 NuGen signed a cooperation agreement with the government to gain access to the 2012 UK Guarantees scheme for infrastructure in order to expedite external project finance for Moorside. Also it was in discussion with DECC regarding terms for the contracts for difference (CfD) for the plant, which need to be agreed before the late 2018 investment decision. The company said in November 2016 that it expects the cost of the project to be £13 to £15 billion.
National Grid will 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. Putting cables through a 22 km tunnel under Morecambe Bay to avoid the south part of the national park will cost £1.2 billion, the major part of £1.9 billion to put transmission lines out of sight.
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 Ltd. It planned to build two or three of the 1380 MWe (gross) ABWR units at each site, and in April 2013 applied to ONR for Generic Design Assessment (GDA), which is expected to take until the end of 2017. Site works would begin 12-18 months before then, with investment decision and full construction possibly from 2019. In December 2013 Hitachi said it plans two units at each site. As with the EPR design, the ONR will work with overseas regulators on assessment of the UK ABWR. (Another ABWR unit is planned for Visaginas in Lithuania, and several 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 is progressing the GDA for Wylfa Newydd with ONR. In 2015 Hitachi incorporated in UK a new company Hitachi Nuclear Energy Europe Ltd (HNEE) which will represent the parent company in a proposed joint venture with Bechtel Management Co and JGC Corporation (based in Japan) to be set up by 2017 for the engineering, procurement and construction (EPC) of the project. HGNE will operate under contract to the new JV. In July 2016 Horizon and Hitachi signed a technical services contract with Japan Atomic Power Co to support Horizon in construction, costing, licensing and commissioning the ABWR units.
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. Babcock International expressed some interest in taking equity in the two Horizon projects. 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 expects a final investment decision in 2019.
National Grid will build 40 km of new 400 kV connection mostly alongside the present line, but including 4 km in a tunnel under the Menai Strait.
China General Nuclear – Bradwell
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.
In connection with the Hinkley Point agreement in October 2015, EDF and CGN agreed to form a 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. CGN is expected to take a 66.5% share and EDF 33.5% in the Bradwell B project, and the two companies will also bring it to a final investment decision.
In September 2016 CGN said that it would submit an application to the ONR for generic design approval for the Hualong One reactor. Bradwell B will comprise two Hualong One units, each with a capacity of 1,150 MW, it said.
Power reactors planned and proposed
||Hinkley Point C-1
||Hinkley Point C-2
||Wylfa Newydd 1
||Wylfa Newydd 2
|China General Nuclear
|China General Nuclear
|Total planned & proposed
||2 x PRISM
||2 x 311
||2 x Candu EC6
||2 x 740
The WNA Reactor Table has two EPRs and two ABWRs as 'planned' (6100 MWe) and nine units (11,800 MWe) 'proposed'.
The PRISM and EC6 options for Sellafield are alternatives for Pu disposition.
The 2015 program 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 the mid-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 expects to apply for US design certification late in 2016, and to apply for GDA in the UK in a similar timeframe.
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 involves a “shared design and development model” under which the company would contribute its SMR conceptual design and then partner with 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.”
Early in 2016 Rolls-Royce said it had submitted a detailed design to the government for a 220 MWe SMR unit (no details yet public). 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 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 150 MWe 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 150 MWe pilot module is envisaged with conventional fuel tubes that runs 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 molten salt reactor design in the SMR competition.
Other participants in the UK's SMR competition include EDF Energy and its Chinese partner CNNC.
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.
Fuel cycle facilities and materials: front end
From the outset, the UK has been self-sufficient in conversion, enrichment, fuel fabrication, reprocessing and waste treatment (see Appendix 1, Nuclear Development in the United Kingdom). 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 is building a 7000 t/yr deconversion plant, or Tails Management Facility, at Capenhurst, with commissioning expected late in 2017p, after cost overruns and delays. It will treat tails from all three European Urenco sites: Capenhurst, Almelo in the Netherlands and Gronau in Germany. Depleted uranium will then be stored in more chemically stable form as U3O8.
