Emerging Nuclear Energy Countries
(Updated May 2015)
- Over 45 countries are actively considering embarking upon nuclear power programs.
- These range from sophisticated economies to developing nations.
- The front runners after Iran are UAE, Turkey, Vietnam, Belarus, Poland and possibly Jordan.
Nuclear power is under serious consideration in over 45 countries which do not currently have it (in a few, consideration is not necessarily at government level). For countries listed immediately below in bold, nuclear power prospects are more fully dealt with in specific country papers:
- In Europe: Italy, Albania, Serbia, Croatia, Portugal, Norway, Poland, Belarus, Estonia, Latvia, Ireland, Turkey.
- In the Middle East and North Africa: Iran (reactor now operating), Gulf states including UAE, Saudi Arabia, Qatar & Kuwait, Yemen, Israel, Syria, Jordan, Egypt, Tunisia, Libya, Algeria, Morocco, Sudan.
- In west, central and southern Africa: Nigeria, Ghana, Senegal, Kenya, Uganda, Namibia.
- In Central and South America: Cuba, Chile, Ecuador, Venezuela, Bolivia, Peru.
- In central and southern Asia: Azerbaijan, Georgia, Kazakhstan, Mongolia, Bangladesh, Sri Lanka
- In SE Asia: Indonesia, Philippines, Vietnam, Thailand, Malaysia, Singapore, Australia, New Zealand.
- In east Asia: North Korea.
Despite the large number of these emerging countries, they are not expected to contribute very much to the expansion of nuclear capacity in the foreseeable future – the main growth will come in countries where the technology is already well established. However, in the longer term, the trend to urbanisation in less-developed countries will greatly increase the demand for electricity, and especially that supplied by base-load plants such as nuclear. The pattern of energy demand in these countries will become more like that of Europe, North America and Japan.
Some of the above countries can be classified according to how far their nuclear programs or plans have progressed:
- Power reactors under construction: UAE, Belarus
- Contracts signed, legal and regulatory infrastructure well-developed: Lithuania, Turkey.
- Committed plans, legal and regulatory infrastructure developing: Vietnam, Jordan, Poland, Bangladesh, Egypt.
- Well-developed plans but commitment pending: Thailand, Indonesia, Kazakhstan, Saudi Arabia, Chile; or commitment stalled: Italy.
- Developing plans: Israel, Nigeria, Kenya, Malaysia, Morocco.
- Discussion as serious policy option: Namibia, Mongolia, Philippines, Singapore, Albania, Serbia, Croatia, Estonia & Latvia, Libya, Algeria, Kuwait, Azerbaijan, Sri Lanka, Tunisia, Syria, Qatar, Sudan, Venezuela, Bolivia, Peru.
- Officially not a policy option at present: Australia, New Zealand, Portugal, Norway, Ireland, Kuwait, Cuba.
A September 2010 report by the International Atomic Energy Agency (IAEA) on International Status and Prospects of Nuclear Power said that some 65 countries without nuclear power plants “are expressing interest in, considering, or actively planning for nuclear power” at present, after a “gap of nearly 15 years” in such interest worldwide. Of these 65 un-named countries, it said that 21 are in Asia/Pacific, 21 in Africa, 12 in Europe (mostly eastern Europe), and 11 in Latin America. However, of the 65 interested countries, 31 are not currently  planning to build reactors, and 17 of those 31 have grids of less than 5 GW, “too small to accommodate most of the reactor designs on offer.” The report added that technology options may also be limited for countries whose grids are between 5 GW and 10 GW.
Of the countries planning reactors, at September 2010: 14 “indicate a strong intention to proceed” with introduction of nuclear power; seven are preparing but haven’t made a final decision, 10 have made a decision and are preparing infrastructure, two have ordered a new nuclear power plant and one has a plant under construction, according to the IAEA assessment (see below re IAEA 'milestone' approach). These are identifiable in our development breakdown above, though Belarus and Poland have been moved up one category as of early 2012, and Saudi Arabia in mid 2012.
However, by September 2012 the picture was less positive for the leading 14 countries, and the IAEA expected only seven newcomer countries to launch nuclear programs in the near term. It did not name these, but Lithuania, UAE, Turkey, Belarus, Vietnam, Poland, and Bangladesh appear likely candidates. Others had stepped back from commitment, needed more time to set up infrastructure, or did not have credible finance.
One major issue for many countries is the size of their grid system. Many nuclear power plants are larger than the fossil fuel plants they supplement or replace, and it does not make sense to have any generating unit more than about one tenth the capacity of the grid (maybe 15% if there is high reserve capacity). This is so that the plant can be taken offline for refueling or maintenance, or due to unforeseen events. The grid capacity and quality may also be considered regionally, as with Jordan for instance. In many situations, as much investment in the grid may be needed as in the power plant(s). Kenya sought to evaluate its grid system before considering the generation options.
Another issue is that of licensing reactor designs. Emerging countries generally do not have the expertise for this, and must initially rely on design licensing by countries such as UK, USA, and France while they focus on building competence to license the actual operation of plants.
IAEA support for new nuclear programs
In all countries governments need to create the environment for investment in nuclear power, including professional and independent regulatory regime, policies on nuclear waste management and decommissioning, and involvement with international non-proliferation measures and insurance arrangements for third party damage.*
In different countries, institutional arrangements vary. Usually governments are heavily involved in planning, and in developing countries also financing and operation. As emerging nuclear nations lack a strong cadre of nuclear engineers and scientists, construction is often on a turnkey basis, with the reactor vendor assuming all technical and commercial risks in delivering a functioning plant on time and at a particular price. Alternatively the vendor may be set up a consortium to build, own and operate the plant. As the industry becomes more international, new arrangements are likely, including public-private partnerships.
The IAEA has published a small book Considerations to Launch a Nuclear Power Programme (2007 ) which addresses the issues involved in a country deciding upon and implementing a nuclear power program. In particular it looks at those considerations before a decision is made, before construction starts and subsequently. It then briefly covers twelve factors for consideration.
According to the IAEA in mid 2010, 20 new countries expected to have nuclear power on line by 2030, though since then some have pulled back and only seven new countries are expected to have capacity on line by the early 2020s.
The IAEA sets out a phased 'milestone' approach to establishing nuclear power capacity in new countries*, applying it to 19 issues. In broad outline the three phase approach is (milestones underlined):
- Pre-project phase 1 (1-3 years) leading to knowledgeable commitment to a nuclear power program, resulting in set up of a Nuclear Power Program Implementing Organisation (NEPIO). This deals with the program, not the particular projects after phase 2.
- Project decision-making phase 2 (3-7 years) involving preparatory work after the decision is made and up to inviting bids, with the regulatory body being established. In phase 2 the government role progressively gives way to that of the regulatory body and the owner-operator.
- Construction phase 3 (7-10 years) with regulatory body operational, up to commissioning and operation.
In 2009 the IAEA began offering Integrated Nuclear Infrastructure Review (INIR) missions to assess national developments, and six INIR missions were conducted during 2009-11 to evaluate the status of countries’ nuclear infrastructure development. The first three were to Jordan, Indonesia and Vietnam. followed by others to Bangladesh, Belarus, Thailand and UAE to the end of 2012. In 2013 INIR missions were to South Africa – the first country with an operating nuclear power program that has requested this service – Poland and then Turkey. In 2014 an INIR mission to Nigeria is planned. Several countries including Egypt, Kenya, and Malaysia have also expressed interest.
More broadly than these INIR missions are Nuclear Energy System Assessments (NESA), using the International Project on Innovative Nuclear Reactors and Fuel Cycles (INPRO) methodology to help countries develop long-term national nuclear energy strategies. The INPRO methodology identifies a set of Basic Principles, User Requirements, and Criteria in a hierarchical manner as the basis for the assessment of an innovative and sustainable nuclear system. The NESA program helps members “in gaining public acceptance, getting assistance in nuclear energy planning in their country, and increasing awareness of innovations in nuclear technologies”. NESAs have been carried out in Belarus, Kazakhstan, Ukraine and Indonesia.
The IAEA also has an Integrated Regulatory Review Service (IRRS) to scrutinise the regulatory structures in particular countries, upon invitation from the government. This may be used for countries embarking upon nuclear power programs, as in Poland early in 2013.
WANO and ASN support for new nuclear programs
For new entrants to the nuclear industry which are moving towards fuel loading in their first reactor, the World Association of Nuclear Operators (WANO) offers pre-startup peer reviews as part of its peer review program, particularly to address the situation of new plants in countries and organisations without previous nuclear power experience. As of early 2011 it had undertaken 12 such reviews and with the great increase in construction happening, had 62 scheduled for the next five years. WANO’s goal is to do a pre-startup review on every new nuclear power plant worldwide. The reviews seek to evaluate how each operating organization is prepared for startup and make recommendations for improvements based on the collective experience of the world industry. The transition between construction and operation at a nuclear power plant is a delicate period, and many incidents occur during the early months of plant operation - both Three Mile Island 2 and Greifswald 5 were almost new units when accidents destroyed them.
In January 2008, the French Nuclear Safety Authority (ASN) indicated that it would pay attention to new nuclear power projects in countries with no experience in this area. It said that the development of nuclear industry in a country needs at least 10 to 15 years in order to build up skills in safety and control and to define a regulatory framework. In a June 2008 position paper the five-member commission of ASN said that building the infrastructure needed to safely operate a nuclear power plant required time and that it would be selective about providing assistance. The commissioners said ASN would give priority to countries using French technologies, that it would apply "geophysical, economic, political, social, and technical" criteria, and require countries to be party to relevant international treaties. ASN said it takes at least five years to set up the legal and regulatory infrastructure for a nuclear power program, two to ten years to license a new plant, and about five years to build a power plant. That means a "minimum lead time of 15 years" before a new nuclear power plant can be started up in a country that does not already have the required infrastructure.
These comments relate to France's creation of Agency France Nuclear International (AFNI) under its Atomic Energy Commission (CEA) to provide a vehicle for international assistance. AFNI will be focused on helping to set up structures and systems to enable the establishment of civil nuclear programs in countries wanting to develop them, and will draw on all of France's expertise in this. It will be guided by a steering committee comprising representatives of all the ministries involved (Energy, Foreign Affairs, Industry, Research, etc) as well as representatives of other major French nuclear institutions including the CEA itself and probably ASN, though this is yet to be confirmed.
The rest of this paper documents progress in a number of countries. Where an individual paper on the particular country exists (as indicated), more detail will be found there.
Due to the high reliance on oil and gas, as well as imports, Italy's electricity prices are 45% above EU average.
Italy today is now the only G8 country without its own nuclear power, and is the world's largest net importer of electricity (effectively, some 15% of its needs), mostly nuclear power from France . This is equivalent to output from about 6 GWe of base-load capacity.
