Nuclear Power in Spain
(Updated January 2017)
- Spain has seven nuclear reactors generating a fifth of its electricity.
- Its first commercial nuclear power reactor began operating in 1968.
- A new uranium mining project is commencing.
- Government commitment to the future of nuclear energy in Spain has been uncertain, but has firmed up as the cost of subsidising renewables becomes unaffordable.
Electricity consumption in Spain had been increasing steadily until 2008 but has since levelled off, and in 2012 it declined 1.9% due to Spain's economic recession. Per capita it is about 4900 kWh/yr.
Electricity production in 2014 was 279 TWh gross, 57 TWh (20%) of this from nuclear power, 47 TWh from gas, 45 TWh from coal, 14 TWh from oil, 52 TWh from wind, 43 TWh from hydro, 14 TWh from solar, and 6 TWh from biofuel and wastes. 3.5 TWh net was exported, some (0.9 TWh net) to Portugal, as in preceding years. Other exports are to Morocco through a 1400 MWe interconnector which can also occasionally draw upon that country’s hydro resources (6 TWh net export in 2014). Spain is essentially separate from the EU grid – a small amount of power can be traded with France (3.5 TWh net import in 2014). Electricity self-sufficiency is a major policy consideration. Provisional figures for 2015 are 280 TWh total, of which 57 TWh nuclear, 55 TWh coal, 51 TWh gas, 15 TWh oil, 31 TWh hydro, 49 TWh wind, and 14 TWh solar.
Total generating capacity was 106.5 GWe in 2012, 7.4 GWe of this nuclear. Wind capacity at the end of 2014 reached 23 GWe, with a guaranteed feed-in tariff. Solar has also been promoted with a feed-in tariff of about €0.30 /kWh, but the take-up was so high that the government had to renege on its subsidy commitments in 2010 after investments had been made, almost halving those for large plants. The country has spent an average of €4.75 billion per year on renewables subsidies since 2004. The government announced that it would award no further feed-in tariff contracts after the end of 2012 for special regime suppliers – renewables and small generators, which have priority market access. See section on Energy Reform Bill below.
A PricewaterhouseCoopers study in 2015 showed that the nuclear industry contributed a total of €2.78 billion to Spain's gross domestic product (GDP) in 2013, representing 0.27% of total GDP. The industry's direct contribution to GDP was €1.97 billion, or 0.19% of total GDP. The total tax contribution of the industry in 2013 was €1.14 billion, of which €781 million was taxes incurred, which represented a cost for companies, and €360 million in taxes as a result of their business.
Nuclear power and industry development
In 1964 construction started on the first of three nuclear power reactors – Jose Cabrera, Zorita, a small pressurised water reactor. Two years later construction of Santa Maria de Garona, a medium-sized boiling water reactor was started, followed two years later by Vandellos 1, a medium-sized gas-cooled reactor similar to UK's Magnox units. This first generation of Spanish units – all turnkey projects – gave practical experience with three different designs, and led to a focus largely on PWR types in the 1970s.
In 1972 ENUSA (Empresa Nacional del Uranio, SA, now now ENUSA Industrias Avanzadas SA), a state-owned company, was set up to take over all of the nuclear front-end activities.
In the early 1970s construction was started on a second generation of seven reactors, five of which were completed. These involved local engineering companies Empresarios Agrupados and INITEC and the state-owned manufacturer ENSA (Equipos Nucleares SA).
In the early 1980s, construction of a third generation of five plants was started, but following a 1984 moratorium following the election of a socialist government, only two were completed – Trillo 1 and Vandellos 2. In 1994 the moratorium was confirmed and the units under construction and immediately planned were abandoned. These comprised two 1000 MWe Westinghouse reactors at Limoniz near Bilbao in Basque region, which were ready to run, two 975 MWe GE reactors at Valdacaballeros in Badajoz region, which were 70% and 60% complete, and Trillo 2, a planned German PWR. A total of €5.7 billion compensation has been paid to Iberdrola and Endesa from 1994 through to 2015. The plants concerned were dismantled and the land sold. As well as these plants, plans for units at Deva and Tudela on the north coast, at Lugo and Sayago on the Portuguese border, and a 6000 MWe plant at Ispaster in Basque region were abandoned.