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 around 2016. The Thermal Oxide Reprocessing Plant (Thorp) was commissioned in 1994 and, as of early 2010, had treated about 6000 tonnes of used fuel for overseas and domestic customers. Of this, 2300 tonnes was domestic used AGR fuel. A further 6600 tonnes arising to the end of the AGR operating lifetimes will need to be treated or stored, depending on the outcome of a review of used oxide fuel management strategyq. Less than 700 tonnes of fuel from overseas customers remains to be reprocessed. In June 2012 the NDA said that Thorp will operate to 2018, and close after completing its existing reprocessing contracts, including those for the AGR fuel. Its capacity is 600 t/yr. The draft NDA business plan to 2018 says it will continue to reprocess AGR and other oxide fuel from EDF Energy and overseas.
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 plutoniumr. 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 – about half as much again if separated. Three of four options involved using the separated plutonium in MOX fuel, the main question is what to do with the AGR fuel – treat as waste, or reprocess at THORP. 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. The question for the UK is whether it wants to offset this with extra savings and revenues from the potentially expensive return to the full nuclear fuel cycle that would come with a refurbishment of THORP and building a new MOX plant. 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 portal 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.
At the end of 2013 the plutonium stockpile was reported as 123 tonnes, including 23 tonnes foreign-owned (since reduced to 15t by swaps), and on completion of reprocessing operations about 2016 it is expected to be 140 tonnes. The government plans to decide on plutonium use or disposition about then. After agreement with Euratom, in mid-2014 the government agreed to NDA taking ownership of about a tonne of foreign plutonium stored in UK – 800 kg owned by a Swedish utility and 140 kg owned by a German research organisation. In 2013 it had similarly taken over about two tonnes of foreign-owned plutonium.
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.
Most UK radioactive wastes are a legacy of the pioneering development of nuclear power, rather than being normal operational wastes arising from electricity generation – though there is a significant amount of these. Some are from military programs. Until 1982, some low- and intermediate-level wastes were disposed of in deep ocean sites. In 1993, the government accepted an international ban on this.
Solid low-level wastes are 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 wastes 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 wastes is planned.
High-level waste (HLW) arising from reprocessing is vitrified and stored at Sellafields, 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. All HLW is to be stored for 50 years before disposal, to allow cooling.
A consultation on regulations relating to wastes was carried out from March 2010. A Waste Transfer Pricing Methodology consultation document in the 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 a Radioactive Waste Management Directorate (RWMD) to develop plans for a deep geological repository for high- and intermediate-level wastes and evolve into the entity that builds and operates it. The Geological Disposal Facility (GDF) is expected to cost around £12 billion undiscountedt 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 RWM Ltd 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 expects to progress site selection on this basis of volunteered sites in 2017. RWM expects 15 to 20 years to be required to identify and investigate sites, following the two-year solicitation.
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 will 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.
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, which expected the contract value to be about £4.2 billion.
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.
Regulation and safety
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)u. 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.
Public opinion and industry support
In the light of developments since 2006, public opinion in UK has remained positive regarding nuclear power, despite the Fukushima accident. Of more significance is that there is strong political support across all three main parties.
In July 2012 a YouGov survey found that 63% of Britons supported the use of nuclear power, and only 22% opposed building new plants on brownfield sites. Twice as many supported electricity market reform as opposed it (35% and 18% respectively) and interest in global warming was low – 59% compared with 72% in 2008.
A YouGov survey in October 2012 found that 40% of the 1734 people polled felt that the UK government should use more nuclear power than at present, up from 35% in November 2011. Maintaining current levels was preferred by 21%, while 20% felt that there should be less nuclear power than at present (down from 27% in 2011). 54% of men, and only 26% of women, felt that there should be more nuclear. Of women, 23% supported the status quo, 25% called for a reduction in nuclear and 25% were unsure. Apart from nuclear, 72% were in favour of increasing solar provision, 55% in favour of more wind farms, and 45% wanted less coal-fired power.
A UK Energy Research Centre report in October 2013 showed similar proportions of people now supporting (32%) and opposing (29%) the use of nuclear power, compared with 26% (supporting) and 37% (opposing) in 2005. While a similar number of people want to see nuclear continue at current levels or expand it, fewer people now want to see nuclear power phased out or shut down (50% in 2005, 40% in 2013). Concern over nuclear power in Britain has dropped from 58% in 2005 and 54% in 2010 to 47% in 2013 post Fukushima.
