FRANCE NUCLEAR POWER - 2017
WNA - Nuclear Power in France
- France derives about 75% of its electricity from nuclear energy, due to a long-standing policy based on energy security. This share may be reduced to 50% by 2025.
- France is the world's largest net exporter of electricity due to its very low cost of generation, and gains over €3 billion per year from this.
- The country has been very active in developing nuclear technology. Reactors and especially fuel products and services have been a significant export.
- About 17% of France's electricity is from recycled nuclear fuel.
In 2015 electricity production was 568 TWh (gross), and of this nuclear provided 437 TWh (77%), hydro 59 TWh, coal and gas 32 TWh, and solar and wind 29 TWh. After net exports of 64 TWh, total electricity consumption came to 422 TWh, about 6,300 kWh per capita on average. Installed capacity at the end of 2015 was 129 GWe.
Over the last decade France has exported up to 70 TWh net each year and Electricité de France (EDF) expects net exports to continue at 55-70 TWh/yr. In 2014 they were principally to Italy, the UK, Switzerland, Belgium, Spain, and Germany.
France has 58 nuclear reactors operated by EDF, with a total capacity of 63.1 GWe.
France's present electricity generation mix is a result of the French government deciding in 1974, just after the first oil shock, to expand rapidly the country's nuclear power capacity, using Westinghouse technology. This decision was taken in the context of France having substantial heavy engineering expertise but few known indigenous energy resources*. Nuclear energy, with the fuel cost being a relatively small part of the overall cost, made good sense in minimising imports and achieving greater energy security.
* In 2014 the US Energy Information Administration put French shale gas resources at 5094 billion m3, though recovery of this was prohibited.
As a result of the 1974 decision, France now claims a substantial level of energy independence and almost the lowest cost electricity in Europe. It also has an extremely low level of carbon dioxide emissions per capita from electricity generation, since over 90% of its electricity is nuclear or hydro.
In mid-2010 a regular energy review of France by the International Energy Agency urged the country increasingly to take a strategic role as provider of low-cost, low-carbon base-load power for the whole of Europe rather than to concentrate on the energy independence which had driven policy since 1973.
The low cost of French nuclear power generation is indicated by the national energy regulator (CRE) setting the price at which EdF’s electricity is sold to competing distributors. In 2014 the rate is €42/MWh, but CRE proposed an increase to €44 in 2015, €46 in 2016 and €48 in 2017 to allow EdF to recover costs of plant upgrades, which it put at €55 billion to extend all 58 reactor lifetimes by ten years. In November 2014 the government froze the price at €42 to mid-2015. This Arenh re-sale price has represented a long-term floor price for EdF’s power, and is nominally based on the cost of production. The industrial group Uniden said that the proposed 2015 wholesale price of €44/MWh would be €14 higher than Germany’s.
French retail prices, without major effects from feed-in tariffs for wind and solar, remain very low. In 2013 French prices for medium-size industrials were about 90% of EU-27 average, and those for medium-size households (at less than 8 c/kWh) were less than half of EU-27 average.
Recent energy policy
In 1999 a parliamentary debate reaffirmed three main planks of French energy policy: security of supply (France imports more than half its energy), respect for the environment (especially re greenhouse gases) and proper attention to radioactive waste management. It was noted that natural gas had no economic advantage over nuclear for base-load power, and its prices were very volatile. It was accepted that there was no way renewables and energy conservation measures could replace nuclear energy in the foreseeable future.
Early in 2003 France's first national energy debate was announced, in response to a "strong demand from the French people", 70% of whom had identified themselves as being poorly informed on energy questions. A poll had shown that 67% of people thought that environmental protection was the single most important energy policy goal. (However, 58% thought that nuclear power caused climate change while only 46% thought that coal burning did so). The debate was to prepare the way for defining the energy mix for the next 30 years in the context of sustainable development at a European and at a global level.
In 2005 a law established guidelines for energy policy and security. The role of nuclear power was central to this, along with specific decisions concerning the European Pressurised Water Reactor (EPR), notably to build an initial unit so as to be able to decide by 2015 on building a series of about 40 of them. It also set out research policy for developing innovative energy technologies consistent with reducing carbon dioxide emissions and it defined the role of renewable energies in the production of electricity, in thermal uses and transport.Early in 2008 a Presidential decree established a top-level Nuclear Policy Council (Conseil Politique Nucleaire – CPN), underlining the importance of nuclear technologies to France in terms of economic strength, notably power supply. It is chaired by the President and includes the prime minister as well as the cabinet secretaries in charge of energy, foreign affairs, economy, industry, foreign trade, research and finance. The head of the Atomic Energy Commission (CEA), the secretary general of national defence and the military chief of staff are on the council. (See section below on Nuclear technology exports for further information.)
Following the election of President Francois Hollande in 2012 with his policy to reduce the proportion of nuclear power in the energy mix, a new wide 'national debate on energy transition' was called, which ran eight months to July 2013. The Ministry for Ecology Sustainable Development and Energy counted 170,000 people taking part in 1000 regional debates, and received 1200 submissions over the Internet. A report published in September 2013 by OPECST, a scientific commission of senators and MPs from the upper and lower houses of Parliament said France risks being exposed to a power price shock if it pursues a speedy reduction of nuclear power and there is insufficient replacement through renewable energy and energy efficiency measures.
In October 2014 the Energy Transition for Green Growth bill was passed by the National Assembly and so went on to the Senate. This set a target of 50% for nuclear contribution to electricity supply by 2025, with a nuclear power capacity cap at the present level of 63.2 GWe, meaning that EDF would have to shut at least 1,650 GW of nuclear capacity when its Flamanville 3 EPR starts commercial operation. The bill also sets long-term targets to reduce greenhouse gas emissions by 40% by 2030 compared with 1990 levels, and by 75% by 2050; to halve final energy consumption by 2050 compared with 2012 levels; to reduce fossil fuel consumption by 30% by 2030 relative to 2012; and to increase the share of renewables in final energy consumption to 32% by 2030. The Senate early in 2015 amended the bill to remove the nuclear cap, but this was not accepted in the lower house. The National Assembly approved the bill including 970 amendments in July 2015, but with the 63.2 GWe nuclear cap and only 50% nuclear supply by 2025. This means that an older plant will need to be closed to allow Flamanville 3 to come online in 2018 (or later). In October 2016 the government postponed until after the 2017 presidential and National Assembly elections any decision on which, if any, reactors would close in order to reduce the nuclear share to 50%. The new environment minister in May 2017 said he was committed to the Energy Transition policy.
The final Green Growth bill also sets long-term targets for France's carbon tax. From €14.50 per tonne CO2, it would increase to €22 in 2016, then to €56 in 2020, rising to €100/tCO2 in 2030. In May 2016 the environment and energy minister announced legislation for a carbon price floor from 2017, so that power producers pay a minimum of €30/t CO2 on fossil fuels used for generation. This proposal was revived following the elections in 2017, and was expected to add €5/MWh to wholesale prices, with EdF moving to close its coal-fired plants by 2022.
In March 2016 Areva, EdF and CEA announced the formation of the tripartite French Nuclear Platform (PFN) to improve the joint effectiveness of the three bodies and devise a shared vision of a medium- and long-term goal for the industry, supporting the Nuclear Policy Council (CPN). Its initial agenda will include the review of technological options for the EPR NM reactor design and the coordination of positions on regulatory changes, notably regarding safety requirements and objectives. The PFN will also address the future of reprocessing in France and elsewhere, the CIGEO deep geological repository project, the development of dismantling technologies for decommissioned reactors, and R&D work on fourth-generation reactor designs.
In 2015 RTE started work on a new 1200 MWe HVDC connection to Turin in Italy, costing about €1 billion, which may have relevance to the new energy policy and domestic supply cap. It will be the longest subterranean high-voltage power line when it goes into service in 2019. In 2014 Italy imported 19 TWh; this HVDC line will add capacity for 10.5 TWh more.
Areva and EdF
Areva* was created in 2001 by merging Framatome (now Areva NP), the nuclear business of Siemens, Cogema (now Areva NC), and Technicatome (now Areva TA – the propulsion and research reactor unit). Areva was the only company with a presence in every part of the nuclear fuel cycle. In 2007 it bought the Canadian mining company Uramin for $2.5 billion, and in 2011 wrote off this investment after concluding that its uranium deposits were of negligible value. Areva’s fortunes have declined from 2011, with reactor projects in Finland (Olkiluoto 3) and France (Flamanville 3) contributing.
* The name has geographical allusions, it is not an acronym.
In February 2011 the Nuclear Policy Council (Conseil Politique Nucleaire – CPN) addressed the rivalry between Areva (almost 90% government-owned) and Electricité de France (EdF, 85% government-owned). This was presumed to have been a factor in losing an important Middle Eastern nuclear power plant contract 14 months earlier. Areva was the world's largest nuclear company, EdF is the largest nuclear electric utility, and set to build new Areva EPR plants in France, UK, China and possibly the USA. However, US prospects have since withered.
The Council directed Areva and EdF to put in place a technical and commercial agreement by mid-year for a strategic partnership to improve the design for the European Pressurized Reactor (EPR) and to work together more closely on several fronts domestically. This agreement was signed in July 2011, covering optimization of Areva's 1,650 MWe EPR design that EdF is building at Flamanville 3, improving maintenance and operation of EdF's reactor fleet, and nuclear fuel cycle developments, including new fuels and final disposal of radwaste. EdF appeared to have the leading role in this, and particularly in export efforts. CPN told Areva to spin off its uranium mining into a subsidiary company "as a preliminary step to study strategic and financial scenarios to ensure its development." In 2015 there are moves for EdF to take over part of Areva, following its losses.
In March 2015, Areva announced a two-part strategy to refocus on its core business of nuclear power and return to competitiveness, aiming to make savings of about €1 billion over the next few years after a record loss in 2014 of €4.83 billion. Areva had five operational business units:
- Reactors and services, with engineering and projects (Areva NP).
- Front end.
- Back end.
- Renewable energies.
Areva SA was 86.52% owned by the government through three entities including CEA (54.37%), Banque publique d'investissement (3.32%), and Agence des participations de l'État (28.83%). Government-owned EDF held 2.24%, and Kuwait Investment Authority 4.82% (bought for €600 million in December 2010). The balance was held by public investors and employees. (Siemens had a 34% interest in Areva NP until March 2011.) In February 2017 Areva SA shareholders approved a reserved capital increase of €2 billion from the French state in order to fund the completion of Olkiluoto 3.* This advance was converted into capital in July 2017, so that the state owns about 92% of Areva SA. Also, completion of the sale to EDF would depend on a "favourable outcome" from tests on the Flamanville reactor pressure vessel metallurgy. The ASN provisionally cleared this in June 2017. In July 2017 Areva said that the French state held 67.05% directly and 25.17% through the CEA, total 92.22%. In light of Areva SA's loss of control of NewCo (now Orano – see below) and the sale of New NP (now Framatome – see below), in mid-July 2017 the French state filed a takeover bid at €4.50 each for the shares not held directly or indirectly. This included the Kuwait equity, sold for €83 million. It will then delist the company.