However, Italy had been a pioneer of civil nuclear power and built several reactors which operated 1963-90. But following a referendum in November 1987, provoked by the Chernobyl accident 18 months earlier, work on the nuclear program was largely stopped. In 1988 the government resolved to halt all nuclear construction, shut the remaining reactors and decommission them from 1990. Italy then remained largely inactive in nuclear energy for 15 years.
In 2004 a new Energy Law opened up the possibility of joint venture with foreign companies in relation to nuclear power plants and importing electricity from them. This resulted from a clear change in public opinion, especially among younger people favouring nuclear power for Italy.
In 2005 Electricite de France and Italy's Enel signed a co-operation agreement which gives Enel some 200 MWe from the new Flamanville-3 EPR nuclear reactor (1700 MWe) in France, and potentially another 1000 MWe or so from the next five such units built. As well as the 12.5% share, Italy's electric utility Enel will also be involved in design, construction and operation of the plants, which will enhance Italy's power security and improve its economics. Enel subsequently announced it was taking a 12.5% share in the second EPR being constructed in France, at Penly.
Enel has also bought 66% of the Slovak Electric utility which operates six nuclear power reactors, and Enel's investment plan for SE approved in 2005 by the Slovak government includes EUR 1.6 billion for completion of Mochovce nuclear power plant - 942 MWe gross. Enel then took its equity in Spain’s Endesa, which has a major stake in three nuclear reactors, to 92% in February 2009.
In May 2008 the new Italian government said that it would work towards having 25% of its electricity from nuclear power by 2030, requiring 8 to 10 large new reactors by then. The government introduced a package of nuclear legislation, including measures to expedite licensing of new reactors at existing nuclear power plant sites, and to facilitate licensing of new reactor sites. Enel planned to build new reactors at one of three licensed sites: Garigliano, Latina, or Montalto di Castro. The first two had small early-model reactors operating to 1982 and 1987. At Montalto di Castro two larger reactors were almost complete when the country's November 1987 referendum halted construction.
In January 2011 the Constitutional Court ruled that Italy could hold a referendum on the planned re-introduction of nuclear power, as proposed by an opposition party. The question posed in the referendum, held in mid-June 2011, was whether voters wanted to cancel some 70 legislative and regulatory measures which had been taken by the government over three years to make it possible to build new nuclear power plants. It would not affect plans for a waste repository. In the referendum, the 2009 legislation setting up arrangements to generate 25% of the country's electricity from nuclear power by 2030 was decisively rejected, bringing new nuclear plans to a halt.
Several research reactors are operating, including AGN Constanza (since 1960), Uni of Pavia's LENA Triga II (250 kW, since 1965), ENEA's Tapiro (5 kW, since 1971), ENEA's Triga RC-1 (1 MW, since 1960) and a subcritical assembly.
Ansaldo Nucleare, which in conjunction with Canada's AECL, built Cernavoda 2 in Romania, is also involved with international R&D on new reactor systems.
See also Italy paper for more up to date information.
Albania gets much of its electricity from hydro, and droughts have limited power supply to four hours per day. In 2007 the government proposed construction of a nuclear power plant for both domestic and export supply to Balkans and Italy. In 2009 Croatia supported the proposal, and the two countries agreed to work together on it. The state-owned national utility, Hrvatska Elektroprivreda (Croatian Electricity Company, or HEP) would be in charge of construction works, and most of the power would be supplied to Croatia. It was earlier intended to invite Montenegro and Bosnia to participate, but Montenegro apparently opposes the plans.
In April 2009 Croatian officials said that an agreement was concluded with Albania for the construction of a joint nuclear facility near the Montenegrin border. The two governments formed a working group of five experts each focused on the technical implementation of the project. In January 2010 the government approved the creation of the Agjencia Kombetare Berthamore (National Atomic Agency) to supervise the development of nuclear projects and set up the legal infrastructure. A proposed site for a 1500 MWe plant is in the Shkoder region, on a lake of that name, bordering Montenegro, or at Drac on the north coast, or Durres. Italian utility Enel was looking into the feasibility of a nuclear plant.
The governments of Russia and Serbia in 2009 were holding 'serious negotiations' for the construction of a nuclear plant on Serbian territory as a joint project.
In August 2010, the Serbian government announced that it would take an equity stake in Bulgaria's Belene nuclear plant, possibly of 5%. In November Bulgaria invited Serbia, Croatia and Macedonia – all electricity customers – to take equity of 1% to 2% in the Belene plant.
The country imports about one-fifth of its electricity requirements and is co-owner with Slovenia of the Krsko nuclear plant close to the border. It is considering joining with Slovenia in building a new reactor at Krsko, joining with Hungary in building new nuclear capacity at Paks, or building a plant of its own at one of two identified sites: Dalj or Prevlaka by 2020. A decision is expected late in 2012. In 2010 Croatia rejected an offer to invest in Bulgaria's Belene plant.
Portugal's electricity production is about 47 billion kWh/yr gross and in 2007 this came 27% from coal, 27% from gas and 22% from hydro. Net imports are about 5 TWh/yr from Spain.
Its electricity grid is closely linked with Spain's, so that a large nuclear plant on the Atlantic coast could serve both countries.
In 2004 the government rejected a proposal to introduce nuclear power but this is now being reviewed.
Norway's electricity is almost entirely hydro. In 2007, 137.7 billion kWh gross was generated, from 29.5 GWe of capacity. Exports and imports vary greatly with the season and hydro situation in Scandinavia. In 2004 net imports were 11.5 TWh and in 2005 net exports were 12 TWh, mostly to and from Sweden. In 2006 imports and exports largely balanced. Per capita use is about 23,000 kWh/yr.
Leaders of Norwegian industry want nuclear energy to supplement hydro. They believe nuclear power based on thorium, which Norway has plenty of, will prevent future energy crises.
A government-appointed committee reported in February 2008 that building thorium-fuelled power reactors was a possibility, which could be tested by using thorium fuel in the country's Halden research reactor. The committee also said that the country should strengthen its international collaboration in nuclear energy and develop its human resources in nuclear science and engineering so as to keep the thorium option open as complementary to the uranium option. "The potential contribution of nuclear energy to a sustainable energy future should be recognised."
The Norwegian Radiation Protection Agency has licensed an underground repository inside a mountain for radioactive waste from the country's oil and gas industry. It will hold 6000 tonnes of NORM waste, and 400 tonnes has already been placed there.
Norway has 12 tonnes of used fuel from its Halden research reactor, and early in 2010 a commissioned report recommended that this be sent to Mayak in Russia for reprocessing. In this case the uranium would be used in RBMK reactor fuel and the plutonium recycled in Russia as MOX.
Poland has the largest reserves of coal in the EU (14 billion tonnes); and most of its electricity comes from coal, as well as most of its heat usage. At least half of the country's gas supply comes from Russia, with the price pegged to oil, but this dependence is set to change with the advent of shale gas domestically. Poland's own electricity consumption is forecast to grow by 54% to 2030, but under the EU's strict climate policy targets the country will need to diversify away from coal.
The Polish cabinet decided early in 2005 that for energy diversification and to reduce CO2 and sulfur emissions the country should move immediately to introduce nuclear power, so that an initial plant might be operating soon after 2020. A 2009 resolution by the council of ministers then called for the construction of at least two plants in Poland, or at least 4.6 GWe out of a predicted 52 GWe total capacity - to provide 15% of power, with coal's share falling to 60% by 2030. This plan remains in place.
The five-stage government plan in 2009 envisaged legislation for a regulatory framework in 2010 (passed in May 2011), investor, site, technology and construction arrangements over 2011-13, technical plans and site works 2014-15, construction of the first unit 2016-20 and successive units constructed by 2030. The entity PGE EJ1 is set up to build the first plant and it will have up to 49% private equity. It will be future operator and licensee.
The government approved legislation amending the country's Nuclear Energy Law to “provide for the establishment of a transparent and stable regulatory framework covering the entire investment process” by the National Atomic Energy Agency (PAA), which will oversee construction of the plants. This was passed decisively by parliament in May 2011, by 407 votes to 2. It covers plant operation and the management of radioactive waste and used fuel.
Poland had four 440 MWe Russian VVER-440 units under construction in the 1980s at Zarnowiec, but these were cancelled in 1990 and the components were sold, but the site remained a leading contender for at least 1500 MWe of capacity.
A public opinion poll in December 2006 carried out for the National Atomic Energy Agency showed that 60% supported construction of nuclear power plants to reduce the country's dependence on natural gas and to reduce CO2 emissions. In contrast to NIMBY attitudes elsewhere, 48% said they would favour such a plant being built in their neighbourhood because of its immediate local benefits including lower power cost. A September 2009 poll showed that 70% of Poles would support having a nuclear power plant within 100 km of their homes.
In July 2006 Lithuania invited Poland to join with Estonia and Latvia in building a new large reactor in Lithuania, to replace the Ignalina units being shut down at EU insistence. In February 2007 the three Baltic states and Poland agreed to build a new nuclear plant there, initially of 3200 MWe. In July 2008 the Lithuanian government with energy companies from Latvia, Estonia and Poland (Latvenergo, Eesti Energia and Polska Grupa Energetyczna) established the Visaginas project development company Visagino Atomine Elektine (VAE) for a new 3200-3400 MWe nuclear power plant. (Further details in Lithuania paper )
See also Poland paper for more up to date information.
Most of Belarus electricity production is from gas. The country imports 90% of its gas from Russia - much of it for electricity, and overall aims for 25-30% energy independence, compared with half that now. There have been studies on both a domestic plant using Russian technology, and Belarus participation in a new nuclear unit at Smolensk or Kursk in Russia.
Plans to build a new coal-fired plant were shelved in 2005 because no coal supply could be found, but a 600 MWe coal-fired plant is now under consideration.
In mid 2006 the government approved a plan for the construction of an initial 2000 MWe PWR nuclear power plant in the in the Mogilev region of eastern Belarus. This was expected to provide electricity at half the cost of that from Russian gas (5 billion cubic metres per year for same capacity) and to provide some 30% of the electricity by 2020 at a cost of about EUR 4 billion (January 2008 estimate) on a turnkey basis.
In November 2007 a presidential decree defined the organizations responsible for preparing for the construction of the country's first nuclear power plant and budgeted money for engineering and site selection. The decree also aims to ensure that nuclear and radiation safety is in line with the recommendations of the International Atomic Energy Agency (IAEA).
In June 2009 the government announced that US$ 9 billion Russian financing had been lined up, and that Atomstroyexport would be the general contractor, with Russian and Belarus subcontractors, notably St Petersburg AEP. Intergovernmental agreements and then a turnkey construction contract with Atomstroyexport for a 2400 MWe plant (2 x 1200 MWe AES-2006 units) were signed in 2011. Operation of the Ostrovets /Astravets plant was scheduled for 2017 and 2018.
A VVER-1000 unit was earlier being built near Minsk but construction was abandoned in 1988 after the Chernobyl accident.