In February 2011 parliament removed a legal provision limiting nuclear plant operating lives to 40 years. The conservative government elected in November 2011 removed the 1984 moratorium, and early in 2012 an industry report recommended in principle 20-year life extensions.
The Socialist government to 2011 had come to power on an anti-nuclear platform, but apart from opposing the licence renewal for the Santa Maria de Garona plant, an early BWR-3 model, it became increasingly positive about nuclear power. In 2011 the responsible minister said that nuclear plants are "essential for the supply of electricity in Spain" and that almost all nuclear power units "will be open, operating and even repowering" until 2021. Also he said that "nuclear energy will be useful as a source of electricity for cars," which the government was promoting, hoping to have one million electric vehicles on the road by 2014. However, that government remained opposed to new nuclear plant construction. The Socialist government's anti-nuclear policy was never translated in to legislation. The November 2011 election brought about a change of government which revisited the decision to close Garona, potentially allowing operation to 2019 (see below).
Nuclear plant ownership and operation is mostly by the Spanish-based but now international utility Endesa SA (originally Empresa Nacional de Electricidad S.A) and Iberdrola. Endesa is 92% owned by Italy's Enel (though it is selling down to 75%). Endesa and Iberdrola have a joint venture operating company: Asociacion Nuclear Asco-Vandellos (ANAV) which covers the 40% of the country's nuclear capacity, in Catalonia. Another joint operating company is Centrales Nucleares Almaraz-Trillo (CNAT), covering the central and west capacity. Centrales Nucleares del Norte (Nuclenor) owns and operated the Santa Maria de Garona plant in the northern province of Burgos. Nuclenor is also owned by Iberdrola and Endesa (50% each), and pioneered nuclear generation in Spain.
In January 2015 Gas Natural Fenosa (which took over Union Fenosa in 2009) said it would move its nuclear assets to its Gas Natural Generacion subsidiary.
Spain is notable for power plant uprates. It has a program to add 810 MWe (11%) to its nuclear capacity through upgrading its nine reactors by up to 13%. For instance, the Almaraz nuclear plant is being boosted by more than 5% at a cost of US$ 50 million. Some 519 MWe of the overall increase is already in place.
Cofrentes was uprated 2% in 1988, another 2.2% in 1998, 5.6% in 2002 and 1.9% in 2003, taking it to 112% of original capacity. Tentative plans will take it to 120% later in the decade.
Licence renewal and taxes
Licence renewal for the Santa Maria de Garona plant came up for review in 2009, and in June the Nuclear Safety Council (CSN) recommended that a 10-year extension be granted, to 2019. The CSN said that plant owner and operator Nuclenor had implemented a comprehensive work program to keep the 40-year old reactor fully serviceable, having spent some €155 million on it. The Socialist government, with a policy then of closing down Spanish nuclear plants as early as possible, granted only a four-year licence extension, to July 2013. In January 2012 the new conservative government referred the matter back to CSN with a view to revoking the 2009 decision and allowing operation to 2019. CSN again approved this and in July 2012 the government removed the 2013 operational limit, subject to Nuclenor renewing the licence.
However, Nuclenor delayed its application until new government rules and taxes were specified, since €480 million in investment would be required to take the plant to mid 2019. Pending government plans involved heavy taxes* – 7% – on electricity generation, amounting to some EUR 1 c/kWh for nuclear, plus a tax of €2190 per kilogram on used nuclear fuel discharged – about €315 million per year across the industry. In addition, utilities must make provision in their accounts for partially used fuel still in the reactor – this would amount to over €500 million per year. Having missed the September deadline to apply for licence renewal from July 2013, Garona was shut down and promptly defueled in December 2012, rather than paying taxes on the plant of €153 million in 2013 and €374 million to 2019, required under the energy reform bill which was passed in December. It was declared officially shut down in July 2013.
In May 2013 Nuclenor approached the government to seek a resolution of the impasse, which might allow the reactor to restart. The CSN said it supported the appeal, and the Ministry should allow Nuclenor to submit a request for a one-year extension of its operating licence before June. However it would need to complete some safety modifications before loading fuel. The Ministry responded in mid June by confirming the mid-2013 shutdown, and saying it was “based solely on economic considerations”. In July 2014 Nuclenor was fined €18.4 million by the financial regulator for shutting down the plant earlier than originally authorised. Nuclenor is appealing. It said that Nuclenor committed "a very serious violation" of the country's laws governing the electricity sector by reducing production capacity or supply of electricity without permission.