* At the end of 2016 the Areva-Siemens consortium was claiming €3.5 billion from TVO for compensation for damages, while TVO’s claim against the consortium was about €2.3 billion. Areva does not expect a final decision before the end of 2017.
The financial losses, including €2 billion in 2015, reinforced moves for EDF to take over Areva. Areva said: “Half of this loss of €2 billion is due to additional provisions for Olkiluoto 3 and half to provisions for restructuring and impairment related to market conditions." Areva anticipated a loss of between €1.5 billion and €2 billion from company operations in 2016 due to “the impact of the remedial measures taken, by expenses to be incurred on the large projects, and by the unfavourable change in working capital requirements."
Since July 2016, Areva has been organised into two separate operating entities, NewCo (now Orano) and Areva NP (now Framatome), each with an executive committee.
Framatome (formerly New NP) and Areva NP
In July 2015 EDF agreed to take a stake of between 51% and 75% in Areva SA's reactor and services unit, New NP*. EDF announced that the transaction was completed on 2 January 2018, with the French utility acquiring a 75.5% stake. On 4 January 2018, Areva announced that New NP had been renamed Framatome. Framatome is the name of a former French reactor vendor from which Areva was originally created.
* New NP (now Framatome) was formed from the spin-off of Areva's reactor operations.
Other shareholders in Framatome are 19.5% MHI, 5% Assystem, following the signing of equity agreements in July 2017. During negotiations MHI made it clear that it would share Atmea technology only with EDF and not with any other partners in New NP.
Framatome holds all existing assets of Areva related to the design and manufacture of nuclear reactors and equipment, fuel design and supply, and services to existing reactors. Framatome excludes all assets, liabilities and staff related to the completion of the Olkiluoto 3 EPR in Finland, which remain with Areva NP, along with some Le Creusot Forge potential liabilities (especially those related to Flamanville 3). Framatome will no longer be tied to a particular reactor design, and long-term operation of all types of reactor will be a major service objective. Annual revenue will be about €3.5 billion.
The six Framatome business units will be: large projects, installed base services, fuel design, component manufacturing, I&C (consolidated), and engineering design.
In March 2017 EDF announced a €4 billion share issue, of which the French state would take up €3 billion, reducing its stake in EDF from 85.8% to 83%. The offering of new shares to existing shareholders was oversubscribed by 22%, EDF said. The rights issue is mostly to finance its developments to 2020.
In the course of the sale of New NP to EDF, it was intended that 15% of New NP's capital would be transferred from Areva SA to the new fuel cycle company – Areva NewCo (Orano) – so that it might maintain a “strategic share” in the reactor business. However, EDF in July 2017 acknowledged discussions between it and Areva “on the conditions for the implementation of the European Commission decision requiring Areva to fully exit New NP at the latest by the end of [the] Areva restructuring plan, planned in 2019."
In May 2017 EDF announced the creation of the Edvance engineering joint venture with Areva NP, to design and build nuclear islands and control systems for new reactors globally. EDF will hold 80%, Areva NP 20%. This arises from the July 2015 agreement to establish a dedicated company for the design, project management and marketing of new reactors (then called NICE). The aim of this company would be to improve the preparation and management of projects, as well as the export offering of the French nuclear industry. EDF said the new company would form part of an "integrated generator/supplier model, which has been tried and tested in several countries."
Orano (formerly New Areva Holding Co.)
As well as plans to sell most of Areva NP to EDF, in June 2016 Areva announced corporate restructuring through the creation of a new company ("NewCo") focused on the nuclear fuel cycle. The entity, originally named New Areva Holding Co., but renamed Orano on 23 January 2018, was initially a wholly-owned subsidiary of Areva SA set up in July 2016. It combines the Areva Mines, Areva NC, Areva Projects and Areva Business Support entities and their respective subsidiaries.
In November 2016 the Areva shareholders approved the transfer of fuel cycle operations and part of Areva SA’s debt to Orano with a €3 billion capital increase which reduces Areva SA equity to under 40%. In July 2017, €2.5 billion of the Areva recapitalisation from the government approved by the European Commission (EC) was allocated to Orano. Following the transaction and capital injection – both approved by the EC – the French state would hold, either directly or indirectly, at least two-thirds of the new company’s capital, with the remainder held by strategic investors. Areva SA no longer controls it following the capital injection. As noted above, 15% of New NP's capital was intended to be transferred from Areva SA to Orano – so that it could maintain a “strategic share” in the reactor business – though the EC vetoed this and it did not proceed. In January 2017 the EC authorised €1.3 billion rescue aid for Orano from the French state, to be reimbursed by conversion to equity.
In February 2017 Areva announced that Japan Nuclear Fuel Ltd (JNFL) and MHI would each invest €250 million for 5% stakes in Orano, and this was confirmed in March. Areva said that the opportunity remained open for other strategic investors to take equity on the same basis, notably China National Nuclear Corporation (CNNC). Areva has “enjoyed longstanding relations” with both Japanese companies on fuel cycle matters. MHI confirmed that it was also proceeding “toward making a similar minority stake investment in Areva NP.” Orano shareholders approved the capital increase on 3 February, €2.5 billion from the French state and €0.5 billion from JNFL and MHI, the latter amount being held in trust until the transfer to EDF is completed.
After July 2017 the equity in Orano was set to be 5% MHI, 5% JNFL, 34.4% Areva SA, and 55.6% French state, which plans a public offering of its shares at €4.50, the same price as the Areva SA reserved capital increase for the completion of Olkiluoto 3.
Since November 2015 CNNC has been interested in taking 10% or 15% of Orano for up to €2 billion. A memorandum of understanding was signed then “on possible cooperation involving an equity component and an industrial component.”
Areva sees the new fuel cycle company as “refocused on less-risky cash flow generating operations” and thus able to refinance on capital markets and “in a good position to grow.”
Rosatom earlier expressed interest in both companies.
Balance of Areva
Areva TA, the propulsion and research reactor unit, as well as the renewables businesses, was retained by Areva SA. In March 2017 its 83.5% stake in Areva TA was sold to a consortium comprising the French government's Agency of State Holdings, the CEA, and French naval defence group DCNS. EDF maintains a 9% stake in Areva TA.
France's nuclear power program cost some FF 400 billion in 1993 currency*, excluding interest during construction. Half of this was self-financed by EdF, 8% (FF 32 billion) was invested by the state but discounted in 1981, and 42% (FF 168 billion) was financed by commercial loans. In 1988 medium and long-term debt amounted to FF 233 billion, or 1.8 times EdF's sales revenue. However, by the end of 1998 EdF had reduced this to FF 122 billion, about two-thirds of sales revenue (FF 185 billion) and less than three times annual cash flow. Net interest charges had dropped to FF 7.7 billion (4.16% of sales) by 1998.
* 6.56 FF = €1 (Jan 1999)
In 2006 EdF sales revenue was €58.9 billion and debt had fallen to €14.9 billion – 25% of this. EdF early in 2009 estimated that its reactors provided power at EUR 4.6 cents/kWh and the energy regulator CRE put the figure at 4.1 c/kWh. The weighted average of regulated tariffs is EUR 4.3 c/kWh. In 2011 a report commissioned by the prime minister put costs at 4.6 c/kWh, and this was confirmed following review by the national court of auditors, with the comment that it could increase by 0.3c to account for higher back-end costs. Power from the new EPR units is expected to cost about EUR 5.5 to 6.0 c/kWh. In 2014 the official auditor, Cour des Comptes, said the cost of nuclear power production had increased 20% between 2010 and 2013.
From being a net electricity importer through most of the 1970s, France has become the world's largest net electricity exporter, with electricity being the fourth largest export. (Next door is Italy, without any operating nuclear power plants. It is Europe's largest importer of electricity, most coming ultimately from France.) The UK has also become a major customer for French electricity.
France's nuclear reactors comprise 90% of EdF's capacity and hence are used in load-following mode (see section below) and are even sometimes closed over weekends, so their capacity factor is low by world standards, at 77.3%. However, availability is almost 84% and increasing.
The first nine power reactors were gas-cooled UNGG (Uranium Naturel Graphite Gaz) units, as championed by the Atomic Energy Authority (CEA). They were similar to the British Magnox units but developed independently. (One UNGG unit was built in Spain.) EdF then chose pressurised water reactor (PWR) types, supported by new enrichment capacity and fully indigenous manufacturing. EdF plans for some BWR units did not proceed.
All French units (the first two derived from US Westinghouse types) are now PWRs of three standard types designed by Framatome (now AREVA): three-loop 900 MWe (34), four-loop 1300 MWe P4 type (20) and finally four-loop 1450 MWe N4 type (4). This is a higher degree of standardisation than anywhere else in the world. (There have been two fast reactors – Phenix which ran for over 30 years, and Super Phenix, which was commissioned but then closed for political reasons.) French development of the four-loop 1300 MWe design flowed back to later US plants, and the 1450 MWe N4 design evolved from it.
French nuclear power reactors
|Class||Reactor||MWe net, each||Commercial operation|
|900 MWe||Blayais 1-4||
12/81, 2/83, 11/83, 10/83
|Chinon B 1-4||
2/84, 8/84, 3/87, 4/88
4/84, 4/85, 9/84, 2/85
9/80, 2/81, 5/81, 11/81
|Gravelines B 1-4||
11/80, 12/80, 6/81, 10/81
|Gravelines C 5-6||
|Saint-Laurent B 1-2||
12/80, 12/80, 5/81, 11/81
|1300 MWe||Belleville 1 & 2||
4/87, 2/88, 2/91, 1/92
|Nogent s/Seine 1-2||
12/85, 12/85, 2/86, 6/86
|N4 – 1450 MWe||Chooz B 1-2||
Differences in net power among almost identical reactors is usually due to differences in cold sources for cooling
Framatome in conjunction with Siemens in Germany then developed the European Pressurised Water Reactor (EPR), based on the French N4 and the German Konvoi types, to meet the European Utility Requirements and also the US EPRI Utility Requirements. This was confirmed in 1995 as the new standard design for France and it received French design approval in 2004. Areva NP sold four EPRs to 2007 – to Finland, EdF and China (2) – and has sold none since, though there are plans to build some in the UK.
Areva NP is working with EdF on a ‘new model’ EPR – EPR NM – with simplified construction and significant cost reduction. The basic design was 30% complete by March 2016, to be completed in 2020, and EdF said that it, not the complex EPR being built at Flamanville, will be the model that replaces the French fleet from the late 2020s.