A DECC survey of over 2000 people in March 2014 showed that 42% supported nuclear power (up from 38% in Sept 2012) and 20% opposed it (down from 27%). Support for renewables was stronger, and 59% said they would be prepared to have a large-scale renewables development in their area. Concern over energy security and climate change had increased since 2012.
The March 2016 DECC survey (N=2105) showed 38% support for nuclear power and 23% against, with 36% neutral. Those with an income over £50,000 (53%), male (49%), in social grades AB (47%), and aged over 65 (44%) were the most likely to support the use of nuclear energy. Regarding nuclear being a reliable source, 49% agreed and 14% disagreed. There was less strong support for nuclear being affordable (37%), safe (34%) and helpful in tackling climate change (35%). This survey also asked about shale gas fracking, and found that half neither supported nor opposed, mostly due to not knowing enough about it, 31% were opposed and 19% supported.
A YouGov poll of over 2000 people in November 2014 showed 45% support for building new nuclear power capacity, and more than two-thirds of those did so due to concern about UK energy security. Reliability of supply and job creation and investment also rated highly. Of the 20% opposing new reactors, 82% did so due to lack of knowledge regarding waste management, and 39% mentioned concern about public safety (down from 26% in 2012). One-third of respondents said they were aware of how the industry currently deals with waste, but only 21% knew about future plans for waste disposal.
A 2015 survey by the UK's Institution of Mechanical Engineers found that 56% of the public support the country's continued use of nuclear power, compared with just 19% who do not, with 25% unsure. Of those who support nuclear power, 82% said that this is because it will "help keep the lights on," 56% because it would provide jobs, and 54% because it would boost the economy. The main concerns for those opposing nuclear power were that it is too dangerous (77%), too damaging for the environment (76%), while just 27% said that it was because it was too expensive.
In March 2013 the government published a 90-page industrial strategy document entitled The UK's Nuclear Future which sets out the government's "clear expectation that nuclear will play a significant role in the UK energy mix in the future" and outlines the 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 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. The 2015 election result is likely to mean no further subsidies for onshore wind, and greater development of shale gas.
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 now 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." Funding is through the Department of Energy and Climate Change (DECC), whose other functions are being trimmed. "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 follows 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 £2 billion loan guarantee for the Hinkley Point C project, it also 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) is likely to be in Cumbria, as flagship of a new regional collaboration between Cumbria and Sichuan province. It will be run by the National Nuclear Laboratory (NNL) in conjunction with CNNC, and linking with other UK nuclear research centres and universities. NNL said: “The work of the centre will help to optimise the nuclear power generations systems we have operating today, as well as working to develop the reactors and fuel cycles which we will deploy in future and better ways of dealing safely with nuclear waste.”
The UK's R&D programme is covered in more detail in Appendix 1, Nuclear Development in the United Kingdom.
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).