In February 2014 cabinet approved a royal decree that allows recently-shutdown plants to apply within 12 months for their operating licences to be renewed, if the shutdown was not for safety reasons. This opened the possibility of restarting Garona if the company could secure a suitable deal. In May 2014 Nuclenor applied to the Ministry of Industry & Energy for a renewal of its operating licence to 2031, enough to justify spending €120 million on upgrading and also payment of the taxes. At the end of July 2014 the CSN voted in favour of issuing a technical instruction to Nuclenor on documentation and additional requirements for the Garoña operating licence renewal, and at the end of September 2014 the company submitted a detailed work plan for meeting these substantial requirements. Nuclenor said it hoped to restart the unit within a year and to operate it until 2031, this period being necessary to justify the investment involved. Nuclenor announced in March 2015 that inspections conducted in November and December indicated no manufacturing defects in the reactor pressure vessel and that it was in a good condition, enabling the unit to operate safely when restarted. The reactor remains closed while engineering work on CSN requirements proceeds, and in November 2015 over 400 people were working on the plant. CSN was expected to decide on licence renewal for the plant in November 2016, but this did not eventuate.
Licence renewal for Almaraz 1&2 came up for review in 2010, and in April the CSN recommended that a 10-year extension be granted, to 2020. It said it had verified that the plant owners – Iberdola, Endesa and Union Fenosa – had kept commitments made at the last extension in 2000, and added that their decision was based on a thorough review of the plant's condition. The Ministry of Industry, Tourism & Trade then approved the CSN recommendation. In January 2011 the government approved 70 MWe uprates for both reactors, with 68 MWe for unit 1 being imminent, the engineering work having been already done.
In June 2010 the CSN recommended a 10-year licence extension for Vandellos 2, and this was approved by the Ministry in July. In February 2011 it recommended a 10-year extension for Cofrentes, and in July 2011 it recommended the same for Asco 1&2. These were agreed in March and September respectively. In October 2014 the CSN granted a 10-year licence renewal for Iberdrola’s Trillo, subject to establishment of ageing management programs. This was confirmed by the Ministry in November.
In May 2016 Catalonia introduced a capacity tax on nuclear power plants in its territory, affecting three reactors – Asco 1&2 and Vandellos 2. The rate is €44.14 per MWe per year.
Power reactors operating in Spain
||Owner (%); operator
||Iberdrola 53%, Endesa 36%, Gas Natural Fenosa 11%; CNAT
||Endesa (100%); ANAV
||Endesa (85%), Iberdrola (15%); ANAV
||Iberdrola (100%); Iberdrola
||Iberdrola (48%), Gas Natural Fenosa (34.5%), EDP (15.5%); CNAT
||Endesa (78%), Iberdrola (28%); ANAV
Capacity figures from IAEA PRIS database March 2016.
The Program of Advanced Nuclear Plants is working on the development of Westinghouse AP600 and GE Advanced Boiling Water Reactor. Spain is also participating in the development of European Utility Requirements (EUR) in relation to advanced nuclear technology and is part of the International Atomic Energy Agency's INPRO project.
Energy Reform Bill
The Energy Reform Bill passed in December 2012 threatened the viability of renewable projects as subsidies were reduced, and may increase dependence on coal and also imported gas. Early in June 2013 the government announced substantial reduction in the renewables subsidies since they accounted for almost half of the €20 billion annual costs of the nation's electrical system, and capped retail tariffs were insufficient to pay for the open-ended cost of escalating renewable inputs. Subsidies for renewables totalled about €9 billion in 2012 and €9.3 billion in 2013. A deficit of €30 billion had built up since 2005, according to the energy and competition regulator CNMC.
The 2012 reforms had started to address this deficit, then in July the Ministry of Industry, Energy and Tourism introduced further ‘definitive reforms’ to reduce the deficit by €4.5 billion per year. These measures will cost utilities €2.7 billion per year and consumers €400 million in 2013 and €900 million per year thereafter, while the government will cover a further €2 billion in 2013 and €900 million per year thereafter of costs. Solar companies are expected to be worst affected, due to debt load estimated at €30 billion, and widespread financial distress was predicted by solar and wind industry groups. In 2000, the government had promised more than 20 years of large subsidies, and investment proceeded on this basis. In May 2013 renewables received an average subsidy of €100/MWh. The reforms remove the feed in tariffs system and substitute a new Regulated Asset Value-based system (or "reasonable profitability" system).