There have been two significant fast breeder reactors in France. Near Marcoule is the 233 MWe Phenix reactor, which started operation in 1974 and was jointly owned by CEA and EdF. It was shut down for modification 1998-2003, returned at 140 MWe for six years, and ceased power generation in March 2009, though it continued in test operation and to maintain research programs by CEA until October 2009.
A second unit was Super-Phenix of 1200 MWe, which started up in 1996 but was closed down for political reasons at the end of 1998 and is now being decommissioned. The operation of Phenix is fundamental to France's research on waste disposal, particularly transmutation of actinides. See further information in R&D section below.
All but four of EdF's nuclear power plants (14 reactors) are inland, and require fresh water for cooling. Eleven of the 15 inland plants (32 reactors) have cooling towers, using evaporative cooling, the others use simply river or lake water directly. With regulatory constraints on the temperature increase in receiving waters, this means that in very hot summers generation output may be limited.
Following the Fukushima accident in 2011 the IRSN undertook a 6-month review of reactor safety. Its report, released in conjunction with ASN, proposed a new set of 'hard core' safety requirements to ensure the protection of vital safety-critical structures and equipment to ensure that vital functions can be maintained in the face of events beyond the design basis of the plant, such as earthquakes, fires, or the prolonged loss of power or emergency cooling.
Licence renewal and uprates
The average age of EdF’s fleet of 58 reactors was 30 years in 2015.
The 900 MWe reactors all had their lifetimes extended by ten years in 2002, after their second 10-yearly review. Most started up late 1970s to early 1980s, and they are reviewed together in a process that takes four months at each unit. A review of the 1300 MWe class followed and in October 2006 the regulatory authority cleared all 20 units for an extra ten years' operation conditional upon minor modifications at their 20-year outages over 2005-14. The third 10-year inspections of the 900 MWe series began in 2009 and run to 2020. The 3rd ten-year inspections of the 1300 MWe series run from 2015 to 2024.
In July 2009 the Nuclear Safety Authority (ASN) approved EdF's safety case for 40-year operation of the 900 MWe units, based on generic assessment of the 34 reactors. Each individual unit will now be subject to inspection during their 30-year outage, starting with Tricastin 1. In December 2010 ASN extended its licence by ten years, to 2020, and in February 2015 it did the same for unit 2, to 2021, conditional upon post-Fukushima safety upgrades being brought forward. In 2016 Gravelines B1 was the tenth 900 MW reactor with licence extension to 40 years, joining Bugey 2, 4&5, Fessenheim 1&2, Dampierre 1 and Tricastin 1-3.
In July 2011 ASN approved a ten-year licence extension for Fessenheim 1, the oldest operating reactor (1977 start-up), subject to making its 1.5 m thick basemat more robust and resistant to possible corium assault (increasing its thickness by 0.5 m and increasing the surface area for corium spreading), as well provision for last-resort fuel decay heat removal in the event of losing the external heat exchanger. EdF considered the cost-benefit situation following the outcome of EU stress tests and completed the work in mid-2013. Much the same work on unit 2 will follow, and EdF committed to this in mid-2013. Bugey 2 was approved by ASN for ten-year life extension in July 2012, and Bugey 4 the same in July 2013, subject to similar conditions for minor upgrading. With Tricastin 1, this brings to five the total approved for 40-year operating life.
In July 2010 EdF said that it was assessing the prospect of 60-year lifetimes for all its existing reactors. This would involve replacement of all steam generators (3 in each 900 MWe reactor, 4 in each 1300 MWe unit) and other refurbishment, costing €400-600 million per unit to take them beyond 40 years. EdF has replaced the steam generators at 22 of its 900 MWe units and is currently replacing those at two units per year, and plans to increase this to three units in 2016. In 2011 it ordered 44 steam generators for 11 of the 1300 MWe units, for €1.5 billion, and will proceed also with the other nine.
In 2012 the government announced that both Fessenheim reactors should close by 2017, for political reasons and regardless of safety evaluations. This would require compensation payments to minority owners: Germany's EnBW has 17.5% and Alpiq, Axpo and BKW in Switzerland together hold 15%. In September 2014 a parliamentary report was presented to the National Assembly confirming that there were no technical reasons for closing the plant, and closing it in 2016 would cost the state some €5 billion, including some €4 billion in compensation to EdF. It was currently generating average annual profits of some €200 million and allowing it to continue operating after 2016 until 2040 would result in profits of some €4.7 billion. The report concluded, "Whatever the long-term energy policy followed, it would make sense, fiscally and economically, to retain the benefit of the 'surplus nuclear' by not prematurely closing second generation plants currently in operation." The energy minister said that in the light of recent investment in Fessenheim, maybe some other units would close instead. Then in November 2015 the government agreed to EdF’s proposal to close Fessenheim only after Flamanville 3 was fully commissioned, about 2019. In August 2016 the government agreed to pay EdF compensation for the closure, in two instalments, the precise amounts depending on wholesale electricity prices through to 2041. In January 2017 EdF agreed to the compensation protocol which would be signed when EdF formally requests shutdown. The initial fixed portion of about €490 million would cover the anticipated costs associated with the closure of Fessenheim. This would include retraining of staff, decommissioning the plant, the basic nuclear facility tax and post-operational costs. Some 20% of this initial payment would be made in 2019, with the remainder due in 2021. Further variable payments would be made to reflect EDF's operating income shortfall up to 2041 due to the closure.
In April 2017 the EdF board decided to give notice of Fessenheim shutdown within six moths prior to full commissioning of Flamanville 3. However, that notice will only be given if "the closure of the Fessenheim power plant is necessary in order to comply with the legal ceiling of 63.2 GW both on the date of the request for repeal and on the date of commissioning Flamanville 3," EdF said. This means that Fessenheim will continue operating until at least the end of 2018. "The decision of the board, taken in application of the law and respecting the company's social interest, enables EDF, fully committed to the energy transition, to have the nuclear fleet necessary to fulfil its obligations to supply its customers.” The French energy minister responded by saying that the French state would "legally enshrine" the "inevitable and irreversible" closure of Fessenheim, and immediately published a decree saying that EDF's authorisation to operate the plant's two reactors will be withdrawn from the day that the Flamanville 3 EPR enters into service.
In February 2014 EdF gave parliament a breakdown of its €55 billion grand carénage reactor life extension program, mostly to be completed by 2025. This includes spending €15 billion replacing heavy components within its fleet of 58 nuclear units, €10 billion on post-Fukushima modifications and €10 billion to boost safety against external events. It pointed out that there are only two parts of a nuclear reactor that cannot be replaced, the reactor pressure vessel and the reactor containment building. The rest of the components have a normal lifespan of 25-35 years and require renovation or replacement. ASN said it would evaluate life extensions on the basis of Generation III criteria regardless of when particular reactors were built. In 2017 EdF’s grand carénage cost estimate to 2025 was reduced to €48 billion, including both maintenance and upgrading.
In March 2015 the ASN said that there were no generic elements to prevent the twenty 1300 MWe units operating safely to 40 years. It considers the actions planned or already taken by EDF to assess the condition of the reactors and control ageing issues up to their fourth inspection are adequate. However, it said these assessments do not take into account any evaluations of the fitness of the units' reactor pressure vessels for operation beyond 30 years, nor the results of tests carried out during the reactors' third ten-yearly inspections, from April 2015 to 2024.
In February 2016 the Court of Audit estimated that EdF’s Grand carenage reactor life extension program to 2030, and including €25 billion operating costs, would come to about €100 billion. It said: "Despite uncertainties identified to date, estimated at approximately €13.3 billion, the effects of this program on the production cost of nuclear electricity are limited.” It also noted that the effect of France’s 2015 energy transition law requiring a reduction of nuclear output would likely be much greater, though "no economic evaluation of the potential consequences have been conducted before the publication of the law," and this was needed.
Uprates: In the light of operating experience, EdF uprated its four Chooz and Civaux N4 reactors from 1455 to 1500 MWe each in 2003. Over 2008-10 EdF plans to uprate five of its 900 MWe reactors by 3%. Then in 2007 EdF announced that the twenty 1300 MWe reactors would be uprated some 7% from 2015, within existing licence limits, and adding about 15 TWh/yr to output.
Building new nuclear capacity: Flamanville 3
In mid-2004 the board of EdF decided in principle to build the first demonstration unit of an expected series of Areva EPRs. This decision was confirmed by the EdF board in May 2006, after public debate, when it approved construction of a new 1650 MWe class EPR unit at Flamanville, Normandy, alongside two existing 1300 MWe units. The decision was seen as "an essential step in renewing EDF's nuclear generation mix".
The overnight capital cost or construction cost was expected to be €3.3 billion in 2005 Euros (€3.55 billion in 2008 Euros), and power from it EUR 4.6 c/kWh – about the same as from new combined cycle gas turbine at 2005 gas prices and with no carbon emission charge. Series production costs were projected at about 20% less. EDF then submitted a construction licence application. The Flamanville 3 unit is to be 4500 MWt, 1750 MWe gross (at sea temperature 14.7°C) and 1630 MWe net.
Under a 2005 agreement with EdF, the Italian utility ENEL was to have a 12.5% share in the Flamanville 3 unit, taking rights to 200 MWe of its capacity and being involved in design, construction and operation of it. However, early in 2007 EdF backed away from this and said it would build the plant on its own and take all of the output. Nevertheless, in November 2007 an agreement was signed confirming the 12.5% ENEL investment in Flamanville – expected to cost €450 million – plus the same share of another five such plants. The agreement also gave EdF an option to participate in construction and operation of future ENEL nuclear power plants in Italy or elsewhere in Europe and the Mediterranean. But in December 2012 ENEL pulled out of the project and partnership with EdF and agreed to be reimbursed €613 million that it had contributed, including accrued interest. ENEL said it would pursue its commercial business in France by other means.
Site works at Flamanville on the Normandy coast were complete and the first concrete was poured in December 2007, with construction to take 54 months and commercial operation expected in May 2012. In January 2007 EdF ordered the nuclear steam supply system from Areva. The turbine-generator section was ordered in 2006 from Alstom – a 1750 MWe Arabelle unit. This was intended to ensure that 85% of the unit's projected cost was largely locked in. The reactor vessel nozzle support ring was forged by Japan Steel Works (JSW) in 2006. The reactor pressure vessel (RPV) was manufactured at Areva's Creusot Forge St Marcel factory, with delivery to the site in October 2013 and installation in January 2014. In April 2015 tests showed that parts of the RPV steel from Creusot Forge had a high carbon content and one-third lower than specified toughness, and the head of ASN said that it would make an assessment of the slight carbon heterogeneity. Over the next two years China’s National Nuclear Safety Administration (NNSA) was involved with this process, since the steam generators for Taishan 1 are also from Cresusot Forge. In June 2017 the ASN in a provisional opinion said that the Flamanville RPV was safe for operation, but that EdF should replace the vessel head by the end of 2024. ASN said it would order additional periodic inspections of the bottom of the RPV. ASN confirmed this order in October 2017.