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,"9 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 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 environmental, social and economic impacts of implementing a policy, and includes comparison with reasonable alternatives to the preferred policy.) As the draft NPSs were revised, the government considered it necessary to launch a further consultation on them15. This consultation16 commenced in October 2010 and the government presented the finalised statements to Parliament for ratification in June 2011. (Along with the decision to abolish the Infrastructure Planning Commission – see Note c above – the new coalition government said it would ensure that NPSs are to be ratified by Parliament.) [Back]
f. At the end of June 2006, the Health and Safety Executive (HSE) published an expert report to the Government’s 2006 energy policy review (see Note a above). The report was informed by responses received between March and April 2006 to a discussion document, HSE review of the pre-licensing process for potential new build of nuclear power stations, posted on the HSE website. The HSE's response to The Energy Review and associated documents can be found on the HSE website (www.hse.gov.uk). [Back]
g. Information on the GDA process can be found on the New nuclear power stations section of the HSE website (www.hse.gov.uk). [Back]
h. The government's proposals for the management and disposal of nuclear wastes arising from future new plants18 were published in February 2008 alongside the Energy Bill 2008, which became the Energy Act 2008 when it received Royal Assent in November 2008. [Back]
i. A consultation on regulations relating to FDPs, including measures to verify and define the content of an FDP, was carried out between March and June 2010.19 A further FDP consultation document in the light of this was issued by the government in December 2010.20. Running alongside these consultations have been related consultations on determining a price for the transfer to government of new-build higher-activity waste and its disposal21. [Back]
j. Soon after the UK Low Carbon Transition Plan white paper was published, the government set out its policy to "develop a more coherent global strategy to harness peaceful nuclear power, and to establish the conditions where we can consider a world free of nuclear weapons" in a document titled The Road to 2010: Addressing the nuclear question in the twenty first century (see Reference 8 below). [Back]
k. In October 2008, Malcolm Wicks MP, the then Special Representative on International Energy Issues, was asked to carry out an independent review of international energy security and how developments internationally were likely to affect the UK’s energy security in the coming decades. In his August 2009 report, Energy Security: A national challenge in a changing world25, he stated: "A range between, say, 35-40 per cent of electricity from nuclear could be a sensible aspiration, beyond 2030." In its response to Wicks' report25, the government said it considered it unnecessary to set a target or 'aspiration'. However, the government reiterated the statement made in the Draft National Policy Statement for Nuclear Power Generation referring to new capacity required by 2025: "New nuclear power should be free to contribute as much as possible towards meeting the need for 25 GW of new non-renewable capacity."26 (The 25 GW figure is based on the assumption that 60 GWe of net new capacity is required by 2025, of which 35 GWe could come from renewables, and the remaining 25 GWe coming from conventional generation capacity.) [Back]
l. The 2002 white paper, Managing the Nuclear Legacy – a Strategy for Action27, posed the question: “Is the creation of the Liabilities Management Authority a backdoor route to more nuclear power?” (At the time, the ‘Liabilities Management Authority’ was the name given then to the organization that was to become the Nuclear Decommissioning Authority.) To this, the answer given was: “No. There is no direct link between the creation of the Liabilities Management Authority and any future proposals for new nuclear capacity. The LMA will focus on dealing with the consequences of the past.” Furthermore, the Energy Act 2004 states that the principal function of the Nuclear Decommissioning Authority is decommissioning (as well as operation of installations pending their decommissioning). [Back]
m. The Horizon Nuclear Power Horizon Nuclear Power website (www.horizonnuclearpower.com) contains information on the joint venture's sites at Wylfa and Oldbury. [Back]
n. British Energy Group delisted from the London Stock Exchange in February 2009 following its acquisition by EDF and has been integrated into the EDF Energy subsidiary. In addition to its plans at Hinkley Point and Sizewell, EDF Energy has grid connection agreements for Bradwell, Dungeness, and Heysham – about 1650 MWe each. However, in 2012 EDF cancelled the agreement for Heysham grid connection.
Under an agreement with the UK government, if both Hinkley Point and Sizewell are included in the Nuclear National Policy Statement and planning consent is obtained for two EPR units at Sizewell, then the potential development land at Bradwell – consisting of land already owned by British Energy (prior to its acquisition by EDF) and land acquired from the Nuclear Decommissioning Authority at auction – will have to be sold. It is therefore unlikely that EDF Energy will build a new nuclear plant at Bradwell. In 2015 China General Nuclear Power Group (CGN) said it intended to apply in 2016 for GDA for the 1150 MWe Hualong One reactor design, with a view to building it at Bradwell.
One of the conditions imposed by the European Commission regarding the acquisition of British Energy by EDF is that EDF is required to dispose of potential development land at either Dungeness or Heysham30. Expressions of interest were invited in May 2009 but no agreement has been reached to date. However, since Dungeness is unlikely to be included in the National Nuclear Policy Statement (see section on Strategic siting assessment), new nuclear deployment at Dungeness is highly unlikely.