See also Belarus paper for more up to date information.
Estonia and Latvia
These countries had not been planning to build any nuclear capacity themselves and are participants in a plan to build the new 3400 MWe Visaginas nuclear plant in Lithuania. This is to replace the Ignalina plant there with much larger capacity to serve the three Baltic states and Poland. See Lithuania paper, and Poland section above.
Estonia generates most of its 9.7 billion kWh/yr gross of electricity from oil shale at the 2380 MWe Narva plant.
However, as plans for Visaginas became uncertain, in 2008 Estonia took steps to identify sites for a possible nuclear power plant of its own, and investigate possible involvement in a sixth Finnish plant. The state energy company Eesti Energia announced early in 2009 that it was considering building two 335 MWe IRIS reactors, from Westinghouse, by 2019. A new energy policy adopted by the government in February 2009 requires the establishment of legal and regulatory structures for nuclear power by 2012, and provides for Eesti Energia to build a nuclear power plant of up to 1000 MWe and to cut the contribution from oil shale to 30% by 2025. In September 2009 Eesti Energia was granted a permit for site surveys of Suur-Pakri Island, the westernmost of a pair of islands off Paldiski, 50 km west of Tallinn. In November 2010 it said that the site was suitable for a plant, and that it may be possible to supply district heating to Tallinn. A public information campaign is under way.
Estonia has recently completed a 350 MW DC cable interconnector with Finland – Estlink – costing EUR 110 million and supported by EC funding. Further potential connections are 650 MW between Estonia and Finland, 500 MW and 1000 MW between Lithuania and Poland, and 700 MW between the three Baltic countries and Sweden.
Estonia has two small Soviet naval reactors originally used for submarine training. They date from 1968 and 1983 and were closed down in 1989. They are in Safestor mode and will be dismantled after fifty years. The fuel has been returned to Russia.
Ireland produced 26 TWh gross from 8.8 GWe of plant for its population of 4.6 million in 2013, giving per capita consumption of 5600 kWh/yr. Half of its electricity is generated by gas, and coal provided 7.2 TWh (28%). Wind provided 4.5 billion kWh in 2013 from 1760 MWe of capacity (end of 2012). Net import in 2012 was 0.4 TWh. Ireland has a target of 3000 MWe wind capacity by 2020. Its main base-load power is from the 915 MWe Moneypoint coal-fired power station in county Clare commissioned in 1987 and which was upgraded in 2010. It is operated by ESB – Electricity Supply Board of Ireland – and is due to be decommissioned in 2025.
A 2012 IEA report said that Ireland is highly dependent on imported oil and gas. While the push to develop renewable energies is commendable, it will result in an increased reliance on natural gas, as gas-fired power plants will be required to provide flexibility in electricity supply when wind power is unavailable. Two-thirds of Ireland's electricity already comes from gas-fired generation, which adds to energy security concerns, particularly as 93% of its gas supplies come from a single transit point in Scotland. The country must successfully develop a range of gas and electricity infrastructure projects and market solutions while continuing to integrate its energy markets with regional neighbours, ie the UK, according to IEA.
In 1981 the government considered building a 650 MWe nuclear power plant (PWR) at Carnsore Point, but the plan was dropped as energy demand flattened. It would have required a link across the Irish Sea to the UK to be viable, due to its large size relative to the Irish grid then. Also the Electricity Regulation Act prohibits the use of nuclear fission.
A government-commissioned report by Forfas in April 2006 pointed to the need for Ireland again to consider nuclear power in order "to secure its long-run energy security". Relatively small-scale nuclear plants were envisaged. The report also suggested accelerating plans for greater east-west interconnection with the UK, which would draw on its nuclear capacity and also provide an export channel for any Irish nuclear power development.
In 2007 Ireland's Electricity Supply Board made it known that it would consider a joint venture with a major EU energy company to build nuclear capacity. In April 2008 the Irish Energy Regulator proposed a nationwide debate on the issue of nuclear power to address the country's pending energy crisis. It referred to the need to find an alternative to meet future energy needs since neither wind power or any other renewable energy sources could satisfy demand. These calls have continued into 2013 as the EPA has pointed to the country’s failure to be on track to meet emission reduction targets of 20% by 2020. In May 2014 a green paper suggested that the 915 MWe Moneypoint coal-fired power station might be replaced there by a nuclear reactor, especially given that the 440 kV transmission infrastructure is in place.
About half of Turkey's electricity comes from gas (two thirds of this from Russia, most of the rest from Iran), a quarter from coal and a bit less from hydro. Demand growth is 8% pa. Per capita consumption has risen from 800 kWh/yr in 1990 to almost 2000 kWh/yr.
Several nuclear power projects have been proposed since 1970, and in 1976 the Akkuyu site on the eastern Mediterranean coast near the port of Mersin was licensed for a nuclear plant. Early in 2006 the province of the port city of Sinop on the Black Sea was chosen to host a commercial nuclear power plant.
In August 2006 the government said it planned to have three nuclear power plants total 4500 MWe operating by 2012-15. The first units of some 5000 MWe total were to be built at Akkuyu, since the site was already licensed, but licensing was also proceeding for Sinop.
In 2007 a new bill concerning construction and operation of nuclear power plants and sale of their electricity was passed by parliament and subsequently approved by the President. The bill provided for the Turkish Atomic Energy Authority (TAEK) to set the criteria for building and operating the plants. The Turkish Electricity Trade & Contract Corporation (TETAS) would then buy all the power under 15-year contracts. The bill also addressed waste management and decommissioning.
TETAS called for tenders in March 2008, inviting bids for the first nuclear power plant at Akkuyu, near the port of Mersin. TAEK issued specifications, allowing for different technologies, while TAEK concentrated on site-specific aspects of the 4800 MWe project. In the event, only one bid was received from 14 interested parties, this being from Atomstroyexport in conjunction with others, for an AES-2006 power plant with four 1200 MWe reactors. After some deliberation, TAEK found that it met technical criteria.
In August 2009 two agreements between TAEK and Rosatom were signed with much fanfare. These seemed to progress the possibility of a Russian nuclear project at Akkuyu, but a legal matter halted progress. In May 2010 Russian and Turkish heads of state signed an intergovernmental agreement for Rosatom to build, own and operate the Akkuyu plant of four 1200 MWe AES-2006 units as a US$ 20 billion project. Rosatom, through Atomstroyexport and Inter RAO UES, will finance the project and start off with 100% equity in the Turkish project company set up to build, own and operate the plant. Longer-term they intend to retain at least 51% of the company. The Turkish firm Park Teknik and state generation company Elektrik Uretim AS (EUAS) are expected to take up significant shares. Meanwhile, EUAS will provide the site. Both Turkish and Russian parliaments then ratified the May agreement for 4800 MWe at Akkuyu.
TETAS will buy a fixed proportion of the power at a fixed price of US$ 12.35 cents/kWh for 15 years, or to 2030. The proportion will be 70% of the output of the first two units and 30% of that from units 3&4 over 15 years from commercial operation of each. The remainder of the power will be sold by the project company on the open market. After 15 years, when the plant is expected to be paid off, the project company will pay 20% of the profits to the Turkish government. Late in 2010 Rosatom announced that construction by Atomstroyexport was expected to start in 2013 and the first unit was planned to be operational in 2018, the others 2019-21.
The agreement also provides for setting up a fuel fabrication plant in Turkey.
Since February 2008 preparatory work has been under way at Sinop on the Black Sea to build a second nuclear plant there, along with a EUR 1.7 billion nuclear technology centre. A 5600 MWe nuclear plant there is expected to cost about $20 billion.
In March 2010 an agreement was signed between Korea Electric Power Corporation (Kepco) and EUAS for Kepco to prepare a bid to build the plant at Sinop, with four APR-1400 reactors starting operation from 2019. The bid, in conjunction with local construction group Enka Insaat ve Sanayi, was due in August. Kepco was to take 40% equity in the plant, and would help with financing. However, Kepco then withdrew.
In May 2013 a consortium led by Mitsubishi Heavy Industries (MHI) and Areva, with Itochu, proposed four Atmea1 reactors with total capacity of about 4600 MWe at a cost of some $22 billion. This was accepted, and an intergovernmental agreement was signed with Japan for “exclusive negotiating rights to build a nuclear power plant”. State generation company Elektrik Uretim AS (EUAS) is expected to take a 25% stake in the project company. Construction start is planned for 2017 and operation from 2023. GdF Suez, which operates seven nuclear reactors in Belgium, is to be the operator.
There are proposals to build further nuclear capacity at another site, as part of 100 GWe required by 2030. Reports suggest that TAEK has identified Igneada on the Black Sea, close to Bulgaria, as a third nuclear power plant site.
Turkey has modest uranium resources, including 7400 tU listed in the 2007 Red Book which are amenable to mining by in situ leaching. Perth-based Anatolia Uranium Pty Ltd (AUL) and its parent company are undertaking a preliminary economic assessment of their Temrezli ISL uranium project, with envisaged production of up to 380 tU/yr over 10 years.
In May 2008 a civil nuclear cooperation agreement with the USA entered into force, and in June 2010 a nuclear cooperation agreement with South Korea was signed.
See also Turkey paper for more up to date information.
Iran generates about three quarters of its electricity from gas and one quarter from oil, with some hydro input.
In the mid 1970s construction of two 1,200 MW(e) PWR units was started at Bushehr by Siemens KWU. In 1979 this was suspended. In 1994, Russia's Minatom and the Atomic Energy Organization of Iran (AEOI) agreed to complete unit 1 of Bushehr nuclear power plant with a VVER-1000 unit, using much of the infrastructure already in place. This long-awaited 915 MWe plant, being constructed by Atomstroyexport, started up in May 2011, was grid-connected early in September, and was expected to begin commercial operation in 2012. A second reactor was planned at the site.
See also Iran paper for fuller background and more up to date information.
Gulf states, UAE
In December 2006 the six member states of the Gulf Cooperation Council (GCC) - Kuwait, Saudi Arabia, Bahrain, the United Arab Emirates (UAE), Qatar and Oman - announced that the Council was commissioning a study on the peaceful use of nuclear energy. France agreed to work with them on this, and Iran pledged assistance with nuclear technology.
Together they produce 416 billion kWh per year (2009), all from fossil fuels and with 5-7% annual demand growth. They have total installed capacity of about 90 GWe, with a common grid apart from Saudi Arabia. There is also a large demand for desalination, currently fuelled by oil and gas.
In February 2007 the six states agreed with the IAEA to cooperate on a feasibility study for a regional nuclear power and desalination program. Saudi Arabia was leading the investigation and thought that a program might emerge about 2009, which it did.
The six nations are all signatories of the NPT and the UAE ratified a safeguards agreement with IAEA in 2003. In mid-2008 it appointed an ambassador to IAEA.