As well as the RPV, forging of steam generator shells was at Areva's Creusot Forge factory from 2007, with installation in 2014. The new RPV head would likely be ordered from JSW if EdF cannot convince the ASN that inspections of the present one will suffice for the long-term. EdF said: "The direct cost of replacing a vessel cap amounts to approximately €100 million. At the same time, EDF's teams are mobilised to develop an in-service monitoring method that would allow it to demonstrate that the lid maintains its qualities over the long term” and it will report more fully to the ASN on this within two years. “If this work is conclusive, EDF will submit a new application to the ASN in order to be able to use the vessel cap beyond 2024."
At the end of 2008 the overnight cost estimate (without financing costs) was updated by 21% to €4 billion in 2008 Euros (€2434/kW), and electricity cost to be 5.4 cents/kWh (compared with 6.8 c/kWh for CCGT and 7.0 c/kWh for coal, "with lowest assumptions" for CO2 cost). These costs were confirmed in mid 2009, when EdF had spent nearly €2 billion. In July 2010 EdF revised the overnight cost to about €5 billion and the grid connection to early 2014 – two years behind schedule. In July 2011 EdF again revised the completion time to 2016 due to re-evaluation of civil engineering works and to take into account interruptions during the first half of the year. The cost was then put at €6 billion. In December 2012 EdF raised the cost estimate to €8.5 billion including financing, and said that completion was still expected in 2016. As the reactor pressure vessel was installed in January 2014 Areva confirmed that first power was expected in 2016, four years behind the original schedule. In September 2015 the completion date was moved to late 2018, with the cost increasing to €10.5 billion. These estimates remained current in mid-2017. In July 2017 EdF said that 98% of the civil structure was completed and 60% of the electro-mechanical work, and that the reactor would be connected to the grid in May 2019.
Building new nuclear capacity: other proposals
In August 2005 EdF announced that it planned to replace its 58 reactors with EPR units from 2020, at the rate of about one 1650 MWe unit per year. It would require 40 of these to reach present capacity. This was to be be confirmed on the basis of experience with the initial EPR unit at Flamanville – use of other designs such as Westinghouse's AP1000 or GE's ESBWR was considered possible. EdF's development strategy had selected the nuclear replacement option on the basis of nuclear's "economic performance, for the stability of its costs and out of respect for environmental constraints." However, in mid-2015 Areva said that it was working with EdF on a ‘new model’ EPR – the EPR NM – with simplified construction and significant (likely 25%) cost reduction. The basic design was 30% complete by March 2016, and EdF said that it, not the complex EPR being built at Flamanville, would be the model that replaced the French fleet from the late 2020s. This design is expected to be completed by 2020, for construction by 2030.
In January 2009 President Sarkozy announced that EdF would build a second 1650 MWe EPR, at Penly, near Dieppe, in Normandy. Like Flamanville, it has two 1300 MWe units now operating, and room for two more. GdF-Suez originally planned to hold a 25% stake in it, Total will hold 8.3%, and ENEL is expected to take up 8% or its full 12.5% entitlement. Germany's E.On. is considering taking an 8% stake. EdF may sell down its share to 50%. The French government owns 85% of EdF, 35.7% of GdF Suez and (directly) then 88% of Areva, which would build the unit. A public debate on the project concluded in 2010, but nuclear safety authority ASN did not accept EdF's application to build the unit, sending it back for further work before the application is submitted to a local public inquiry. However, EdF then halted plans for the Penly 3 unit and said that it did not intend to build more nuclear capacity in France for operation before 2025.
A third new reactor, with majority GdF Suez ownership and operated by it, was proposed to follow – in line with the company's announced intentions. A GdF Suez (now Engie) subsidiary, Electrabel, operates seven reactors in Belgium and has equity in two French nuclear plants.
After deciding not to participate in the Penly 2 project, in February 2010 GdF Suez sought approval to build an 1100 MWe Areva-MHI Atmea1 reactor at Tricastin or Marcoule in the Rhone valley to operate from about 2020. This sparked union opposition due to the private ownership. It would have been a reference plant for the Areva-Mitsubishi design, providing a base for export sales.
Power reactors under construction and proposed
|Type||MWe gross||Construction start||Grid connection||Commercial operation|
|Flamanville 3||EPR||1750||12/07||May 2019||2019|
Further nuclear power development
In January 2006 the President announced that the Atomic Energy Commission (CEA)* was to embark upon designing a prototype Generation IV reactor to be operating in 2020, bringing forward the timeline for this by some five years. France has been pursuing three Gen IV technologies: gas-cooled fast reactor, sodium-cooled fast reactor, and very high temperature reactor (gas-cooled). While Areva has been working on the last two types, the main interest in the very high temperature reactors has been in the USA, as well as South Africa and China. CEA interest in the fast reactors is on the basis that they will produce less waste and will better exploit uranium resources, including the 220,000 tonnes of depleted uranium and some reprocessed uranium stockpiled in France.
* Now the Commission of Atomic and Alternative Energy
If the CEA embarks on the sodium-cooled design, there is plenty of experience to draw on – Phenix and Superphenix – and they could go straight to a demonstration plant – the main innovations would be dispensing with the breeding blanket around the core and substituting gas for water as the intermediate coolant. A gas-cooled fast reactor would be entirely new and would require a small prototype as first step – the form of its fuel would need to be unique. Neither would operate at a high enough temperature for hydrogen production, but still CEA would participate in very high temperature R&D with the USA and east Asia.
In December 2006 the government's Atomic Energy Committee decided to proceed with a Generation IV sodium-cooled fast reactor prototype whose design features are to be decided by 2012 and the start up aimed for 2020. A new generation of sodium-cooled fast reactor with innovations intended to improve the competitiveness and the safety of this reactor type is the reference approach for this prototype. A gas-cooled fast reactor design is to be developed in parallel as an alternative option. The prototype will also have the mission of demonstrating advanced recycling modes intended to improve the ultimate high-level and long-lived waste to be disposed of. The objective is to have one type of competitive fast reactor technology ready for industrial deployment in France and for export after 2035-2040. The prototype, possibly built near Phenix at Marcoule, will be 250 to 800 MWe and is expected to cost about €1.5 to 2 billion and come on line in 2020. The project will be led by the CEA.
Load-following with PWR nuclear plants
Normally base-load generating plants, with high capital cost and low operating cost, are run continuously, since this is the most economic mode. But also it is technically the simplest way, since nuclear and coal-fired plants cannot readily alter power output, compared with gas or hydro plants. The high reliance on nuclear power in France thus poses some technical challenges, since the reactors collectively need to be used in load-following mode. (Since electricity cannot be stored, generation output must exactly equal to consumption at all times. Any change in demand or generation of electricity at a given point on the transmission network has an instant impact on the entire system). In France, because electricity is cheap relative to other sources (based on imported fossil fuel), electric heating is widespread and a 1°C temperature change in winter means that demand on the grid changes by about 2400 MWe, making it the most temperature-sensitive demand in Europe, adding to the normal challenge of satisfying the balance between supply and demand.
RTE, a subsidiary of EdF, is responsible for operating, maintaining and developing the French electricity transmission network. France has the biggest grid network in Europe, made up of some 100,000 km of high and extra high voltage lines, and 44 cross-border lines, including a DC link to UK. Electricity is transmitted regionally at 400 and 225 kilovolts. Frequency and voltage are controlled from the national control centre, but dispatching of capacity is done regionally. Due to its central geographical position, RTE is a crucial entity in the European electricity market and a critical operator in maintaining its reliability.
All France's nuclear capacity is from PWR units. There are two ways of varying the power output from a PWR: control rods, and boron addition to the primary cooling water. Using normal control rods to reduce power means that there is a portion of the core where neutrons are being absorbed rather than creating fission, and if this is maintained it creates an imbalance in the fuel, with the lower part of the fuel assemblies being more reactive that the upper parts. Adding boron to the water diminishes the reactivity uniformly, but to reverse the effect the water has to be treated to remove the boron, which is slow and costly, and it creates a radioactive waste.
So to minimise these impacts since the 1980s EdF has used in each PWR reactor some less absorptive 'grey' control rods which weigh less from a neutronic point of view than ordinary control rods and they allow sustained variation in power output. This means that RTE can depend on flexible load following from the nuclear fleet to contribute to regulation in these three respects:
- Primary power regulation for system stability (when frequency varies, power must be automatically adjusted by the turbine).
- Secondary power regulation related to trading contracts.
- Adjusting power in response to demand (decrease from 100% during the day, down to 50% or less during the night, and respond to changes in renewable inputs to the grid, etc.)
PWR plants are very flexible at the beginning of their cycle, with fresh fuel and high reserve reactivity. An EdF reactor can reduce its power from 100% to 30% in 30 minutes. But when the fuel cycle is around 65% through these reactors are less flexible, and they take a rapidly diminishing part in the third, load-following, aspect above. When they are 90% through the fuel cycle, they only take part in frequency regulation, and essentially no power variation is allowed (unless necessary for safety). So at the very end of the cycle, they are run at steady power output and do not regulate or load-follow until the next refueling outage. RTE has continuous oversight of all French plants and determines which plants adjust output in relation to the three considerations above, and by how much.
RTE's real-time picture of the whole French system operating in response to load and against predicted demand shows the total of all inputs. This includes the hydro contribution at peak times, but it is apparent that in a coordinated system the nuclear fleet is capable of a degree of load following, even though the capability of individual units to follow load may be limited.Plants being built today, eg according to European Utilities' Requirements (EUR), have load-following capacity fully built in.
Fuel cycle – front end
France uses some 12,400 tonnes of uranium oxide concentrate (10,500 tonnes of U) per year for its electricity generation. Much of this comes from Areva in Canada (4500 tU/yr) and Niger (3200 tU/yr) together with other imports, principally from Australia, Kazakhstan and Russia, mostly under long-term contracts. Areva perceives the front end of the French fuel cycle as strategic, and invests accordingly.
Beyond this, it is self-sufficient and has conversion, enrichment, uranium fuel fabrication and MOX fuel fabrication plants operational (together with reprocessing and a waste management program). Most fuel cycle activities are carried out by Areva.
Uranium concentrates have been converted to hexafluoride at the 14,000 t/yr Comurhex Malvesi and Pierrelatte plants in the Rhone Valley, which commenced operation in 1959 and 1961.