As noted in the paragraph above on Dungeness, EDF is required to dispose of potential development land at either Dungeness or Heysham, and expressions of interest were invited in May 2009. Both EDF and Iberdrola sent letters of support for the nomination of Heysham to be included as a suitable site within the Nuclear National Policy Statement. Whereas EDF Energy estimates that 2022 is a feasible early deployment date for commissioning of a new unit, Iberdrola considers 2019/2020 possible, with potentially an additional unit following two years later.
o. When the Nuclear Decommissioning Authority (NDA) took ownership of the Springfields site on 1 April 2005, BNFL subsidiary Westinghouse continued with the management and operation (M&O) of the site through its Uranium Asset Management Ltd (UAM) business. This arrangement continued with the sale of Westinghouse to Toshiba. The M&O contract expired at the end of March 2010 and, from April 2010, Westinghouse leased the site on a long-term basis from the NDA. Responsibility for the commercial fuel manufacturing business and the workforce was transferred to Westinghouse. At the same time, UAM was replaced by a 60:40 Toshiba-Westinghouse joint venture, Advance Uranium Asset Management Ltd. [Back]
p. Tails from Capenhurst have been sent to Tenex in Russia since the mid-1990s for re-enrichment. The product at about 0.7% U-235 was returned to Urenco, the tails from that process remaining in Russia, and are considered a resource for future fast reactors there. This arrangement concluded at the end of 2009. [Back]
q. Earlier, it had been planned to operate Thorp until 2011 to meet contractual commitments for AGR and overseas LWR fuel. However, following the April 2005 feed clarification cell event (see section on Sellafield in Appendix 1, Nuclear Development in the United Kingdom) and a subsequent period offline, Thorp has since been operating on reduced capacity due to constraints over evaporator capacity. A review of the strategy for the management of used oxide fuel is underway31, the outcome of which will affect the projected closure date for Thorp. [Back]
r. The default position, as outlined in the Nuclear Decommissioning Authority (NDA) document NDA Plutonium Topic Strategy – Credible Options Summary32, is as follows: "Plutonium – of which 100 tonnes is located at Sellafield and two tonnes at Dounreay – is treated as a zero value asset. The default plan is to store the material until 2070 at Dounreay and until 2120 at Sellafield."
In May 2010, a plutonium storage facility was completed after five years construction. It is the Sellafield Product and Residues Store, with 100-year design life, and all plutonium and plutonium residues at Sellafield will eventually be consolidated there. [Back]
s. By mid-2009, the Sellafield vitrification plant had produced its 5000th canister of vitrified high-level waste, representing 3000 m3 of liquor reduced to 750 m3 of glass. The plant fills about 400 canisters per year, each about 1.2m high. Some 1850 canisters of vitrified waste will be returned to overseas customers from 2010 under the Vitrified Residue Returns (VRR) program. This will take about ten years to complete. [Back]
t. The government plans for waste from new nuclear build to be disposed of alongside NDA-owned waste in the planned Geological Disposal Facility (GDF). The NDA estimates that the total undiscounted cost of the GDF will come to £11,790 million. Of this, the NDA estimates that its share of the GDF would come to £10,493 million (undiscounted). A further £2 billion undiscounted would be required if existing stocks of separated plutonium and uranium were required to be disposed of33. Disposal costs for waste arising from new nuclear plants are expected to be borne by the waste producers.
More detailed figures on the total cost of the planned GDF are given in the Department of Energy & Climate Change's December 2010 Consultation on an updated Waste Transfer Pricing Methodology for the disposal of higher activity waste from new nuclear power stations (see Reference 21 below). This quotes NDA estimates of the total fixed costs of the GDF as £4401 million and total variable costs for legacy and committed waste of £7751.6 million. The consultation document estimates that the total variable costs for the disposal of new build waste (based on a "generic" 1350 MWe PWR) would be £217.2 million per reactor. Operators of new plants would also contribute towards the fixed costs of the GDF. The consultation document estimates that this contribution towards the fixed costs of the GDF would come to £132.9 million per reactor including a financing charge. (Costs are given in September 2008 money values.) [Back]
u. The UK's Health and Safety Executive (HSE) comprises the Office for NUclear Regulation (ONR) www.hse.gov.uk/nuclear – formerly the Nuclear Installations Inspectorate (NII), the Ofﬁce for Civil Nuclear Security (OCNS) and the UK Safeguards Office (UKSO). The ONR is the nuclear safety regulator for the civil and defence related nuclear sites in the UK. The OCNS is the security regulator for the UK’s civil nuclear industry, including both on site and the security of sensitive nuclear material in transit. The UKSO oversees the application of international safeguards measures in the UK.