The UAE produces most of its electricity from gas, for which it relies on some imports. Electricity demand is growing by 9% per year and is expected to require 40 GWe of capacity by 2020. It relies entirely on electricity to provide its potable water, by desalination.
In April 2008 the UAE independently published a comprehensive policy on nuclear energy. This projected escalating electricity demand from 15.5 GWe in 2008 to over 40 GWe in 2020, with natural gas supplies sufficient for only half of this. Imported coal was dismissed as an option due to environmental and energy security implications. Nuclear power "emerged as a proven, environmentally promising and commercially competitive option which could make a significant base-load contribution to the UAE's economy and future energy security." Hence 20 GWe nuclear is envisaged from about 14 plants, with nearly one quarter of this operating by 2020. Two sites envisaged were between Abu Dhabi and Qatar, and possibly at Al Fujayrah on the Indian Ocean coast.
Accordingly, and as recommended by the IAEA, the UAE established a Nuclear Energy Program Implementation Organization which has set up the Emirates Nuclear Energy Corporation (ENEC) as a public entity, initially funded with $100 million, to evaluate and implement nuclear power plans within UAE.
In October 2009 the Federal Law Regarding the Peaceful Uses of Nuclear Energy was signed into effect, providing for development of a system for licensing and control of nuclear material, as well as establishing the independent Federal Authority of Nuclear Regulation to oversee the whole UAE nuclear energy sector, and appointing the regulator's board, headed by a senior US regulator. The law also makes it illegal to develop, construct or operate uranium enrichment or spent fuel processing facilities within the country's borders.
The UAE invited expressions of interest from nine companies for construction of its first nuclear power plant. ENEC reduced this to a short list of three and sought bids by mid 2009. The three bidders on the short list comprised Areva, with Suez and Total, proposing its EPR, GE-Hitachi proposing its ABWR, and the Korean consortium proposing the APR-1400 PWR technology. The last group is led by Korea Electric Power Co. (KEPCO), and involves Samsung, Hyundai and Doosan, as well as Westinghouse, whose System 80+ design (certified in the USA) has been developed into the APR-1400. The UAE has expressed an intention to standardize on one technology.
In December 2009 ENEC announced that it selected the bid from the KEPCO-led consortium for four APR-1400 reactors. The value of the contract for the construction, commissioning and fuel loads for four units is about US$20 billion, with a high percentage of the contract being offered under a fixed-price arrangement. The consortium also expects to earn another $20 billion by jointly operating the reactors for 60 years.
By 2020 UAE hopes to have four 1400 MWe nuclear plants running and producing electricity at a quarter the cost of that from gas. ENEC has appointd the global full-service program management, engineering, construction and operations firm C2HM Hill to manage the UAE's plans for bringing nuclear power to the country.
The site selected is at Barakah, on the coast 53 km west of Ruwais, a little closer to Qatar than to Abu Dhabi city. ENEC lodged a full construction licence application for units 1&2 in 2012, and started construction of unit 1, and unit 2 start is expected a year later. Commercial operation is envisaged in 2017 and 2018 respectively, followed by 2019 and 2020 for units 3&4.
Though part of UAE, Dubai is considering its own nuclear power possibilities, separate from Abu Dhabi's Barakah plant. In 2009 it set up a Supreme Council of Energy as an independent legal entity, whose task is to oversee all matters relating to Dubai's energy sector. This includes possible use of nuclear energy for electricity and desalination plants.
The USA and South Korea signed bilateral nuclear energy cooperation agreements with the UAE in January and June 2009 respectively. The UK and Japan have signed Memoranda of Understanding on nuclear energy cooperation with UAE. France has a nuclear cooperation agreement with UAE and has discussed nuclear energy development with Saudi Arabia, offering Atomic Energy Commission (CAE) assistance. The USA has signed memoranda of understanding re nuclear cooperation with Saudi Arabia and Bahrain.
See also: UAE paper for more up to date information.
Saudi Arabia is the main electricity producer and consumer in the Gulf States, with 217 TWh production in 2009, fairly evenly split between oil and gas. Capacity is over 30 GWe. Demand is growing 8% per year and peak demand is expected to be 60 GWe by 2020. Saudi Arabia is unique in the region in having 60 Hz grid frequency, which severely limits the potential for grid interconnections.
In August 2009 it announced that it was considering a nuclear power program, and in April 2010 a royal decree said: "The development of atomic energy is essential to meet the Kingdom's growing requirements for energy to generate electricity, produce desalinated water and reduce reliance on depleting hydrocarbon resources." The King Abdullah City for Nuclear and Renewable Energy (KA-CARE) is being set up in Riyadh to advance this agenda and to be the competent agency for treaties on nuclear energy signed by the kingdom. It is also responsible for supervising works related to nuclear energy and radioactive waste projects. In June 2010 it appointed the Finland- and Swiss-based Poyry consultancy firm to help define "high-level strategy in the area of nuclear and renewable energy applications" with desalination. In November 2011 it appointed WorleyParsons to conduct site surveys and regional analysis to identify potential sites, to select candidate sites then compare and rank them, and to develop technical specifications for a planned tender for the next stage of the Saudi nuclear power project.
Shaw Group in partnership with Toshiba/ Westinghouse and Exelon is bidding for EPC contracts, expecting Saudi Arabia to build up to 32 nuclear units. However, a nuclear cooperation agreement with France in early 2011 is likely to energetically advance French interests in any such plans. A mid 2011 nuclear cooperation agreement with Argentina is evidently related to smaller plants for desalination. A November 2011 agreement with South Korea calls for cooperation in nuclear R&D, including building nuclear power plants and research reactors, as well as training, safety and waste management. A January 2012 agreement with China relates to nuclear plant development and maintenance, research reactors, and the provision of fabricated nuclear fuel. KA-CARE said it was negotiating with Russia, Czech Republic, UK and the USA regarding "further cooperation".
In June 2011 the coordinator of scientific collaboration at KA-CARE said that it plans to construct 16 nuclear power reactors over the next 20 years at a cost of more than 300 billion riyals ($80 billion). The first two are planned to be on line in ten years and then two more per year to 2030. These would generate about 20% of Saudi Arabia's electricity. Smaller reactors such as Argentina’s CAREM are envisaged for desalination.
In April 2013 KA-CARE projected 18 GWe of nuclear capacity by 2032 of total 123 GWe, with 16 GWe solar PV, 25 GWe solar CSP (to provide for heat storage), and 4 GWe from geothermal, wind and waste. About half the capacity in 2032 would still be hydrocarbon, with one third solar following investment in that of some $108 billion. In addition 9 GWe of wind capacity would be used for desalination.
See also: Saudi Arabia paper for more up to date information.
Qatar has undertaken its own investigation in to the viability of nuclear power and late in 2008 announced that there was not yet a strong case for proceeding, especially in the absence of modern 300 to 600 MWe reactors being available. However, in 2010 it raised the possibility of a regional project for nuclear generation. Qatar expects to need 7900 MWe of capacity by 2010, along with desalination capacity of 1.3 million cubic metres per day in addition. In 2009 it produced 24.8 TWh, all from gas. In 2010 Qatar signed a nuclear cooperation agreement with Russia's Rosatom.
Oman also investigated nuclear power, joined GNEP, and in June 2009 signed a nuclear cooperation agreement with Russia. However, late in 2008 it said that since most of its demand was peak load, nuclear did not seem appropriate, though investment in a nuclear plant in a neighbouring GCC country was possible. In 2009 it produced 17.8 TWh, mostly from gas.
Kuwait is considering its own nuclear program for power and water, and in March 2009 moved to set up a national nuclear energy commission, in cooperation with the IAEA. In April 2010 it signed a nuclear cooperation agreement with France relating to a range of civil nuclear energy applications, including electricity generation, water desalination, research, agronomy, biology, earth sciences and medicine. In December 2010 the Kuwait Investment Authority agreed to take EUR 600 million equity (4.8%) in Areva. Kuwait also has nuclear cooperation agreements with USA, Russia and Japan.
In September 2010 it announced an intention to build four 1000 MWe nuclear power reactors by 2022, but in mid 2011 said it would not proceed with this. Cabinet also assigned the role of the Kuwait National Nuclear Energy Committee (KNNEC) to the Kuwait Institute for Scientific Research (KISR). Most of Kuwait's 53.2 TWh production in 2009 was from oil. In 2010 it had 11 GWe of capacity but this is expected to grow to 25 GWe by 2030. In 2011 it expended 350,000 bbl of oil (2.1 GJ) per day on electricity generation and desalination, this is expected to rise to 500,000 bbl (3 GJ) by 2030.
Bahrain produced 12.1 TWh in 2009.
Jordan imports over 95% of its energy needs, at a cost of about one fifth of its GDP. It generated 14.3 Billion kWh, mostly from natural gas, and imported 0.4 billion kWh of electricity in 2009 for its six million people. In 2012 its electricity was 25% from natural gas imported (unreliably) from Egypt, 32% from heavy fuel oil, 32% from diesel, and 11% was imported. It has 2400 MWe of generating capacity and expects to need 3600 MWe by 2015, 5000 MWe by 2020 and 8000 MWe by 2030 when it expects doubled electricity consumption. Per capita electricity consumption is about 2000 kWh/yr. Jordan has regional grid connection of 500 MWe with Egypt and 300 MWe with Syria, and it is increasing links with Israel and Palestine. This will both increase energy security and provide justification for larger nuclear units.
Also it has a "water deficit" of about 600 million cubic metres per year (1500 demand, 900 supply). Its 2007 national energy strategy envisages 29% of primary energy from natural gas, 14% from oil shale, 10% from renewables and 6% from nuclear by 2020. Jordan has regional grid connection of 500 MWe with Egypt, 300 MWe with Syria, and it is increasing links with Saudi Arabia, Israel and Palestine. This will both increase energy security and provide justification for larger nuclear units
Jordan's Committee for Nuclear Strategy, set up in 2007, set out a program for nuclear power to provide 30% of electricity by 2030, and to provide for exports. The nuclear law was modified in 2007 to establish the Jordan Atomic Energy Commission (JAEC) and the Jordan Nuclear Regulatory Commission (JNRC), including radiation protection and environmental roles.
Site options with seawater cooling are limited to 30 kilometres of Red Sea coast near Aqaba. After commencing a siting study for the new plant some 25 km south of Al Aqabah and 12 km east of the Gulf of Aqaba coastline, in 2010 the proposed location for the first reactor became the Majdal area in northern Al Mafraq province, about 40 km north of Amman, due to better seismic characteristics. The plant needs to have PGA seismic level of 400 gal for safe shutdown. Cooling water will come from the municipal Khirbet Al Samra Wastewater Treatment Plant, with the cooling system modeled on that at Palo Verde in Arizona, USA.