At the start of 2014 the impact of the switch to capacity-based incentives was unclear. Enel Green Power said it expected to lose FiTs for one-third of its capacity installed before 2005, mostly for wind. All renewable sources now have to take the pool price and there follows some uncertain assessment regarding “reasonable profitability”. In April 2014 CNMC said that proposed reductions in subsidies for renewables would cost producers some €1.7 billion in 2014 (wind €400 million, others €150-250 million each). The FiT modifications would determine the rate of return for existing renewable energy companies at 7.4% and for future ones at 7.5%, compared with more than 10% in the past. Iberdrola and Acciona were reviewing their business plans.
A new Renewable Energy Law was passed in June 2014 in order to reduce subsidies for renewables by €1.7 billion per year and control the tariff deficit which had reached €26 billion. The average payout from January to April 2014 was €90.70/MWh, total €3.39 billion. The Decree applies to 39 GWe of renewable capacity and is designed to ensure an annual return of about 7.4% on invested capital over a project’s lifetime (20 years for wind plants). The capacity complement ranges up to €105/GWe for the newest wind plants, but tapers off to 2004 and older installations, mostly wind farms built before 2004, will cease receiving subsidies. The pool price calculation has caps and floors – for 2014 the caps are €52-56 and the floors €40-44, and these increase slightly to 2017.
In May 2016 the European Commission gave the government permission to disburse €2.13 billion of public funds to the operators of 26 “uncompetitive” coal mines that are due to be shut down by 2018. The aid aims to cover production losses of the mines and compensation to workers.
Uranium was discovered in Salamanca during the 1950s. Production commenced in 1974 at ENUSA's Fe mine (Mina Fe), which grew to become the largest uranium mine in the Iberian Peninsula. It produced over 4000 tU. The mine closed in 2000 due to low uranium prices, though minor output continued to 2002 from decommissioning, and the mining areas have since been restored. One large pit and three small ones are involved. At Mina Fe, the Elefante Plant was a bacterial heap leach facility which was replaced by the 800 tU/yr Quercus mill in 1993. The Quercus plant used a combination of heap leach and dynamic leach to 2003.
Australian-based Berkeley Energia Ltd owns uranium properties in Salamanca province and also pursued a joint venture with ENUSA to develop the Salamanca State Reserves, using the Quercus mill (Saelices el Chico).* In July 2012 a new agreement between Berkeley and ENUSA gave Berkeley full rights to the Alameda and Villar deposits, in two state reserves. The extensively-drilled Alameda and Esperanza/Villar deposits, are about 10km from Aguila and Quercus mill, and contiguous with other Berkeley leases against the Portugal border. Villar and Alameda North have 3660 tU inferred resources which are now part of Berkeley’s Salamanca project. Almeda’s 8130 tU is mostly indicated resources. A 2.5% royalty will apply. However, Berkeley waives its rights to mine in any state reserves where ENUSA has undertaken rehabilitation, or to use the Quercus mill. The 2009 cooperation agreement was terminated.
Berkeley's own Retortillo area, including some smaller deposits, is 35 km northeast of Alameda. While Berkeley attempted to progress the ENUSA JV project, in October 2011 the company turned its attention back to its own deposits where exploration had ceased in 2008, and it applied for a mining licence for these as Salamanca 1, using bacterial heap leaching rather than toll processing through the Quercus mill (as envisaged with the JV). A preliminary feasibility study was completed in 2011 showing pre-mining cost of €62.5 million and mine life of ten years producing 9750 tU.
A pre-feasibility study in 2013 using only the 13,270 tU estimated resources of Alameda and Retortillo was based on open pit mining with acid heap leaching at both sites, a central processing plant at Retortillo and a remote ion exchange operation at Alameda, with resin trucked to the main plant. Initial capital cost would be US$ 95 million, followed by $74 million to develop Alameda. It indicated an 11-year mine life averaging 1000 tU/yr at $25/lb U3O8.