The OCNS and the UKSO formerly came under the Department of Trade and Industry (DTI) but in April 2007, the security activities of the OCNS and operational safeguards work of UKSO transferred from the DTI to the HSE. At that time, the Nuclear Safety Directorate became the Nuclear Directorate, which disappeared in 2011 when ONR was created.
In addition, the Radioactive Materials Transport Team (RMTT), in the Dangerous Goods Division of the Department for Transport (DfT), is the regulator for the safety of the transport of radioactive material (including nuclear material) by road and rail. The Transport Security and Contingencies Directorate (TRANSEC) of the DfT is the regulator for the security of the transport of non-nuclear radioactive material by road and rail. [Back]
1. Energy white paper, Our energy future – creating a low carbon economy, Cm 5761, Department of Trade and Industry (February 2003) [Back]
2. The Energy Challenge, Energy Review Report 2006, Cm 6887, Department of Trade and Industry (July 2006) [Back]
3. Greenpeace Ltd., R (on the application of) v Secretary of State for Trade and Industry,  EWHC 311 (Admin) (15 February 2007) [Back]
4. Meeting the Energy Challenge, A White Paper on Energy, Cm 7124, Department of Trade and Industry (May 2007) [Back]
5. The Future of Nuclear Power – the role of nuclear power in a low carbon UK economy, Consultation Document, Department of Trade and Industry (May 2007), published on The future of nuclear power: the role of nuclear power in a low carbon UK economy consultation website [Back]
6. Meeting the Energy Challenge – A White Paper on Nuclear Power, Cm 7296, Department for Business, Enterprise & Regulatory Reform (January 2008), published on the Nuclear white paper 2008: 'Meeting the energy challenge' website [Back]
7. See the Department of Energy & Climate Change website on the Climate Change Act 2008 [Back]
8. The Road to 2010: Addressing the nuclear question in the twenty first century, Cm 7675, Cabinet Office (July 2009) [Back]
9. Energy Policy: An Overview, The Scottish Government (September 2008) [Back]
10. Major infrastructure stays on fast-track as planning quango closes, Department of Communities and Local Government news release (29 June 2010) [Back]
11. Towards a Nuclear National Policy Statement: Consultation on the Strategic Siting Assessment Process and Siting Criteria for New Nuclear Power Stations in the UK, Department for Business, Enterprise & Regulatory Reform (July 2008) [Back]
12. Towards a Nuclear National Policy Statement: Government response to consultations on the Strategic Siting Assessment process and siting criteria for new nuclear power stations in the UK; and to the study on the potential environmental and sustainability effects of applying the criteria, Office for Nuclear Development, Department of Energy & Climate Change, URN 09/581 (January 2009) [Back]
13. A consideration of alternative sites to those nominated as part of the Government’s Strategic Siting Assessment process for new nuclear power stations, Prepared by Atkins for the Department of Energy & Climate Change (November 2009) [Back]
14. Consultation on draft National Policy Statements for Energy Infrastructure, Department of Energy & Climate Change (November 2009); Draft National Policy Statement for Nuclear Power Generation (EN-6), Presented to Parliament pursuant to section 5(9b) of the Planning Act 2008, Department of Energy & Climate Change (November 2009) [Back]
15. Consultation on draft national policy statements for energy, Department of Energy & Climate Change press release (15 July 2010) [Back]
16. Consultation on revised draft National Policy Statements for Energy Infrastructure, Planning for new energy infrastructure, Department of Energy & Climate Change (October 2010), available on the website for the Consultation on the revised draft National Policy Statements for Energy Infrastructure on the Department of Energy & Climate Change website (www.decc.gov.uk) [Back]
18. The Consultation on Funded Decommissioning Programme Guidance for New Nuclear Power Stations, Department for Business, Enterprise & Regulatory Reform (February 2008) and The Government Response to the Consultation on Funded Decommissioning Programme Guidance for New Nuclear Power Stations, Office for Nuclear Development, Department for Business, Enterprise & Regulatory Reform (September 2008) are available on the website for the Consultation on funded decommissioning programme guidance for new nuclear power stations [Back]
19. Consultation on The Financing of Nuclear Decommissioning and Waste Handling Regulations, Department of Energy & Climate Change (March 2010), available on the website for the Consultation on funded decommissioning programme guidance for new nuclear power stations on the Department of Energy & Climate Change website (www.decc.gov.uk) [Back]
20. Consultation on revised Funded Decommissioning Programme Guidance for New Nuclear Power Stations, Department of Energy & Climate Change (December 2010), available on the website for the Consultation on revised Funded Decommissioning Programme Guidance for new nuclear power stations on the Department of Energy & Climate Change website (www.decc.gov.uk) [Back]
21. Consultation on a Methodology to Determine a Fixed Unit Price for Waste Disposal and Updated Cost Estimates for Nuclear Decommissioning, Waste Management and Waste Disposal, Department of Energy & Climate Change (March 2010), available on the website for the Consultation on a methodology for determining a Fixed Unit Price for waste disposal and updated cost estimates for nuclear decommissioning, waste management and waste disposal on the Department of Energy & Climate Change website (www.decc.gov.uk).