In May 2007 Areva NC announced plans for a new conversion project – Comurhex II – expanding and modernising the facilities at Malvesi and Pierrelatte near Tricastin to strengthen its global position in the front end of the fuel cycle. The €610 million project increased capacity to 15,000 tU/yr from 2014, with scope (but no plans) for increase to 21,000 tU/yr. At Malvesi near Moussan uranium oxide concentrate is converted to UF4 powder, and this is sent on to Pierrelatte to produce UF6. About 40% of production is on toll basis or exported.
In January 2009 EdF awarded a long-term conversion contract to Areva. On 31 December 2017 Areva announced that it had shut down Comurhex I, with production from the unit to be replaced by Comurhex II from late 2018 onwards. At the start of 2018 Comurhex I had an inventory of three years' worth of sales, from which customers would be supplied between the closure of Comhurhex I and the opening of Comurhex II.
Comurhex also converts reprocessed uranium.
Areva has undertaken deconversion of enrichment tails at Pierrelatte since the 1980s. Its 20,000 t/yr W2 plant produces aqueous HF which is recycled, and the depleted uranium is stored long-term as chemically stable U3O8.
For 33 years this was at Eurodif's 1978 Georges Besse I plant at Tricastin nearby Perrelatte, with 10.8 million SWU capacity (enough to supply some 81,000 MWe of generating capacity – about one-third more than France's total). Eurodif was by far the largest single electricity consumer in France, using 15 TWh/yr for much of its life. It ran at about half capacity (using about 800 MWe) until mid-2012 and then closed down, as replacement capacity at Georges Besse II reached 1.5 million SWU/yr. The plant delivered more than 200 million SWU, or 35,000 t of enriched product in 33 years. Areva owns 59.66% of Eurodif.
In 2003 Areva agreed to buy a 50% stake in Urenco's Enrichment Technology Company (ETC), which comprises all its centrifuge R&D, design and manufacturing activities. The deal will enable Areva to use Urenco/ETC technology to replace its inefficient Eurodif gas diffusion enrichment plant at Tricastin. The final agreement after approval by the four governments involved was signed in mid 2006.
The new Georges Besse II enrichment plant at Tricastin was officially opened in December 2010 and commenced commercial operation in April 2011. The €3 billion two-unit plant, which reached full annual capacity of 7.5 million SWU in 2016 (with potential for increase to 11 million SWU), was built and is operated by Areva NC subsidiary Societe d'Enrichissement du Tricastin (SET). The south plant started construction in 2007, commenced operation in 2011, and reached full capacity of 4.3 million SWU/yr in 2015. Construction of the north plant began in 2009 with first production in March 2013, and was fully operational at the end of 2016 with 3.2 million SWU/yr capacity. Areva claims a 60% cost saving in its construction compared with the south plant, due to experience gained and not changing design. Most production from GBII was contracted as of 2011.
Minority stakes in SET are being offered to customers, and Suez took up 5% in 2008. In March 2009 two Japanese companies, Kansai and Sojitz Corp, jointly took up 2.5%, in June 2009 Korea Hydro & Nuclear Power took a further 2.5%, and in November 2010 Kyushu Electric Power and Tohoku Electric Power each took 1%. The 4.5% Japanese holdings are grouped as Japan France Enrichment Investing Co. (JFEI). EdF as principal customer opted for a long-term contract instead, and in February 2009 it signed a €5 billion long-term enrichment contract with Areva. It runs over 17 years to 2025, corresponding with the amortisation of the new plant. Korea Hydro and Nuclear Power (KHNP) in mid 2007 signed a long-term enrichment supply contract of over €1 billion – described at that time as Areva's largest enrichment contract outside France.
Enrichment will be up to 6% U-235, and reprocessed uranium will only be handled in the second, north unit. There is potential to expand capacity to 11 million SWU/yr, probably with a third unit.
When fully operational in 2018 the whole SET plant will free up some 3000 MWe of Tricastin nuclear power plant's capacity for the French grid – over 20 billion kWh/yr (@ 4 c/kWh this is €800 million/yr). The new enrichment plant investment is equivalent to buying new power capacity @ €1000/kW. The GB II plant will require only about 75 MWe (80 kWh/SWU, compared with about 2600 kWh/SWU for GB I).
About 7300 tonnes of depleted uranium tails is produced annually, most of which is stored for use in Generation IV fast reactors. Only 100-150 tonnes per year is used in MOX. By 2040 this resources is expected to total some 450,000 tonnes of DU.
Enrichment of depleted uranium tails has been undertaken in Russia, at Novouralsk and Zelenogorsk. Some 33,000 tonnes of French DU from Areva and EdF has been sent to Russia in 128 shipments over 2006-09, and about 3090 t of enriched 'natural' uranium (about 0.7% U-235) has been returned as of May 2010: 2400 t to Eurodif, 380 t to Areva Pierrelatte, and 310 t to Areva FBFC Romans. The contracts for this work end in 2010, and the last shipment was in July 2010 with the returned material to be shipped by year end. Tails from re-enrichment remain in Russia as the property of the enrichers.
Fuel fabrication is at several Areva plants in France and Belgium. Significant upgrading of these plants forms part of Areva's strategy for strengthening its front end facilities. MOX fuel fabrication is described below.
Fuel cycle – back end
France chose the closed fuel cycle at the very beginning of its nuclear program, involving reprocessing used fuel so as to recover uranium and plutonium for re-use and to reduce the volume of high-level wastes for disposal. Recycling allows 30% more energy to be extracted from the original uranium and leads to a great reduction in the amount of wastes to be disposed of. Overall the closed fuel cycle cost is assessed as comparable with that for direct disposal of used fuel, and preserves a resource which may become more valuable in the future. Back end services are carried out by Areva. Used fuel storage in pools at reactor sites is relatively brief. Late in 2011, 70% of EdF's used fuel was in used fuel pools, mostly at La Hague, 19% was in dry casks and 11% had been reprocessed. Total in storage was 14,200 tonnes.
Used fuel from the French reactors and from otehr countries is sent to Areva's La Hague plant in Normandy for reprocessing. This has the capacity to reprocess up to 1700 tonnes per year of used fuel in the UP2 and UP3 facilities, and had reprocessed 28,600 tonnes to the end of 2012. The treatment extracts 99.9% of the plutonium and uranium for recycling, leaving 3% of the used fuel material as high-level wastes which are vitrified and stored there for later disposal. Typical input today is 3.7% enriched used fuel from PWR and BWR reactors with burn-up to 45 GWd/t, after cooling for four years. In 2009 Areva reprocessed 929 tonnes, most from EdF, but 79 t from SOGIN in Italy. It was aiming for throughput of 1500 t/yr by 2015, though with completion of German and Japanese contracts the sole source of feed is now EdF.
EdF was sending some 850 tonnes for reprocessing out of about 1200 tonnes of used fuel discharged per year, though from 2010 it sent 1050 t/yr. The rest is preserved for later reprocessing to provide the plutonium required for the start-up of Generation IV reactors. Reprocessing is undertaken a few years after discharge, following some cooling. Some 10.5 tonnes of plutonium and 1000 tonnes of reprocessed uranium (RepU) are recovered each year from the 1050 tonnes treated each year. The plutonium is immediately shipped to the 195 t/yr Melox plant near Marcoule for prompt fabrication into about 120 tonnes of mixed-oxide (MOX) fuel, which is used in 24 of EdF's 900 MWe reactors.
At the end of 2010, there were 80 tonnes of civilian plutonium in storage in France, 60 t of it at La Hague. Of the total, 56 t belonged to French entities, and 27 t to EdF. ANDRA said that quantity corresponds to almost three years’ production of MOX fuel at Areva’s 195 t/yr Melox facility. To late 2014, Areva had reprocessed more than 13,000 tonnes of used EdF fuel at La Hague, and recycled 130 tonnes of plutonium into MOX for EdF. From this, it has delivered 4000 MOX fuel assemblies to EdF.
Used MOX fuel and used RepU fuel is stored pending reprocessing and use of the plutonium in Generation IV fast reactors. These discharges earlier amounted to about 140 tonnes per year, but rose to 200 tonnes from 2010. Used MOX fuel is not reprocessed at present.
EdF's recycled uranium (RepU) is converted in Comurhex plants at Pierrelatte, either to U3O8 for interim storage, or to UF6 for re-enrichment in centrifuge facilities at Seversk in Russia*. About 500 tU of French RepU as UF6 was sent to JSC Siberian Chemical Combine at Seversk for re-enrichment. The enriched RepU UF6 from Seversk was then turned into UO2 fuel in Areva's FBFC Romans plant (capacity 150 t/yr). EdF used it in the Cruas 900 MWe power reactors from the mid-1980s to 2014. The main RepU inventory – 24,000 tonnes at four sites at the end of 2010 but only 16,900 tonnes at the end of 2012 – constitutes a strategic resource, and EdF intends to increase its utilization significantly. The enrichment tails remain at Seversk, as the property of the enricher.
* RepU conversion and enrichment requires dedicated facilities due to its specific isotopic composition (presence of even isotopes – notably U-232 and U-236 – the former gives rise to gamma radiation, the latter means higher enrichment is required). It is the reason why the cost of these operations may be higher than for natural uranium. However, taking into account the credit from recycled materials (natural uranium savings), commercial grade RepU fuel is competitive and its cost is more predictable than that of fresh uranium fuel, due to uncertainty about future uranium concentrate prices.
Considering both plutonium and uranium, EdF estimates that about 20% of its electricity is produced from recycled materials. Areva's estimate is 17%, from both MOX and RepU.
Areva has the capacity to produce and market 150 t/year of MOX fuel at its Melox plant for French and foreign customers (though it is licensed for 195 t/yr). In Europe 35 reactors have been loaded with MOX fuel. Contracts for MOX fuel supply were signed in 2006 with Japanese utilities. All these fuel cycle facilities comprise a significant export industry and have been France’s major export to Japan. At the end of 2008 Areva was reported to have about 30 t/yr in export contracts for MOX fuel, with demand very strong. However, EdF has priority. To the end of 2012 Melox had produced about 2000 tonnes of MOX fuel. In 2014 it produced 134 tonnes.
In addition to LWR fuel, about 5000 tonnes of gas-cooled reactor natural uranium fuel was earlier reprocessed at La Hague, and over 18,000 tonnes was reprocessed at the UP1 plant for such fuel at Marcoule, which closed in 1997.
At the end of 2008 Areva and EdF announced a renewed agreement to reprocess and recycle EdF's used fuel to 2040, thereby securing the future of both La Hague and Melox plants, though prices were not specified past 2013. The 2008 agreement supported Areva's aim to have La Hague operating at 1500 t/yr by 2015, instead of two-thirds of that in 2008. It also meant that EdF increased the amount of its used fuel sent for reprocessing to 1050 t/yr from 2010, and Melox would produce 120 t/yr MOX fuel for EdF then, up from 100 tonnes in 2009. It also meant that EdF would recycle used MOX fuel. The base terms for the 2013-20 period were in a 2014 agreement that increased volumes of used LWR fuel to about 1,100 tonnes and MOX fuel to 123 tonnes per year.