Zona 7 with 12,080 tU (including 10,700 tU indicated resource at 0.062%U) is about 10 km from the proposed treatment plant at Retortillo, and due to its relatively high grade (0.05%U) and shallow depth it is being integrated with development plans. Retortillo has 5150 tU as measured and indicated resources, and a little more as inferred in satellite deposits.
In April 2014 Berkeley was granted a 30-year mining licence for Retortillo. A definitive feasibility study is underway. Possible satellite operations include initially Zona 7 (11,600 tU, 10 km from Retortillo), and in July 2015 CSN approval represented the first of three steps in authorizing the treatment plant as a radioactive facility in the name of Berkeley Minera Espana. In October 2015 the company had all approvals in hand for project infrastructure. Some infrastructure development started in March 2016, major plant items were ordered late in 2016 and full construction of the mine and plant started early in 2017. Production, ramping up to 1700 tU/yr, is expected from 2018.
The Gambuta deposit 145 km southeast has 4250 tU as inferred resource and is considered part of the Salamanca project.
Overall, Berkeley (March 2016) claims 34,500 tU resources for the Salamanca project (JORC-compliant) at average grade 0.041%U, with 200 ppm U3O8 cut-off. An updated pre-feasibility study based only on 23,600 tU measured and indicated resources showed that incorporating Zona 7 transformed the economics of the project. It increased the mine life from 11 to 17.5 years (at average 1150 tU/yr) and reduced the operating costs from US$24.60 to US$15.60 per pound of U3O8 produced “during steady state operations” (1650 tU/yr), and reduced the initial capital cost from $95 million to $81 million. A definitive feasibility study in July 2016 showed 1700 tU/yr production over ten years at $15.06/lb.
The 1600 tonnes of uranium used in Spain each year is imported. ENUSA has a 10% stake in mining in COMINAK, mining at Akouta in Niger.
Fuel cycle facilities
There are no conversion or enrichment facilities in Spain, but ENUSA owns 11% of Eurodif, with a large diffusion enrichment plant at Marcoule in France. It also contracts for other conversion and enrichment services abroad.
ENUSA's Juzbado plant in Salamanca, commissioned in 1985, produces BWR and PWR fuel elements for Spain's reactors and also supplies other customers in Europe. In 2008 more than half of its 921 fuel assemblies were exported.
GNF ENUSA Nuclear Fuel S.A. (GENUSA) is jointly owned by Global Nuclear Fuel-Americas, LLC (a GE-led joint venture with Hitachi and Toshiba) as majority owner, and ENUSA. It was set up in 1989 and markets BWR fuel in Europe.
In 1991, ENUSA with Westinghouse Electric Corporation and British Nuclear Fuel Ltd (BNFL), created the European Fuel Group (EFG), with the purpose of a joint action in the European PWR nuclear fuel market.
Radioactive waste management
ENRESA (Empresa Nacional de Residuos Radiactivos SA) was established in 1984 as a state-owned company to take over radioactive waste management and decommissioning of nuclear plants. It is now the only state-owned part of the nuclear fuel cycle in Spain.
It drew up a General Plan for radioactive wastes which was approved by parliament in 1999. It is based on nuclear power plant lives of 40 years, and addresses the need to manage almost 200,000 cubic metres of low and intermediate-level wastes and 10,000 cubic metres of used fuel and other high-level wastes.
ENRESA's low and intermediate-level waste storage facility is at El Cabril, Cordoba. It has operated since 1961. In July 2016 Enresa was given approval by the Nuclear Safety Council to operate the new VLLW disposal facility there, which has a storage capacity of over 17,000 m3.
Since 1983 Spain's policy has been for an open fuel cycle, with no reprocessing. The 1999 plan for used fuel envisaged initial storage at each reactor for ten years. Some temporary storage for dry casks at Trillo up to 2010 was planned, and establishment of a longer-term centralised facility would follow. Meanwhile research would progress on deep geological disposal as well as transmutation, with a decision on disposal to be made after 2010. Granite, clay and salt formations were under consideration.