In November 2009 JAEC signed an $11.3 million agreement with WorleyParsons for the pre-construction phase of a 1000 MWe nuclear power plant. The firm is carrying out technology selection - preparing the tender and evaluating bidders, as well as assisting in fuel cycle engineering and waste management plans for the plant. It will also assist in establishing a utility company, expected to be a public-private entity with up to 75% equity from an experienced strategic partner, to own and operate the plant.
In 2009 the JAEC evaluated seven offers from at least four reactor vendors. In May 2010 three vendors and designs were short listed, the Atmea1 from Areva-MHI, the AECL EC6, and the AES-92 from Atomstroyexport. In April 2012 the field was narrowed to two: Atmea1 and AES-92. JAEC and WorleyParsons will take forward discussions first on the actual reactor designs and secondly "on the financing and organization support that the vendor will be providing for future operation of the plant."
In February 2011 the Energy Minister announced that JAEC had short-listed GDF Suez, Rosatom, Datang International Power Generation Co. and Kansai Electric Power Co. as possible strategic partners to invest in and operate the new plant, with the government retaining 26-51% of the equity. Jordan is looking at limited recourse financing with a debt-equity ratio of at least 70-30, and wants to set up a long-term (eg 45-year) power purchase contract, with the government guaranteeing part of the debt. The overnight cost is expected to be $4900/kW, hence likely $9.8 billion apart from financing.
JAEC expects to start building a 750-1200 MWe nuclear power unit in 2013 for operation by 2020 and a second one for operation by 2025.
Longer-term, four nuclear reactors are envisaged, and separately to the present tender process Rosatom has offered these on a build, own and operate (BOO) basis similar to its project in Turkey. Rosatom would establish a project company and eventually offer 49% of it to local investors. Further nuclear projects will involve desalination.
In December 2009 the JAEC selected a consortium headed by the Korean Atomic Energy Research Institute (KAERI) with Daewoo to build a 5 MW research and test reactor (JRTR) at the Jordan University for Science & Technology by 2015 – the country's first. The reactor, similar to South Korea's HANARO heavy water reactor, will use 19% enriched fuel and will have the potential to upgrade to 10 MW. It will be financed partly by a $70 million soft loan from South Korea, with 0.2% interest rate and repayment over 30 years. The JRTR will serve as an integral part of the nuclear technology infrastructure and will become the focal point for a Nuclear Science and Technology Centre (NSTC) with a key role in educating and training future generations of nuclear engineers and scientists. It will supply radioisotopes for medicine, industry and agriculture.
The country claims low-cost uranium resources of 140,000 tU plus another 59,000 tU in phosphate deposits. A feasibility study on recovering uranium as a by-product of phosphate production is under way.
In October 2008 a joint venture between JAEC and Areva was established to define uranium resources in central Jordan, and in February 2010 this became the JV company Nabatean Energy. Also the Jordan French Uranium Mining Company (JFUMC) was set up as a joint venture between Areva and Jordan Energy Resources Inc. and trades as Jordan Areva Resources. In June 2012 JFUMC said it had identified over 20,000 tU as reserves in a 72 sq km area. It will carry out a feasibility study on mining, and development of an open pit mine is expected to begin in 2013, for operation from 2015. Areva said its goal was "to create a full partnership with Jordan on training and obtaining nuclear technology".
A further 22,000 tU is reported at Hasa and Qatrana, 80 km south of Amman, following 2010-11 work by Jordan Energy Resources Inc (JERI), a commercial arm of JAEC. This is in the Qatrana phosphorites, where uranium at 0.015-0.017% would be a co-product with phosphates and vanadium. About 52 Mt of phosphate is reported, but neither this nor the uranium is as JORC-compliant resources. JERI is calling for bids from major mining companies to develop seven separate blocks comprising the deposit late in 2012. Some uranium mineralisation is also reported at Rweished near the Iraq border in the far northeast.
China National Nuclear Corporation (CNNC) has been searching for uranium at Hamra-Hausha in the north, and Wadi Baheyya in the south.
Jordan has signed nuclear cooperation agreements with France, Canada, UK and Russia, in respect to both power and desalination, and is seeking help from the IAEA. It has signed a nuclear cooperation agreement with China, covering uranium mining in Jordan and nuclear power, and others with South Korea, Japan, Spain, Italy, Romania, Turkey and Argentina related to infrastructure including nuclear power and desalination. A full nuclear cooperation agreement with USA is pending, though the USA wants Jordan to emulate UAE and rule out uranium enrichment. Jordan joined the Global Nuclear Energy Partnership (GNEP) in 2007.
See also: Jordan paper for more up to date information.
Egypt produced 156.6 TWh gross in 2011, with per capita consumption of 1910 kWh/yr at the end of 2012. In 2011, 117.0 TWh of electricity came from gas, 24.7 TWh from oil, and 12.9 TWh from hydro. Demand growth is about 7% pa. Gas resources are expected to be severely depleted in 20 years. In 2011-12 generating capacity was 25.1 GWe and the projected capacity in 2021-22 is 43.7 GWe.
Egypt set up its Atomic Energy Commission in 1955, and what became the Atomic Energy Authority the following year, responsible for licensing and regulation. In 1964 a 150 MWe nuclear plant with 20,000 m3/day desalination capacity was proposed, then in 1974 a 600 MWe plant was proposed for Sidi Kreir near Alexandria. The government's Nuclear Power Plants Authority (NPPA) was then established in 1976, and in 1978 plans were drawn up for ten reactors by 1999 with 7200 MWe capacity, at Sidi Kreir, Al Arish, Cairo and in Upper Egypt. Talks then with French, German and Austrian interests as well as Westinghouse came to nothing.
In 1983 the El Dabaa site on the Mediterranean coast 250 km west of Alexandria and Zafraana on the Gulf of Suez were selected for nuclear plants. Germany's KWU, Framatome and Westinghouse tendered to provide reactors for El Dabaa. Australia and Niger agreed to supply uranium. This plan was aborted following the Chernobyl accident. Over 1999-2001 the NPPA carried out a feasibility study for a cogeneration plant for electricity and desalination, updating it in 2003. New nuclear cooperation agreements were signed with Russia in 2004 and 2008, reviving Egypt's plans for a nuclear power and desalination plant there, supported by Rosatom.
On the basis of the feasibility study for a cogeneration plant for electricity and potable water at El-Dabaa, in October 2006 the Minister for Energy announced that a 1000 MWe reactor would be built there by 2015. The US$ 1.5 to 2 billion project would be open to foreign participation.
In December 2008, following an international tender, the Energy & Electricity Ministry awarded a $180 million contract to Bechtel to choose the reactor technology, choose the site for the plant, train operating personnel, and provide technical services over some ten years. However, in May 2009 the government transferred this contract to WorleyParsons, who signed it in June with the NPPA for $160 million over 8 years to support the establishment of a 1200 MWe nuclear plant. The contract included site surveys and regional analysis to identify potential sites, selecting candidate sites then comparing and ranking them, and developing technical specifications for a planned tender. The ministry said that Egypt aimed to begin generating nuclear electricity in 2017 at one of five possible sites.
Early in 2010 the proposal had expanded to four plants by 2025, the first being on line in 2019 or 2020. In March 2010 a legislative framework to regulate nuclear installations and activities in order to ensure the protection of facilities, individuals and property was signed into law. The first unit was expected to cost about US$ 4 billion. In 2011 plans were put on hold until the political situation stabilised.
In April 2013 Egypt approached Russia to renew its nuclear cooperation agreement, focused on construction of a nuclear power plant at El Dabaa and joint development of uranium deposits. In October 2013 the Minister for Electricity & Energy reactivated plans for El Dabaa, and announced a site office there for the Nuclear Power Plant Authority (NPPA). The Russian Foreign Minister said in November 2013 that Russia was ready to finance an Egyptian nuclear plant. In January 2014 the Ministry said it would issue a tender at the end of the month and announce the contractor in June, using WorleyParsons as consultants. In mid-2014 the target date for the tender was December 2014, and it was made plain that the winner would need to finance the plant. The tender would be for two units of 900 to 1650 MWe each. Four units should come on line 2020 to 2026. The El Dabaa site is deemed suitable for eight reactors.
In February 2015 a further agreement was signed so that Rosatom and the Ministry of Electricity and Renewable Energy "agreed to launch detailed discussions on the prospective project," involving construction of two 1200 MWe nuclear power units, with the prospect of two more. More specifically, Rusatom Overseas and NPPA also signed a project development agreement for a two-unit AES-2006 nuclear power plant with desalination facility. Two intergovernmental agreements are now pending – one for nuclear power plant construction and one for financing.
Other nuclear cooperation agreements are with China (2006) and South Korea (May 2013).
As well as addressing power supplies, the NPPA expects to have four nuclear desalination plants operating by 2025.
Egypt has a 1961-vintage 2 MW Russian research reactor at Inshas, serviced by Russia, and a 22 MW Argentinian research reactor (ETRR-2) partly supported by Russia and which started up in 1997.
Egypt signed the NPT in 1968, but until 1981 refused to ratify it unless Israel did. This caused plans in the 1970s to come to nothing.
Israel produces 60 billion kWh gross per year, more than two thirds from coal and one fifth from imported gas in 2012. It has about 14 GWe capacity with little reserve. Population is 7.9 million, with average per head consumption 6300 kWh/yr. Net exports (to unspecified countries) were 4.2 billion kWh in 2011.
In the 1980s the state-owned Israel Electric Corporation (IEC) set aside a site in the southern Negev at Shivta for a nuclear power plant, and discussions were held with France regarding equipment. The question was raised again in 2007 by the National Infrastuctures Ministry and Atomic Energy Commission. A twin reactor nuclear plant of 1200-1500 MWe under IAEA safeguards was envisaged for the site by 2020. Early in 2010 Israel said that it would prefer to develop its nuclear plant in collaboration with Jordan, but the overture was not reciprocated. In mid 2011 the prime minister was quoted as saying that plans would not proceed.
Israel has a 5 MWt research reactor at Nahal Soreq near Tel Aviv under IAEA safeguards, operating since 1960 with US fuel, and another 70 MWt French-built heavy water reactor at Dimona in the Negev, which is understood to have been used for military plutonium production. The Soreq reactor is due to be shut down about 2017 and replaced by a particle accelerator.
Israel is one of three significant countries which have never been part of the Nuclear Non-Proliferation Treaty (NPT), so any supply of nuclear equipment or fuel from outside the country would be severely constrained. Unlike India and Pakistan, Israel has had no civil nuclear power program.
Syria produced 41 TWh gross in 2011, 16.3 TWh of this from oil, 21.5 TWh from gas, 3.3 TWh from hydro. Electricity demand was growing rapidly.
Syria had plans in the 1980s to build a VVER-440 reactor but abandoned these after the Chernobyl accident and due to the collapse of Soviet Union. With escalating oil and gas prices, nuclear power was being considered again, and Russia had offered to help. The Syrian Atomic Energy Commission in 2011 published a proposal for a nuclear power plant by 2020.