Under the 2006 Planning Act, each nuclear operator (EDF, AREVA, CEA) manages its waste management and decommissioning fund, which stays inside the company.
France's back-end strategy and industrial developments are to evolve progressively in line with future needs and technological developments. The existing plants at La Hague (commissioned around 1990) have been designed to operate for at least forty years, so with operational and technical improvements taking place on a continuous basis they are expected to be operating until around 2040. This will be when Generation IV plants (reactors and advanced treatment facilities) should come on line. In this respect, three main R&D areas for the next decade include:
- The COEX process based on co-extraction and co-precipitation of uranium and plutonium together as well as a pure uranium stream (eliminating any separation of plutonium on its own). This is designed for Generation III recycling plants and is close to near-term industrial deployment.
- Selective separation of long-lived radionuclides (with a focus on Am and Cm separation) from short-lived fission products based on the optimization of DIAMEX-SANEX processes for their recycling in Generation IV fast neutron reactors with uranium as blanket fuel. This option can also be implemented with a combination of COEX and DIAMEX-SANEX processes.
- Group extraction of actinides (GANEX process) as a long term R&D goal for a homogeneous recycling of actinides (ie U-Pu plus minor actinides together) in Generation IV fast neutron reactors as driver fuel.
All three processes are to be assessed as they develop, and one or more will be selected for industrial-scale development with the construction of pilot plants. In the longer term the goal is to have integral recycling of uranium, plutonium and minor actinides. In practical terms, a technology – hopefully GANEX or similar – will need to be validated for industrial deployment of Gen IV fast reactors about 2040, at which stage the present La Hague plant will be due for replacement.
See also R&D section below.
Waste disposal is being pursued under France's 1991 Waste Management Act (updated 2006) which established the Agence Nationale pour la gestion des Déchets Radioactifs – ANDRA – as the National Radioactive Waste Management Agency and which set the direction of research - mainly undertaken at the Bure underground rock laboratory in eastern France, situated in clays. Another laboratory is researching granites. Research is also being undertaken on partitioning and transmutation, and long-term surface storage of wastes following conditioning. Wastes are to be retrievable from the repository. ANDRA publishes a waste inventory every two years and reports to government so that parliament can decide on waste policy.
The 2006 revision of the Waste Management Act extended the mandate of the Commission Nationale d'Evaluation – CNE – the National Scientific Assessment Committee, to all wastes. Its role was assessing R&D in three areas concerned with high-level and intermediate-level wastes: deep-geologic disposal, separation and transmutation, and interim storage of nuclear wastes, and this was extended to nuclear materials and all types of waste when CNE2 succeeded the initial CNE in 2006. In April 2007 the government appointed 12 new members to the CNE2 to report on progress in France's waste management R&D across EdF, CEA, ANDRA and the National Centre for Scientific Research. It reports annually.
After strong support in the National Assembly and Senate, the Nuclear Materials and Waste Management Program Act was passed in June 2006 to apply for 15 years. This formally declared deep geological disposal as the reference solution for high-level and long-lived radioactive wastes, and set 2015 as the target date for licensing a repository and 2025 for opening it. It also affirmed the principle of reprocessing used fuel and using recycled plutonium and uranium "in order to reduce the quantity and toxicity" of final wastes, and called for construction of a prototype fourth-generation reactor by 2020 to test transmutation of long-lived actinides.
Funds for waste management and decommissioning remain segregated but with the producers, rather than in an external fund. In 2016 the energy minister set the reference cost of the repository project at €25 billion (in 2011 Euro), the figure to be updated as construction proceeds. This is slightly higher than EdF and Areva had provided for in their accounts, so will require adjustments of €800 million and €250 million respectively. ANDRA is expected to lodge a construction licence application in 2017, start construction in 2020, and commence the pilot phase of disposal in 2025. More than half the total cost is expected to be construction, and one-quarter for operation over 100 years.
The 2006 Waste Management Act defined three main principles concerning radioactive waste and substances: reduction of the quantity and toxicity, interim storage of radioactive substances and ultimate waste, and deep geological disposal. A central point is the creation of a national management plan defining the solutions, the goals to be achieved and the research actions to be launched to reach these goals. This plan is updated every three years and published according to the law on nuclear transparency and security.
The 2006 Act was largely in line with recommendations to government from the CNE following 15 years of research. Their report identified the clay formation at Bure as the best site, but was sceptical of partitioning and transmutation for high-level wastes, and said that used MOX fuel should be stored indefinitely as a plutonium resource for future fast neutron reactors, rather than being recycled now or treated as waste. In a 2010 report CNE2 said that transmutation of minor actinides in fast reactors would add about 10% to power cost, and transmutation of all actinides in an accelerator-driven system (ADS) would add about 20%. Wastes from transmutation reactors will be in interim storage for at least 70 years. In its 2012 report CNE2 noted the great value of plutonium in fast reactors and their role in transmuting long-lived actinides, hence “an experimental reactor and its associated cycle – fuel fabrication and reprocessing – are indispensable” to test “the industrial and economic viability” of that concept while maintaining France’s leadership in civil nuclear energy. In particular the Astrid project would allow “preservation of a range of energy options and ensure France’s energy independence for several centuries.” (see R&D section below)
Earlier, an international review team reported very positively on the plan by ANDRA for a deep geological repository complex in clay at Bure. In 1999 ANDRA was authorised to build an underground research laboratory at Bure to prepare for disposal of vitrified high-level wastes (HLW) and long-lived intermediate-level wastes.
ANDRA is designing its Bure repository – the Industrial Centre for Geological Disposal (Centre Industriel de Stockage Géologique, CIGEO) – to operate at up to 90°C, which it expects to be reached about 20 years after emplacement. In October 2012 CNE2 endorsed the plans for the CIGEO 500-metre deep repository at Bure. Public consultation over May to December 2013 showed that the public was “not opposed in principle” to the project, but wanted a pilot phase demonstration and provision for reversibility. ANDRA commissioned detailed studies on waste handling procedures, and it expects to submit to government its master plan for operation and disposal for CIGEO in 2017. A construction permit application is expected in 2018, with construction from 2020. The pilot phase of CIGEO is expected to operate from 2025. It will be designed to take 10,000 cubic metres of HLW, mostly vitrified (from reprocessing 45,000 t used fuel), and 73,600 m3 of long-lived ILW, of which 15,000 m3 is metallic parts from spent fuel.* Vitrified waste canisters will be inserted into long horizontal boreholes 70 cm in diameter lined with steel tubes. In 2015 an amendment to the 2006 Act clarified that for the CIGEO project HLW being ‘recoverable’ referred to short-term practicality, while ‘reversible’ meant guaranteeing long-term policy flexibility.
* Initially the CIGEO concept included direct disposal of some categories of used fuel, but the cost implication was considerable due to increased footprint and safeguards management, and the idea was abandoned. Only standard universal canisters will be used, and all fuel will be recycled.
Two further repositories are envisaged by ANDRA and CEA.
LLW & ILW:
ANDRA has the Centre de l’Aube disposal facility for low-level (LLW) and short-lived intermediate-level wastes (ILW) near Soulaines in the Aube district, with a capacity of one million cubic metres, and a quarter of this so far filled. It opened in 1992 and benefited from the experience gained at Centre da la Manche. It is operated by an Areva subsidiary. ANDRA also has the Morvilliers facility (CSTFA) nearby licensed to hold 650,000 cubic metres of very low-level waste (VLLW), mostly from plant dismantling, in the Aube district around Troyes east of Paris. ANDRA’s Centre de la Manche facility next to La Hague received 527,000 m3 of low- and short-lived intermediate-level wastes from 1969 to 1994, and is now capped with a multi-layer grassed cover.
In June 2008, ANDRA officially invited 3,115 communities with favorable geology to consider hosting a facility for the disposal of long-lived LLW (FA-VL, containing radionuclides with half lives of over 30 years). This is 70,000 m3(18,000 tonnes) of graphite from early gas-cooled reactors and 47,000 m3 of radium-bearing materials from manufacture of catalytic converters and electronic components, as well as wastes from mineral and metal processing that cannot be placed in Andra's low-level waste disposal center in Soulaines. In response, 40 communities put themselves forward for consideration. Preliminary studies completed late in 2008 by ANDRA revealed that two – Auxon and Pars-lès-Chavanges in the Aube district – had suitable rock formations and environments for the disposal of the wastes, but after intense lobbying by anti-nuclear groups both withdrew. Investigations are proceeding. A repository is likely to be in clay, about 15 metres below the land surface. Meanwhile ANDRA is building a store for FA-VL wastes at its Morvilliers VLLW site.
In April 2007 the government appointed 12 new members to the CNE to report on progress in France's waste management R&D across EdF, CEA, ANDRA and the National Centre for Scientific Research.
Financing wastes: EdF sets aside 0.14 cents/kWh of nuclear electricity for waste management costs. At the end of 2016, EdF had €19.6 billion provisions in its dedicated back-end fund for France, comprising €10.6 billion for spent fuel management and €9.0 billion for long-term radioactive waste management.
Wastes R&D: In August 2010 ANDRA announced that it expected €100 million for two waste projects:
- To establish a commercially viable system to recycle materials recovered during decommissioning of nuclear facilities. The materials – mainly steel and concrete – would be used exclusively in the nuclear industry. (French law prohibits using recycled materials from nuclear installations in non-nuclear applications, which discourages recycling of decommissioning waste and threatens to quickly fill Andra’s Morvilliers disposal facility – CSTFA).
- To develop techniques to condition chemically-active intermediate-level radwastes for final disposal. Those 'mixed' wastes can be in liquid, gaseous, or organic form. The goal is to condition them in the most inert physical and chemical forms possible to meet safety requirements of a deep repository. Most such wastes are from outside the nuclear power industry, but industry generation of them is expected to increase. Industrial-scale solutions are likely to be costly, and ANDRA is therefore seeking international partners.
Thirteen experimental and power reactors are being decommissioned in France, nine of them first-generation gas-cooled, graphite-moderated types, six being very similar to the UK Magnox type. There are well-developed plans for dismantling these (which have been shut down since 1990 or before) and work is progressing. However, completion awaits the availability of sites for disposing of the intermediate-level wastes and the alpha-contaminated graphite from the early gas-cooled reactors. At least one of these, Marcoule G2, has been fully dismantled.
The other four include the 1240 MWe Superphénix (Creys-Malville) fast reactor, the veteran 233 MWe Phénix fast reactor, the 1966 prototype 305 MWe PWR at Chooz, and an experimental 70 MWe GCHWR at Brennilis. A licence was issued for dismantling Brennilis in 2006, and for Chooz A in 2007. EdF points to Chooz A as the most representative plant of those currently operating, and dismantling work on it is on schedule for completion in 2022 and on budget.