In mid-2006 Parliament approved ENRESA's plans to develop a temporary central nuclear waste storage facility by 2010, and the CSN approved its design, which was similar to the Habog facility near the Borssele power plant in the Netherlands. In December 2009 the government called for municipalities to volunteer to host this €700 million Almacen Temporal Centralizado (ATC) facility for high-level wastes and used fuel. The government offered to pay up to €7.8 million annually once the facility is operational. It is designed to hold for 100 years 6700 tonnes of used fuel and 2600 m3 of intermediate-level wastes, plus 12 m3 of high-level waste from reprocessing the Vandellos 1 fuel. The facility is to be built in three stages, each taking five years. Asco and Villar de Canas were two towns among eight that volunteered, attracted by the prospect of €700 million over 20 years and the annual direct payments, plus many jobs. A campaign of fearmongering was mounted by nuclear detractors to dissuade residents of the eight towns, and some regional governments were also opposed.
In September 2011 the Ministry for Industry announced its selection and rankings:
- Zarra (Valencia) 736 points.
- Asco (Tarragona) 732 points.
- Yebra (Guadalajara) 714 points.
- Villar de Canas (Cuenca) 692 points.
In December 2011 the Ministry announced that Villar de Canas had been selected, though only a 60-year storage period was mentioned. Pending construction, used fuel remains at individual power plants. Several, including Asco and Trillo (as well as Jose Cabrera), are using dry storage, Asco with Holtec Hi-Storm casks. In July 2015 the CSN confirmed that Villar de Canas was suitable for the ATC and that ENRESA could begin preliminary site works while the regulatory process continued. The ATC facility will provide storage for some 12,816 cubic metres of wastes for 60 years, by which time a repository for permanent disposal should be available.
Holtec has licensed and supplied its HI-STAR 100 dual-purpose metal casks to transport fuel from the individual power plants to the ATC central storage facility. The casks can also store used fuel.
Waste management and decommissioning is funded by a levy of about 1% on all electricity consumed.
In Spain, once a plant is shut down and a decommissioning permit is granted, control is transferred from owners and operators
to Enresa, which is responsible both for decommissioning and long-term management of radioactive waste.
Vandellos 1, a 480 MWe French UNGG gas-graphite reactor, was closed down in mid 1990 after 18 years operation, due to a turbine fire which made the plant uneconomic to repair. In 2003 ENRESA concluded phase 2 of the reactor decommissioning and dismantling project, which allows much of the site to be released. The cost of the 63-month project was €93 million. After 30 years in Safestor, when activity levels have diminished by 95%, the remainder of the plant will be removed.
In April 2006 the 142 MWe Jose Cabrera (Zorita) PWR plant was closed after 38 years operation. Rather than using Safstor, dismantling the plant is being undertaken over eight years from 2010 by Enresa – on schedule and within budget, the total cost is estimated at €150 million at 2016 prices. About 4% of the plant's constituent material will need to be disposed of as radioactive waste, the rest can be recycled, including 43 tonnes of internal components. Used fuel is stored at site in Holtec Hi-Storm casks.
In December 2012 the Santa Maria de Garona plant, an early BWR-3 model of 446 MWe net, operating since 1971, was closed down after 41 years operation. Nuclenor operated the plant on behalf of its owners, Iberdrola and Endesa. However, there is some prospect of restarting the plant (see main section above).
Regulation and safety
In 1980 the Consejo de Seguridad Nuclear (CSN – nuclear safety council) was set up to take over both nuclear safety and radiological protection matters. The CSN was overhauled in 2007, following an incident in 2004 at Vandellos 2, and the scope for penalties increased.
In 2009 Endesa was fined €15.4 million over a radioactive release incident during a refuelling operation at Asco 1 in 2007. There were six charges of breaching safety rules. The incident was rated 2 on the INES scale.
Licensing is under a 1964 law (amended) and 1999 regulations by the Economic Ministry, advised by CSN and Ministry of Environment.
Civil liability for nuclear damage is covered under international conventions to which Spain is party – the IAEA Vienna Convention and the OECD Paris and Brussels Conventions. Operators need to cover €150 million.
Spain is a party to the Nuclear Non-Proliferation Treaty (NPT) as a non-nuclear weapons state. Its safeguards agreement under the NPT came into force in 1967 and in 1985 it came under the Euratom safeguards arrangement. In 1998 it signed the Additional Protocol in relation to its safeguards agreements with both IAEA and Euratom.
IAEA, Country Nuclear Power Profiles.