However, over 2001-07 Syria built at a remote location what appeared to be a gas-cooled reactor similar to the plutonium production unit at Yongbyong in North Korea. This was destroyed by an Israeli air strike in 2007 and the remains then demolished. Israel claimed that the facility was a 25 MWt gas-cooled reactor with military purpose. The project was clandestine and apparently in breach of Syria's obligations under the NPT.
Tunisia produced 16 billion kWh gross in 2011, almost all of this from gas. Capacity was 3.8 GWe in 2012, and projects 24.5 to 33.3 GWe in 2031.
The government is reported to be evaluating the possible construction of a 600-1000 MWe nuclear plant costing US$ 1.14 billion at either a northern or a southern site. Desalination is a major need.
The National Atomic Energy Commission (CENA) was established in 1990, focused on nuclear technology for various functions but not power. The country’s nuclear law has been overhauled in collaboration with IAEA since 2008. The regulatory body is the National Agency for Nuclear Safety (ANSN) which is complemented by the National Centre for Radiation Protection (CNRD), set up in 1981. A National Centre for Nuclear Science & Technology was set up in 1993 to undertake research.
Tunisia has reserves of 100 Mt phosphates containing 50,000 tU. At 1.6 Mt/yr P2O5 production, this would yield 265 tU/yr by-product.
In December 2006 a nuclear cooperation agreement was signed with France, focused on nuclear power and desalination, and in April 2008 this was amplified.
In 2011 Libya produced 27.6 TWh gross of electricity, 15.6 TWh of this from gas, 12 TWh from oil.
Early in 2007 it was reported that Libya was seeking an agreement for US assistance in building a nuclear power plant for electricity and desalination. In 2006 an agreement with France was signed for peaceful uses of atomic energy and in mid 2007 a memorandum of understanding related to building a mid-sized nuclear plant for seawater desalination. Areva TA would supply this, with some involvement of the French CEA, and consultations on the project continue. In 2008 Libya signed a civil nuclear cooperation agreement with Russia.
Early in 2010 the Libyan Atomic Energy Institute was preparing a nuclear law as part of the institutional infrastructure for setting up nuclear power plants. It has tentatively selected a site for both power and desalination.
In 2003 Libya had halted a clandestine program developing uranium enrichment capability, and fully opened itself to IAEA inspections.
Libya has a Russian 10 MW research reactor at Tajoura operating since 1983 which is under IAEA safeguards, and is reported to be adapting this for a nuclear desalination demonstration plant with a hybrid MED-RO system.
Algeria produced 46 billion kWh gross of electricity in 2010, almost all from natural gas, and it is a major gas exporter. Demand is increasing rapidly.
In January 2007 Russia signed an agreement to investigate the establishment of nuclear power there. Further nuclear energy cooperation agreements with Argentina, China, France, and the USA followed over 2007-08, the French one coupled with strong commercial interest from Areva. In April 2015 China National Nuclear Corporation and the Algerian Atomic Energy Commission signed an agreement to cooperate in areas including nuclear energy, research reactors, nuclear safety, nuclear technology and water desalination.
In February 2009 the government announced that it planned to build its first nuclear power plant to be operating about 2020, and might build a further unit every five years thereafter. In 2013 the target became a first plant by 2025, and a Nuclear Engineering Institute was established to provide training. In September 2014 a further intergovernmental agreement was signed with Rosatom, envisaging “cooperation in the construction of nuclear power plants and research reactors, the use of nuclear reactors for heat generation and desalination of seawater, joint prospecting and mining of uranium deposits, nuclear fuel handling and processing of nuclear waste.” Rosatom said the key aspect of it was construction of VVER reactors, on the basis of its “vast experience of building nuclear power plants in countries with hot climates and high seismic activity,” and Algeria’s energy minister said that the timeline for this was “the next 12 years.”
In September 2009 its National Mining Patrimony Agency put uranium exploration leases in the southern Tamanrasset province out for tender. The 2011 'Red Book' shows the country having 26,000 tonnes of uranium resources, all in the high-cost category.
Algeria has operated two research reactors since 1995, at Draria and Ain Ouessara. The 15 MWt Es-Salam plant is a Chinese heavy water reactor which started up in 1992, the Nur 1 MWe pool unit was built by INVAP of Argentina in the 1980s.
Morocco has growing electricity demand and produced 25 TWh gross in 2011. It also has requirements for desalination. In 2011, coal supplied 11.7 TWh, 6.6 TWh was from oil, 4.0 TWh from gas, 2 TWh from hydro.
The government has plans for building an initial nuclear power plant in 2016-17 at Sidi Boulbra, and Atomstroyexport is assisting with feasibility studies for this. It is also setting up the infrastructure to support a nuclear power program, including establishment of a nuclear safety authority and a radiation protection authority. Earlier proposals were for a 600 MWe nuclear power plant to be sited between the cities of Essaouira and Asfi.
Morocco has a 2 MW Triga research reactor under construction at Mamoura near Rabat.
For desalination, it has completed a pre-project study with China, at Tan-Tan on the Atlantic coast, using a 10 MWt heating reactor which produces 8000 m3/day of potable water by distillation.
In October 2007 a partnership with France to develop a nuclear power plant near Marrakesh was foreshadowed and a nuclear energy cooperation agreement was signed. A further cooperation agreement was signed in mid 2010.
In January 2010 the government announced plans for two 1000 MWe nuclear reactors to start operation after 2020 as part of its submission to the Copenhagen Accord, agreed late in 2009. (Under the terms of the Copenhagen Accord, developing countries were invited to submit proposed Nationally Appropriate Mitigation Actions - NAMAs - demonstrating how they planned to reduce their greenhouse gas emissions through specified projects.) It said it would call for tenders for the two units by 2014.
In January 2011 the government approved plans to set up a nuclear safety agency and draft a law on nuclear security.
In 2007 Areva signed an agreement with Morocco's Office Cherifien des Phosphates (OCP) to investigate recovery of uranium from phosphoric acid. The amount of uranium in Morocco's phosphates is reported to be about 6.9 million tonnes. At 4.8 Mt/yr P2O5 production, some 960 tU/yr by-product is likely.
The government's Office National des Hydrocarbures et des Mines (ONHYM) is encouraging exploration for uranium to build upon that done by French and Russian geologists prior to 1982. Three areas are under investigation: Haute Moulouya, Wafagga and Sirwa. The first two have palaeochannel deposits.
Sudan’s grid capacity was 2600 MWe in 2012. In 2011 it produced 8.6 TWh, 6.5 TWh of this from hydro.
In 2007 a nuclear power program was initiated by the Ministry of Energy & Mines, and in 2010 the country started considering the feasibility of a nuclear power plant, and Sudan's Atomic Energy Commission is consulting the IAEA. The Ministry of Electricity and Dams (MED) is the main agency, and it has set up the Nuclear Energy Generation Dept (NEGD) to undertake a feasibility study along with site and technology selection. The objective is to have a nuclear plant with four 300-600 MWe units, or 4400 MWe, operating by 2030. There is an Atomic Energy Act, but radwaste and transport functions will be under a comprehensive new draft Nuclear Act incorporating IAEA safety and other principles
In the short term, Sudan aims to build a research reactor by 2020, and IAEA is assessing this proposal.
Sudan has been an IAEA member since 1958 and has had a safeguards agreement with IAEA under NPT since 1975.
Yemen is considering plans for using small nuclear reactors to 300 MWe in 2025-2030, then a commercial nuclear power plant with 1000-1500 MWe about 2035. It is working with IAEA on these plans. Meanwhile a research reactor is envisaged. An Atomic Energy law is in draft form.
Nigeria produced 28 TWh in 2012 from less than 6 GWe of plant (about 1.5 GWe unavailable due to shortage of gas); 23 TWh was from gas, 5.7 TWh from hydro and none from oil. It had final consumption of 25 TWh, giving per capita consumption of only 140 kWh/yr. The Energy Commission of Nigeria under the federal Ministry of Science & Technology is responsible for policy, and the energy sector has seen major change as the government actively privatises new generation and transmission projects. In the first phase of its liberalisation process, five generation and ten distribution companies (linked to the country’s main power holding company) have been privatized since 2013. In addition, the Niger Delta Power Holding Company (NDPHC) is privatizing ten newly built generation plants. These newly privatized generation companies are contractually obliged to increase generation for each plant over the next five years. An additional 2 GWe increase is to stem from investments by new independent power producers. The government in December 2014 signed an agreement with Turkey’s Koztek Electric and Energy Technologies with a view to the construction of new power plants and transmission facilities “wholly financed by Turkish business interests.”
The government is planning to increase the use of solar power, and 3 GWe of utility-scale solar PV capacity is being developed in a $5 billion public-private partnership project with Skypower FAS Energy in the Delta state. A feed-in tariff (FIT) regime is being developed to support renewables investment.
To address rapidly increasing base-load electricity demand, Nigeria has sought the support of the International Atomic Energy Agency to develop plans for up to 4000 MWe of nuclear capacity by 2025. Nigeria is Africa's most populous country and its power demand was expected to reach 10,000 MWe by 2007 – though grid-supplied capacity in 2006 was only 2600 MWe. Power shortages have caused industries to relocate to Ghana. The federal Ministry of Power is in charge of electricity generation, grids and pricing.
The federal government in 2007 approved a technical framework or 'roadmap' for its nuclear energy program, along with a strategic implementation plan. This is to proceed through manpower and infrastructure development, power reactor design certification, regulatory and licensing approvals, construction and start-up. A strategic plan to streamline this was adopted in 2009, with a target of 1000 MWe of nuclear capacity by 2020, and another 4000 MWe by 2030. In 2013 preparations were made for an IAEA INIR mission in 2014 and a national self-evaluation report was to be sent to IAEA by April in preparation for this.
A Nigerian Nuclear Regulatory Authority (NNRA) has been set up for regulatory oversight on all uses of ionising radiation, nuclear materials and radioactive sources under the federal Ministry of Science & Technology.
The Nigerian Atomic Energy Commission (NEAC) is alongside but not under any federal ministry, and is responsible for the national Nuclear Energy Program Implementation Committee (NEPIC), which has eight teams. In October 2010 NEAC announced the selection of four sites for further evaluation by its environmental and siting team. These are around Geregu/Ajaokuta in Kogi state in north central zone, Itu in Akwa Ibom state in the south-east, Agbaje, Okitipupa in Ondo state in the southwest zone and Lau in Taraba state in the northeast zone. It said construction was envisaged from 2014, and first power by 2020. Early in 2014 the first two sites – Geregu and Itu – were being evaluated.