Shutdown Power Reactors in France
In April 2008 ASN issued a draft policy on decommissioning which proposes that French nuclear installation licensees adopt "immediate dismantling strategies" rather than safe storage followed by much later dismantling. The policy foresees broad public information in connection with the decommissioning process.
In June 2016 EdF told ASN that it was adopting a new strategy for decommissioning the six main GCR reactors at Bugey, Chinon and Saint-Laurent. This will push back the timeline by several decades.
Materials arising from EdF's decommissioning will include: 500 tonnes of long-liver intermediate-level wastes, 18,000 tonnes of graphite, 41,000 tones of short-lived intermediate-level wastes and 105,000 tonnes of very low level wastes.
The Eurodif gaseous diffusion enrichment plant at Tricastin, closed down in June 2012, is being decommissioned from 2015, after residual uranium was recovered from it. The decommissioning cost is put at €800 million. It is expected to generate 130,000 tonnes of steel and 20,000 tonnes of aluminium that could be recycled, subject to regulatory approval, for use in ANDRA’s disposal centres or elsewhere in the industry from 2017.
Organisation and financing of final decommissioning of the UP1 reprocessing plant at Marcoule was settled in 2004, with the Atomic Energy Commission (CEA) taking it over. The total cost is expected to be some €5.6 billion. The plant was closed in 1997 after 39 years of operation, primarily for military purposes but also taking the spent fuel from EdF's early gas-cooled power reactors. It was operated under a partnership, Codem, with 45% share by each of CEA and EdF and 10% share by Cogema (now Areva NC). EdF and Areva paid CEA €1.5 billion and are clear of further liability.
The total expected cost is periodically re-evaluated, and EDF puts aside an amount related to the total estimated cost, the actualisation cost and the expected lifetime of the plants. At the end of 2016 it carried provisions of €16.4 billion for decommissioning and last cores in France, comprising €14.1 billion for decommissioning and €2.3 billion for last cores. It estimates that the total cost (from 2035) will be €75 billion.
In January 2012 France's Court of Audit released a report on the costs of nuclear power in the country. It included a section on decommissioning, and said that the future costs for decommissioning all of France's nuclear facilities (including reactors, research facilities and fuel cycle plants) and disposing of radioactive wastes were estimated to be €79.4 billion. The cost of demolishing facilities came to €31.9 billion, including €18.4 billion for dismantling EDF's 58 operating reactors. The costs of managing used fuel were put at €14.8 billion ($19.3 billion), while waste disposal will cost €28.4 billion. However, the court noted that these future costs estimates are tentative because of the lack of firm decommissioning costs and the lack of final disposal plans. A massive increase in future costs would have a "significant but limited" impact on the annual cost of electricity production, it said.
In January 2017 a parliamentary committee reported: "The cost of decommissioning is likely to be greater than the provisions," the technical feasibility is "not fully assured" and the dismantling work will take "presumably more time than expected." It questioned the basis of EdF’s estimates of €75 billion total cost. EdF responded that it "assumes full responsibility for the technical and financial aspects of dismantling its nuclear plants," and noted that it was currently decommissioning nine reactors, so had a good basis of experience. It also pointed out that its funds set aside for decommissioning were audited by the Ministry of the Environment, Energy and the Sea the previous month.
Regulation & safety
The General Directorate for Nuclear Safety and Radiological Protection (DGSNR) was set up in 2002 by merging the Directorate for Nuclear Installation Safety (DSIN) with the Office for Protection against Ionising Radiation (OPRI) to integrate the regulatory functions and to "draft and implement government policy."
In 2006 the new Nuclear Safety Authority (Autorite de Surete Nucleaire – ASN), an independent body with five commissioners – became the regulatory authority responsible for nuclear safety and radiological protection, taking over these functions from the DGSNR, and reporting to the Ministers of Environment, Industry & Health. However, its major licensing decisions will still need government approval.
Research is undertaken by the IRSN – the Institute for Radiological Protection & Nuclear Safety – also set up in 2002 from two older bodies. IRSN is the main technical support body for ASN and also advises DGSNR.
There have been two INES Level 4 accidents at French nuclear plants, both involving the St Laurent A gas-cooled graphite reactors. In October 1969, soon after commissioning, about 50 kg of fuel melted in unit 1, and in March 1980 some annealing occurred in the graphite of unit 2, causing a brief heat excursion. On each occasion the reactor was repaired, and the two were eventually taken out of service in 1990 and 1992.
The French Nuclear Energy Society (SFEN) is a professional association.
The Atomic Energy Commission (Commissariat à l'énergie atomique – CEA) was set up in 1945 and is the public R&D corporation responsible for all aspects of nuclear policy, including R&D. In 2009 it was re-named Commission of Atomic Energy and Alternative Energy (Commissariat à l'énergie atomique et aux énergies alternatives, CEA).
The CEA has 14 research reactors of various types and sizes in operation, all started up 1959 to 1980, the largest of these being the 70 MWt Osiris at Saclay, which started up in 1966 for material and fuel testing, and is now being decommissioned. About 17 units dating from 1948 to 1982 are shut down or decommissioning. About half of these operating reactors use high-enriched fuel. Early in 2012 the USA shipped 186 kg of 93%-enriched HEU to Grenoble for the High Flux reactor (RHF) at the Institut Max von Laue-Paul Langevin (ILL). Previously this had used fuel sourced from Russia.
In 2004 the US energy secretary signed an agreement with the French Atomic Energy Commission (CEA) to gain access to the Phenix experimental fast neutron reactor for research on nuclear fuels. The US Department of Energy acknowledged that this fast neutron "capability no longer exists in the USA". The US research with Phenix irradiated fuel loaded with various actinides under constant conditions to help identify what kind of fuel might be best for possible future waste transmutation systems.
In mid-2006 the CEA signed a four-year €3.8 billion R&D contract with the government, including development of two types of fast neutron reactors which are essentially Generation IV designs: an improved version of the sodium-cooled type (SFR) which already has 45 reactor-years operational experience in France, and an innovative gas-cooled type. Both would have fuel recycling. The CEA sought support under the EC's European Sustainable Nuclear Industrial Initiative and partnerships with Japan and China to develop SFR which will have great flexibility in breeding ratios. It noted that China and India are aiming for high breeding ratios to produce enough plutonium to crank up a major push into fast reactors.
The National Scientific Evaluation Committee (CNE) in mid 2009 said that the sodium-cooled model, Astrid(Advanced Sodium Technological Reactor for Industrial Demonstration), should be a high priority in R&D on account of its actinide-burning potential. It is envisaged as a 600 MWe prototype of a commercial series of 1500 MWe SFR reactors which is likely to be deployed from about 2050. These will consume the plutonium in used MOX fuel and utilise the half million tonnes of DU that France will have by 2050. Astrid will have high fuel burnup, including minor actinides in the fuel elements, and while the MOX fuel will be broadly similar to that in PWRs, it will have 25-35% plutonium and negative void reactivity in the core. It will use an intermediate sodium coolant loop, though whether the tertiary coolant is water/steam or gas was an open question, due to be decided at the end of 2017. Over 2014-16 experiments with Brayton cycle gas turbine technology driven by nitrogen were carried out with the CEA. Four independent heat exchanger loops are likely, and it will be designed to reduce the probability and consequences of severe accidents to an extent that is not now done with FNRs. Astrid is called a "self-generating" fast reactor rather than a breeder in order to demonstrate low net plutonium production. Astrid is designed to meet the stringent criteria of the Generation IV International Forum in terms of safety, economy and proliferation resistance. CEA plans to build it at Marcoule.
In September 2010 the government confirmed its support, and €651.6 million funding to 2017, for a 600 MWe Astrid prototype. (A further €350 million was later approved to 2020.) In December 2012 it approved moving to the design phase, with a final decision on construction to be made in 2019. The six-year conceptual design was finished in 2015. The basic design phase runs to 2019, with 14 industrial partners. The CEA is responsible for the project and will design the reactor core and fuel, but will collaborate with Areva, which would design the nuclear steam supply system, the nuclear auxiliaries and the instrumentation and control system. Japanese partners are playing a major role since 2015.
According to a February 2010 study by Deloitte for the EU's Strategic Nuclear Energy Technology Platform, a 600 MWe sodium-cooled fast reactor would cost €4.286 billion, with most of the financing coming from European institution loans, EU incentives and grants such as the EC's European Sustainable Nuclear Industrial Initiative, plus EUR 839 million from private investors.
The Astrid program includes development of the reactor itself and associated fuel cycle facilities: a dedicated MOX fuel fabrication line (AFC) is to be built about 2017 and a pilot reprocessing plant for used Astrid fuel (ATC) about 2023. Fuel rods containing actinides for transmutation were scheduled to be produced from 2023, though fuel containing minor actinides would not be loaded for transmutation in Astrid before 2025. All the dates appear to have slipped, and with a decision in 2019, construction could start in 2022 and operation about 2030.
A major tripartite France-US-Japan accord on developing fast reactors was signed in October 2010, and some Astrid safety and performance features have been checked by the Idaho National Laboratory in USA. In May 2014 Japan committed to support Astrid development, and in August 2014 JAEA, Mitsubishi Heavy Industries and Mitsubishi FBR Systems concluded an agreement with the CEA and Areva to progress cooperation on Astrid. In 2015 JAEA with MHI-MFBR became the second largest contributor to the program, after Areva NP. In March 2017 the Japanese partnership was strongly reaffirmed after Japan decided to decommission its Monju FNR.
CNE is a high-level scientists’ panel set up under the 1991 nuclear waste management act and charged with reviewing the research and development programs of the organizations responsible for nuclear energy, research and waste. The CNE expressed a clear preference for the concept of heterogeneous recycling of minor actinides, called CCAM. In that process, minor actinides are separated out from used fuel in an advanced-technology reprocessing plant and then incorporated into blanket assemblies which are placed around the core of a future fast reactor. Such blanket assemblies could contain 20% minor actinides or more, dispersed in a uranium oxide matrix. (In homogeneous recycling, the actinides are incorporated into the actual fuel.)
The second line of FNR development is the gas-cooled fast reactor. A 50-80 MWt experimental version – Allegro – is envisaged to be built by 2025. This will have either a ceramic core with 850°C outlet temperature, or a MOX core at 560°C. The secondary circuit will be pressurized water. The CEA has encouraged Czech Republic, Hungary and Slovakia to host the demonstration project. Further detail in Fast Neutron Reactors paper.