Consultation on an updated Waste Transfer Pricing Methodology for the disposal of higher activity waste from new nuclear power stations, Department of Energy & Climate Change (December 2010), available on the website for the Consultation on an updated Waste Transfer Pricing Methodology for the disposal of higher activity waste from new nuclear power stations on the Department of Energy & Climate Change website (www.decc.gov.uk). [Back]
22. The Energy Challenge, Energy Review Report 2006, Cm 6887, Department of Trade and Industry (July 2006) [Back]
23. The UK Low Carbon Transition Plan: National strategy for climate and energy, HM Government (July 2009) is published on The UK Low Carbon Transition Plan website on the Department of Energy & Climate Change website (www.decc.gov.uk) [Back]
24. The Coalition: our programme for government, HM Government (May 2010) [Back]
25. The August 2009 report by Malcolm Wicks, Energy Security: A national challenge in a changing world and the Government Response to Malcolm Wicks’s Review of International Energy Security, ‘Energy Security: A national challenge in a changing world’, Department of Energy & Climate Change (April 2010), are available on the Energy Security: A national challenge in a changing world website on the Department of Energy & Climate Change website (www.decc.gov.uk) [Back]
26. Draft National Policy Statement for Nuclear Power Generation (EN-6), Presented to Parliament pursuant to section 5(9b) of the Planning Act 2008, Department of Energy & Climate Change (November 2009) [Back]
27. Managing the Nuclear Legacy – A strategy for action, Department for Trade and Industry (July 2002) [Back]
28. Winning bidders in NDA land auction announced, Nuclear Decommissioning Authority news release (29 April 2009) [Back]
29. GDF Suez, Iberdrola And Scottish And Southern Energy To Acquire Site From Nuclear Decommissioning Authority, ScottishPower press release (28 October 2009); Sellafield land sale agreed, Nuclear Decommissioning Authority news release (28 October 2009); NuGen news release (2 December 2014). [Back]
30. Case No COMP/M.5224 - EDF / BRITISH ENERGY, Eur-Lex document number 32008M5224, European Commission (22 December 2008) [Back]
31. Oxide Fuel Strategy, Nuclear Decommissioning Authority news release (16 March 2010) and Oxide Fuel Topic Strategy discussion paper, Nuclear Decommissioning Authority (March 2010) [Back]
32. NDA Plutonium Topic Strategy – Credible Options Summary, Nuclear Decommissioning Authority (30 January 2009) [Back]
33. Geological Disposal: Steps towards implementation, NDA Report no. NDA/RWMD/013, Nuclear Decommissioning Authority (March 2010) [Back]
34. Implementation of changes to the Paris and Brussels Conventions on nuclear third party liability: a public consultation, Department of Energy & Climate Change (January 2011), available on the website for Implementation of changes to the Paris and Brussels Conventions on nuclear third party liability: a public consultation on the Department of Energy & Climate Change website (www.decc.gov.uk) [Back]
NDA, January 2014: Progress-on-approaches-to-the-management-of-separated-plutonium-position-paper-January-2014.pdf