In March 2009 Russia signed a cooperation agreement with Nigeria, including provision for uranium exploration and mining in the country. A further broad agreement in June 2009 envisaged the construction of a Russian power reactor and a new research reactor. In July 2011 Russia's Rosatom and the Nigerian Atomic Energy Commission finalized a draft intergovernmental agreement to cooperate on the design, construction, operation and decommissioning of an initial nuclear power plant. This needs approval by the two governments. A further three nuclear plants are planned, bringing the total cost to about $20 billion. In June 2012 Rosatom signed a memorandum of understanding with the NAEC to "prepare a comprehensive program of building nuclear power plants in Nigeria," including the development of infrastructure and a framework and system of regulation for nuclear and radiation safety. Rosatom has confirmed that Russian financing options will be available to Nigeria, whose preferred option is a build-own-operate (BOO) arrangement with majority Rosatom equity. This is to be confirmed in a further intergovernmental agreement. Early in 2015 the intention was to have a first unit on line by 2025, and 4800 MWe operating by 2035.
Following evaluation of US designs by the Nigerian Nuclear Regulatory Authority (NNRA) about 2009, the government of Imo state signed an agreement with Barnett Holding Co in the USA to investigate sites for modular nuclear power reactors, using IAEA guidelines. These were to be 5 to 20 MWe and deployed to Owerri township, Ogwu city development, and elsewhere in Imo state.
Nigeria's first research reactor was commissioned at Ahmadu Bello University in 2004. It is a 30 kW Chinese Miniature Neutron Source Reactor similar to other Chinese units operating in Ghana, Iran, Syria and China. It uses high-enriched uranium fuel but is converting to LEU. The IAEA assisted the Nigerian government with the project, to "reinforce and widen the human resource base to sustain nuclear technology" in relation to medical technology, geochemistry, mineral and petrochemical analysis and exploration. A larger research reactor is envisaged.
Ghana produced 12 billion kWh gross in 2012, two thirds of this from hydro, 2.5 TWh from oil and 1.5 TWh from gas. Net export was 0.6 TWh to Togo. Hydro power is from the Volta River Authority in the north of the country, and the VRA is responsible for all power generation from a total of almost 2 GWe in 2014. The government aims to more than double generating capacity to 5000 MWe by 2015 and become an electricity exporter. In 2014 there were power shortages resulting in load shedding by the Electricity Company of Ghana in the south of the country. Earlier projections to 2015 suggested demand of 19.5 billion kWh then. Under the national electrification project commenced in 1989, access reached 72% (2012, of 24.6 billion population), resulting in a fourfold increase in domestic demand.
In April 2007 the government announced that it planned to introduce nuclear power on energy security grounds and in 2008 quantified this as 400 MWe of nuclear capacity by 2018. In 2012 it was “in the long term” and not before 2030, but envisaging 1000 MWe unit(s). In late 2014 the target was to start building 700 MWe before 2020 for 2025 commissioning and expanding to 1000 MWe.
The Ministry of Energy established the Nuclear Energy Programme Implementation Organization (NEPIO) called the Ghana Nuclear Power Programme Organization (GNPPO), in September 2012 as part of the first IAEA milestone. It will deal with all the issues associated with the planning and implementation of a nuclear power program, develop legal and regulatory frameworks, and co-ordinate the activities of all stakeholder institutions involved in the planning of it. Eight technical groups have been set up to undertake planning and implementation. Three potential sites have been identified by the Energy Ministry.
In May 2012 Ghana hosted a regional meeting on “Co-operation and Networking for Nuclear Power Programme in Africa”, organized by the Ghana Atomic Energy Commission (GAEC) under the auspices of the IAEA. The GAEC said that “the increasing energy requirements for the socio-economic development of Africa, coupled with the ever volatile prices of fossil fuels, continue to be a major challenge for a lot of African countries.”
In 2012 the Ministry of Energy & Petroleum signed a cooperation agreement with Rosatom, and in mid-2013 further discussion took place on the specifics of joint projects facilitating the implementation of plans by Ghana to develop a nuclear industry with Russian help.
The Nuclear Regulatory Power Bill to establish an independent nuclear regulatory body, another prerequisite for the operating a nuclear power plant, was being considered by parliament in 2014. The Radiation protection Board is the current authority.
Ghana joined the Global Nuclear Energy Partnership (GNEP), now the International Framework of Nuclear Energy Cooperation (IFNEC), in September 2007. In mid-2012 it signed a nuclear cooperation agreement with Russia, which envisages assistance in building up the infrastructure for nuclear power in Ghana. A further agreement was expected in June 2013. The country is open to the possibility of a foreign build-own-and-operate (BOO) project for nuclear power, such as is Russian policy. No developments are expected before about 2020.
The Ghana Atomic Energy Commission (GAEC) was set up in 1963 to introduce nuclear science and technology into the country and to exploit the peaceful applications of nuclear energy for national development. Its main facility is a small (30 kW) Chinese research reactor, operated since 1994 by GAEC’s National Nuclear Research Institute (NNRI).
GAEC and the University of Ghana established the School of Nuclear and Allied Sciences (SNAS) in 2006 to provide human resources to run the eventual power plant, and ensure the continuous training of competent nuclear scientists.
Early in 2010 Senegal announce that as part of its policy to replace oil for power generation, and to integrate with the West African Power Pool, it was considering a nuclear power plant by about 2010. Domestic demand is only 550 MWe, but is growing at 7% per year, and electricity production in 2011 was 3 TWh, 2.6 TWh of this from oil. France has offered technical assistance.
Uganda's Atomic Energy Bill came into effect in 2008, to regulate the use of ionising radiation and provide a framework to develop nuclear power generation. The government has signed an agreement with IAEA to initiate moves in that direction. Peak demand in 2007 was 428 MWe met mainly from hydro, and projected demand for 2015 is 2000 MWe. Some $500 million is being spent on doubling transmission lines to 3400 km, including links to Kenya and Rwanda.
Electricity production in 2011 was 7.85 TWh, 3.45 TWh from hydro, 1.5 TWh from geothermal, 2.57 TWh from oil. In 2014 Kenya's installed electricity generation was 1767 MWe with a maximum demand of 1457 MWe. This is generated from 767 MWe of hydro capacity and now 680 MWe of geothermal which will supply about half the demand, as well as some oil and gas and other. The 960 MWe Lamu coal-fired plant is expected on line in 2017. The annual demand growth has reached 7% and is expected to increase to 15% as the Vision 2030 projects are implemented. Demand is expected to reach 15,000 MWe by 2030, and in March 2015 the Energy Regulatory Commission said installed capacity in 2033 would be 24,674 MWe, allowing significant exports. Of this, 7264 MWe would be geothermal, 5400 MWe coal-fired, 2600 MWe nuclear, 3960 gas turbine and 2180 MWe wind.
In 2010 Kenya's National Economic & Social Council recommended that the country start using nuclear power by 2020 to meet its growing electricity demand. A former Energy Minister was appointed to head a Nuclear Electricity Project Committee which aims to replace some oil and gas-fired capacity with nuclear power, and start construction of a plant by 2017. Coastal sites were being sought, and the project involves conforming plans to IAEA terms, conditions and milestones. The IAEA completed an initial review of plans in March 2011 considering a site on Athi Plains, 50 km from Nairobi. The Energy Ministry notes that a South Korean plant would cost about $3.5 billion, but would provide cheaper electricity than alternatives. Another estimate of the project cost is $9.8 billion.
Kenya Electricity Generation Co. Ltd. (KenGen, 70% state-owned), supplies 80% of the country's power, mostly from hydro to 2013, and aims to double installed capacity to 3000 MWe by 2018, then 4200 MWe in 2022 and increase that to 9000 MWe by 2030 – at least half geothermal. It expects total 2030 Kenya capacity to be almost 18 GWe, with IPPs. It is seeking a partner to produce nuclear power by 2022 to help meet rising demand and diversify from hydropower. Some 280 MWe of geothermal capacity at KenGen’s Olkaria in the Rift Valley came on line early in 2015 and the first 400 MWe of the 1600 MWe Menengai project, expected to cost $24 billion, is being built by the state-owned Geothermal Development Company (GDC), to come on line in 2016. The US-East Africa Geothermal Partnership (EAGP) was established in 2012 to promote the development of geothermal energy resources and projects in East Africa, including Kenya. UNEP’s African Rift Geothermal Development Facility (ARGeo) is also involved. Geothermal power from the Rift Valley is prospective, and is being pursued by ARGeo.
Kenya Power (50.1% state-owned) owns and operates most of the electricity transmission and distribution system. A 220 kV link with Uganda is being built. A 400 kV AC, 2000 MWe link of 508 km with Tanzania was funded by the African Development Bank early in 2015, and a 500 kV DC link with Ethiopia is planned for 2017, funded by the World Bank. This will allow the Eastern Africa Power Pool to connect with the Southern Africa Power Pool.
In May 2014 the Kenya Nuclear Electricity Board (KNEB), set up in 2012 under the Ministry of Energy, sought expressions of interest in evaluation of the grid system for fast-track establishment of nuclear power.
Namibia's electricity supply of 3.8 billion kWh in 2011 was two-thirds supplied by South Africa, which faces supply constraints itself. The 1.4 billion kWh generated domestically was mostly from hydro. A coal-fired plant is planned for Walvis Bay.
Namibia holds about 7% of the world's uranium reserves, which are mined to fuel nuclear power stations around the world. Now the government has committed to a policy position of supplying its own electricity from nuclear power. The country faces severe challenges in power supply.
See also: Namibia paper for more up to date information.
In 2011 the country produced 20.3 billion kWh gross of electricity, 17.3 TWh of this from gas and 2.7 TWh from hydro.
In 1980 a 1000 MWe nuclear power plant was under construction but this was abandoned about 1986. In 2007 the Institute for Radiation Problems of the National Academy of Sciences proposed a 1500 MWe nuclear power plant on the same site in the Avai region of southern Azerbaijan to support proposed industrialisation there. In 2009 Russia offered to take part in construction of the plant.
In June 2008, the International Atomic Energy Agency (IAEA) issued a preliminary agreement to support a 10-15 megawatt research reactor 15 km north of Baku. The $119 million reactor would be operated by the Institute for Radiation Problems, which specializes in nuclear energy research. Construction was expected to begin in 2012, but preparatory studies were discontinued in November 2013.
In May 2014 the president ordered the establishment of a National Nuclear Research Centre under the Ministry of Communications and High Technologies. In September 2014 Areva offered to build a research reactor in line with IAEA guidance.
Azerbaijan is party to the NPT with an Additional Protocol and to the Comprehensive Test Ban Treaty.
Georgia generated 10.2 billion kWh gross in 2011, 7.9 TWh of this from hydro and 2.3 TWh from natural gas.
It is heavily dependent on Russia for energy supplies and there is some discussion about building a nuclear power plant to assist its energy independence. This could be in collaboration with Azerbaijan or Armenia. In November 2006 Russia threatened to double the price of gas to Georgia. In August 2008 it invaded Georgia.