In June 2010 the CEA signed a major framework agreement with Rosatom covering "nuclear energy development strategy, nuclear fuel cycle, development of next-generation reactors, future gas coolant reactor systems, radiation safety and nuclear material safety, prevention and emergency measures." Much of the collaboration will be focused on reprocessing and wastes, also sodium-cooled fast reactors. Subsequently EdF signed a further cooperation agreement covering R&D, nuclear fuel, and nuclear power plants – both existing and under construction.
In December 2009, as part of a €35 billion program to improve France's competitiveness, the government awarded €1 billion to the CEA for Generation IV nuclear reactor and fuel cycle development. CEA has two priorities in this area:
- Fast neutron reactors with sodium or gas cooling and a closed fuel cycle.
- In collaboration with industry partners, a very high temperature 600 MWt reactor for electricity around 2025 and long-term for process heat applications such as hydrogen production.
Areva is developing Antares, the French version of General Atomics' GT-MHR – a high-temperature gas-cooled reactor with fuel in prismatic blocks. It says that it "is using the Antares program to make VHTR a pivotal aspect of its new product development."
In 2015, CEA's nuclear research centres in Saclay and Cadarache became the first to be designated international research hubs under the International Centre based on Research Reactors (ICERR) program launched by the International Atomic Energy Agency (IAEA) the previous year. The designation period covers 2015 to 2020. Related to this, the CEA has signed agreements with Jordan, Morocco, Tunisia, Algeria, Slovenia and Indonesia. The ICERR program allows participating research reactors in its framework to coordinate and rationalise their offer of facilities, resources and services to interested IAEA member states.
In March 2007 the CEA started construction of a 100 MWt materials testing reactor at Cadarache to replace Osiris. The Jules Horowitz reactor (JHR) with twice the neutron flux of Osiris is the first such unit to be built for several decades, and has been identified by the EU as a key infrastructure facility to support nuclear power development, as well as producing radioisotopes and irradiating silicon for high-performance electronic use. The €500 million cost is being financed by a consortium including CEA (50%), EdF (20%), Areva (10%) and EU research institutes (20%). Since the anticipated planned high-density U-Mo fuel is not likely to be ready in time, it will start up on uranium silicide fuel enriched to 27%. Areva TA has designed and is building it and commissioning is expected by 2021.
Also at Cadarache, Areva TA with DCNS is building a test version of its Réacteur d’essais à terre (RES), a land-based equivalent of its K15 naval reactor of 150 MW, running on low-enriched fuel. It has also designed the NP-300 reactor based on these, able to be built in sizes up to about 300 MWe.
In January 2011 DCNS announced the Flexblue submerged nuclear power plant concept, developed in collaboration with Areva, EdF and CEA. A 50 to 250 MWe nuclear power system (reactor, steam generators and turbine-generator) would be housed in a submerged 12,000 tonne cylinder about 100 metres long and 12-15 metres diameter, offshore at about 60-100 m depth. DCNS is a state-owned naval defence group formed in 2007 from the merger of DCN shipyard and Thales SA, and makes nuclear submarines and surface ships. It has built 18 nuclear reactors for the French navy and is building the RES test reactor and some components for EPR reactors. Subject to market evaluation, DCNS could start building a prototype Flexblue unit in 2013 in its shipyard at Cherbourg for launch and deployment in 2016. Offshore Flamanville has been mentioned as a potential site for a prototype unit. The concept eliminates the need for civil engineering, and refueling or major service can be undertaken by refloating it and returning to the shipyard.
In relation to introduction of Generation IV reactors by 2040, the CEA is investigating several fuel cycle strategies:
- Optimising uranium and plutonium recycling from present and EPR reactors, then co-management of U&Pu and possibly Np in Gen IV fast reactors.
- Recycling these with a low proportion of minor actinides (eg 3% MA) in driver fuels of Gen IV fast reactors.
- Recycling (in about one third of France's reactors) with up to 30% of minor actinides in MOX blanket assemblies of Gen IV fast reactors.
CEA is part of a project under the Generation IV International Forum investigating the use of actinide-laden fuel assemblies in fast reactors – The Global Actinide Cycle International Demonstration (GACID). See Generation IV Nuclear Reactors paper.
The well-established 900 MWe PWR design was sold to several export markets: Iran (2), South Africa (2) and South Korea (2) and China (4). There are two 900 MWe French reactors operating at Koeberg, near Cape Town in South Africa, two at Hanul/Ulchin in South Korea and four at Daya Bay/Ling Ao in China, near Hong Kong. The deal with Iran collapsed politically in 1979 and the engineering components retained in France were used at Gravelines. China's CPR-1000 design is based on the four French M310 units.
Framatome in conjunction with Siemens in Germany then developed the European Pressurised Water Reactor (EPR), based on the French N4 and the German Konvoi types, to meet the European Utility Requirements and also the US EPRI Utility Requirements. This received French design approval in 2004. Areva NP sold four EPRs to 2007 – to Finland, France and China (2). In 2009 Areva with GDF-Suez and Total lost a bid to build four EPRs near Abu Dhabi in the UAE. Areva has sold no EPRs since 2007, though there are plans to build some in the UK.
Export sales and prospects for French nuclear power plants
|Country||Plant||Type||Est. cost||Company||Status, financing|
|Iran||Darkhovin 1&2||M310||$2 billion||Framatome||Cancelled in 1979|
|South Africa||Koeberg 1&2||M310||Framatome||Commissioned 1984-85|
|South Korea||Hanul/ Ulchin 1&2||M310||Framatome||Commercial operation 1988-89|
|China||Daya Bay||M310||Framatome||Commercial operation 1994|
|China||Ling Ao||M310||Framatome||Commercial operation 2002|
|Finland||Olkiluoto 3||EPR||Areva NP||Construction delayed and over budget|
|China||Taishan 1&2||EPR||Areva NP||Construction delayed and over budget|
|Turkey||Sinop 1-4||Atmea1||$22 billion||MHI-Areva||Planned|
|UK||Hinkley Point C 1&2||EPR||£19.6 billion||Areva NP||Planned, construction start 2019|
|UK||Sizewell C 1&2||EPR||Areva NP||Planned|
After Areva lost its bid to build EPRs in the UAE, the Nuclear Policy Council (CPN) in 2011 called on Areva, EdF, GdF-Suez (now Engie) and "other stakeholders" to strengthen their collaboration on the Atmea1 power reactor. This is a medium-sized (1100 MWe) Generation III design being developed under a 2006 joint venture by Areva NP and Mitsubishi Heavy Industries. The reactor is intended for marketing primarily to countries embarking upon nuclear power programs, although CPN said that construction of an initial Atmea1 in France, as proposed by GdF Suez, would be considered. In addition, the Ministry of Energy would lead a working group to look into the technical, legal and economic aspects of small (100-300 MWe) reactor designs. In May 2013 the Turkish government accepted a proposal from a consortium led by Mitsubishi Heavy Industries (MHI) and Areva, with Itochu, for four Atmea1 reactors at Sinop, at a cost of some $22 billion.
The Nuclear Sector Strategy Committee (CSFN) was set up in February 2011 by the CPN and comprises representatives of 80 companies and industry organizations. It is headed up by EdF. The CSFN Fund for Modernization of Nuclear Enterprises has seed money of €133 million, with €50 million being contributed each by France’s public investment bank through its sovereign investment fund, FSI, and EDF. Areva would contribute €13 million, Alstom €10 million, and the three largest civil engineering and construction firms, Bouyges, Vinci and Eiffage, the rest. It is an expression of French determination to regain a major role in nuclear exports through "patriotic solidarity". A new trade association, Gifen, was envisaged.
With the French Atomic Energy Commission (CEA) coordinating national policy, CPN told it to negotiate with Chinese authorities to establish a comprehensive partnership between the two countries on all aspects of the civil nuclear power sector, including safety. This could include development of a new 1000 MWe Generation III reactor with China, probably with China General Nuclear Power Group (CGN) and based on the successful CPR-1000 in which Areva retains some intellectual property rights. CGN refers to this as Generation II+, and has said that it was on a development trajectory with the design which would eliminate those rights by 2013 and result in a design of an exportable Generation III standard. The French nuclear safety authority (ASN) is adamant that there should be no French involvement with any nuclear power project using a reactor design that is not licensable in France. (EdF's China involvement is in holding 30% of the Guangdong Taishan Nuclear Power Joint Venture Company Limited – TNPC, which is building the twin EPR power plant at Taishan. CGN holds the balance.)
These 2011 policy developments incorporated the role of the Agence France Nucleaire International (AFNI), created in May 2008 under CEA to provide a vehicle for international assistance. Its purpose is to help to set up structures and systems to enable the establishment of civil nuclear programs in countries wanting to develop them and to draw on all of the country's expertise in this. It is guided by a steering committee comprising representatives of all the ministries involved (such as Energy, Foreign Affairs, Industry, Research) as well as representatives of other major French nuclear institutions including the CEA itself and the Institute for Radiological Protection & Nuclear Safety (IRSN). Its work will be confined to countries with which France has signed a nuclear cooperation agreement, among the 40 countries which have sought assistance from France. It functions on a fee for service basis.
France is a party to the Nuclear Non-Proliferation Treaty (NPT) which it ratified in 1992 as a nuclear weapons state. Euratom safeguards apply in France and cover all civil nuclear facilities and materials.
In addition, IAEA applies its safeguards activities in accordance with the trilateral "voluntary offer" agreement between France, Euratom and the IAEA which entered into force in 1981.
France undertook nuclear weapons tests 1960-95 and ceased production of weapons-grade fissile materials in 1996. Since then it has ratified the Comprehensive Test Ban Treaty.
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AOG - The Dubai Electricity & Water Authority (DEWA) is to invest around $22bn on new energy projects across the next five years, with the renewables sector accounting for an increasing share of electricity generation, according to CEO Saeed Mohammed Al Tayer.
TRANSCANADA - TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada or the Company) announced net income attributable to common shares for fourth quarter 2017 of $861 million or $0.98 per share compared to a net loss of $358 million or $0.43 per share for the same period in 2016. For the year ended December 31, 2017, net income attributable to common shares was $3.0 billion or $3.44 per share compared to net income of $124 million or $0.16 per share in 2016.
ROSATOM - February 13, 2018, Moscow. – ROSATOM and the Ministry of Scientific Research and Technological Innovations of the Republic of Congo today signed a Memorandum of Understanding on cooperation in the field of peaceful uses of atomic energy.
FRB - Industrial production edged down 0.1 percent in January following four consecutive monthly increases. Manufacturing production was unchanged in January. Mining output fell 1.0 percent, with all of its major component industries recording declines, while the index for utilities moved up 0.6 percent. At 107.2 percent of its 2012 average, total industrial production was 3.7 percent higher in January than it was a year earlier. Capacity utilization for the industrial sector fell 0.2 percentage point in January to 77.5 percent, a rate that is 2.3 percentage points below its long-run (1972–2017) average.