Most of Kazakhstan’s electricity comes from coal. Electricity production was 86.6 TWh in 2011, 70 TWh from coal, 8 TWh from gas and 8 from hydro It has no national electricity grid, but a northern grid links to Russia and a southern one links to Kyrgystan and Uzbekistan.
Kazakhstan's main significance is as the world's largest producer of uranium. It has put in place a variety of international arrangements to add value to this domestically and to supply Japan and China in particular.
The Russian BN-350 fast reactor at Aktau (formerly Shevchenko), on the shore of the Caspian Sea, successfully produced up to 135 MWe of electricity and 80,000 m3/day of potable water over some 27 years until it was closed down in mid 1999. About 60% of its power was used for heat and desalination. It was operated by the Mangyshlak Power Generation Co. (MAEK). The plant was designed as 1000 MWt but never operated at more than 750 MWt and was most recently quoted at 520 MWt, but it established the feasibility and reliability of such cogeneration plants. (In fact, oil/gas boilers were used in conjunction with it, and total desalination capacity through ten multi-effect distillation (MED) units was 120,000 m3/day.)
Kazakh plans for nuclear power include large light-water reactors for the southern region, 300 MWe class units for the western part and smaller cogeneration units in regional cities. There are proposals for a new nuclear power plant near Lake Balkhash in the south of the country, north of Almaty. A feasibility study on building a new 600 MWe nuclear power plant, here or at Aktau, is being undertaken and is due to be completed in 2009. Power from the first 300 MWe unit is expected in 2016, and the second in 2017.
A July 2006 joint venture with Russia's Atomstroyexport envisages development and marketing of innovative small and medium-sized reactors, starting with OKBM's VBER-300 as baseline for Kazakh units. Atomstroyexport expected to build the initial one, but the plan is apparently on hold.
In 2007 a number of high-level agreements on energy cooperation were signed with Japan. These included some relating to uranium supply to Japan, and technical assistance to Kazakhstan in relation to fuel cycle developments and nuclear reactor construction. Kazatomprom said that it aimed to supply 40% of the Japanese market for both natural uranium and fabricated fuel from 2010 - about 4000 tU per year.
A Kazatomprom joint venture with Russia's Tenex, confirmed in 2008, is to extend a small uranium enrichment plant at Angarsk in southern Siberia (this will also be the site of the first international enrichment centre, in which Kazatomprom has a 10% interest). It will eventually be capable of enriching the whole 6000 tonnes of uranium production from Russian mining JVs in Kazakhstan.
Over 2006-08 China Guangdong Nuclear Power Group Holdings (CGNPC) signed a strategic cooperation agreement with Kazatomprom, then an agreement on uranium supply and fuel fabrication, on Chinese participation in Kazakh uranium mining joint ventures and on Kazatomprom investment in China's nuclear power industry. Kazatomprom seeks to become the main uranium and nuclear fuel supplier to CGNPC (accounting for a large share of the new reactors being built in China). A further agreement covers cooperation in uranium mining, fabrication of nuclear fuel for power reactors, long-term trade of natural uranium, generation of nuclear electricity and construction of nuclear power facilities. A framework strategic cooperation agreement was signed with rival China National Nuclear Corporation (CNNC) in 2007 and this was followed in 2008 with another on "long-term nuclear cooperation projects" under which CNNC is to invest in a Kazakh uranium mine.
In 2007 Canada's Cameco Corporation signed an agreement with Kazatomprom to investigate setting up a uranium conversion plant, using its technology, and also increasing uranium production at its 60% owned Inkai mine. In 2008 Cameco and Kazatomprom announced the formation of a new company – Ulba Conversion LLP – to build a 12,000 t/yr uranium hexafluoride conversion plant at the Ulba Metallurgical Plant in Ust-Kamenogorsk. Cameco will provide the technology and hold 49% of the project.
The internationally-significant Ulba Metallurgical Plant at Ust Kamenogorsk in the east of the country was commissioned in 1949. It has a variety of functions relevant to uranium, the most basic of which since 1997 is to refine most Kazakh mine output of U3O8. Since 1973 Ulba has produced nuclear fuel pellets from Russian-enriched uranium which are used in Russian and Ukrainian VVER and RBMK reactors. Other exports are to the USA and it plans to market to Asia. Ulba is majority owned by Kazatomprom and 34% by Russia's TVEL. In 2007 a technological assistance agreement was signed with Japan apparently in line with government announcements that it would move towards selling its uranium as fabricated fuel or at least fuel pellets rather than just raw material.
In 2008 Areva signed a strategic agreement (MOU) with Kazatomprom to expand the existing Katco joint venture from mining 1500 tU/yr to 4000 tU/yr (with Areva handling all sales), to draw on Areva’s engineering expertise in a second JV (49% Areva) to install 1200 tonnes per year fuel fabrication capacity at the Ulba Metallurgical Plant, and in a third JV (51% Areva) to market fabricated fuel.
At Kurchatov (aka Semipalatinsk-21) on the former Semipalatinsk nuclear test site three research reactors owned by the National Nuclear Centre are operated by the Institute of Atomic Energy. A fourth is at Almaty. The three larger ones are tank-type units of 6, 10 and 60 MW, the newest is a 400 kW high-temperature gas reactor. All were supplied by Russia and use high-enriched fuel.
Kazakhstan joined the Global Nuclear Energy Partnership (GNEP) in September 2007.
See also Kazakhstan paper for more up to date information.
Russia is reported to be examining the feasibility of building nuclear power plants in Mongolia, and Mongolia's Nuclear Energy Agency has tentative plans for developing nuclear power from 2021. Three sites under consideration are Ulaan Baatar, western Mongolia and Dornod province.
In December 2010 Russia and Mongolia concluded a high-level agreement to cooperate in identifying and developing Mongolia's substantial uranium resources.
The country’s gross electricity production in 2011 was 4.75 billion kWh, mostly from brown coal, and about 13% of electricity is imported from Russia.
see also Mongolia paper.
Chile imports over 70% of its energy, mostly as hydrocarbons. It produced 68.4 billion kWh gross in 2012 from some 17.6 GWe of plant and imported 0.7 billion kWh. There is a need to build a further 5 GWe by 2020 to secure a measure of energy security as Argentina cuts back gas supplies. Per capita consumption is 3350 kWh/yr. About 30% of electricity comes from hydro, depending on how much rain it has, and in 2011, 21% came from imported natural gas. In 2012, 24 billion kWh came from coal and there are proposals for new coal-fired plants.
In February 2007 the Energy Ministry announced that it was beginning technical studies into the development of nuclear power. A major business group has already had discussions with Areva about building a nuclear power plant to connect Chile's northern and central power grids. In November 2007 the President asked the Energy Minister to prepare new studies regarding the country's nuclear energy options for the next administration. In mid 2009 the country's mining industry called for the establishment of nuclear power by about 2025 to counter escalating energy costs and an impending energy deficit. In 2010 the Nuclear Power Committee, part of the Energy Commission of the Professional Association of Engineers of Chile, proposed four 1100 MWe units for the grid.
These could be sited in three sections of the coastline: Angofasta region, 1400 km north of Santiago, with a dense population as well as extensive mining activity and a major ($3.43 billion) desalination plant due on line in 2017; the Coquimbo region, 300 km north of Santiago, serving the north of the capital's metropolitan area; and El Liberatador, 200 km south of Santiago, to serve the city as well as insuring against possible reduction in hydroelectric generation there. With the first unit starting construction in 2015 and operational in 2020, all four could be operating by 2030, providing 26% of the country's 140 billion kWh of electricity demand then. A significant application of nuclear power is likely to be desalination for major mines in the northern Atacama desert.
Early in 2010 the Energy Minister said that the first nuclear plant of 1100 MWe should be operating in 2024, joined by four more by 2035 to replace coal capacity. He outlined a plan to create the necessary infrastructure, including developing human resources, a regulatory framework, safety and waste management provisions, geological studies and building public consensus between the years 2012 and 2018. A public-private partnership is proposed to build the first plant, with a tender being called in 2016. A new head of the Chilean Atomic Energy Commission (Comisión Chilena de Energía Nuclear, CCHEN) was appointed in February 2011 and an agreement between CCHEN and France's CEA on "institutional cooperation in nuclear energy" was signed, providing for training. Also a high-level group was set up, co-chaired by senior executives of GdF Suez and Chile's Quinenco to promote French nuclear industry collaboration with CCHEN. In October 2012 the Energy Minister said that said that two studies will be launched in 2013, one to examine technological options for a nuclear power plant, and a second into possible locations for it.
In August 2009 the government signed a nuclear cooperation agreement with Russia's Rosatom with a view to developing a nuclear power program and related projects.
Venezuela produced 122 TWh gross in 2011, 17.4 TWh of this from oil, 21 TWh from gas, and 83.7 TWh from hydro.
The National Assembly has introduced legislation which includes nuclear power as an option. The President announced in November 2007 that the country would pursue a nuclear power program, inspired by Brazil and Argentina. Late in 2008 he announced that this would be with Russian help, and the first unit would be in the northwestern province of Sulia. A civil nuclear cooperation agreement was signed with Russia in November 2008 and further nuclear agreements in April and October 2010. The country also has very close links with Iran.
The last of these Russian agreements, ratified by parliament in November 2010, provided for construction of two nuclear reactors of 1200 MWe each and also for construction of a research reactor to produce radioisotopes, as well as relevant infrastructure and training. No clear timeline was set, though the agreement involved an action plan to 2014. The parliamentary commission in charge of the deal said "with the launch of the nuclear power plant, Venezuela will be able to save up to a billion dollars a year by exporting 15 million barrels of oil which are now spent on producing the equivalent volume of electricity." However, in mid 2011 it appeared that plans had been shelved.
The government has confirmed that Iran is assisting with geophysical surveys related to uranium exploration, but there is no mining. Unconfirmed reports in 2009 of uranium exports to Iran have been denied. A Canadian company, U3O8 Corp, is exploring for uranium in the Guyana part of the Roraima Basin, which straddles the border.
The country had a small (3 MW) research reactor, operated 1960-94 by the Venezuelan Institute for Scientific Research (IVIC), and in mid 2009 was discussing with Atomenergoprom the construction of another.
Bolivia generated 7.2 TWh in 2011, 4.5 TWh from gas and 2.35 TWh from hydro. The government is setting up an Atomic Energy Commission and planning to establish a nuclear reactor program in 2014, both for power generation and medical isotopes. In October 2014 the president announced plans to spend $2 billion on developing nuclear energy over the next decade. This would include a cyclotron and a research reactor.
In March 2015 the government signed a cooperation agreement with Argentina to promote and develop infrastructure and institutions for the peaceful use of nuclear energy, following one signed in May 2013. Argentina's support will include the design, construction and operation of nuclear power plants and research reactors, as well as radioactive waste management.
The government says that Iran and France have also offered support. In July 2014 Russia offered Bolivia "a comprehensive plan for the development of nuclear energy for peaceful purposes."
The Mining Corporation of Bolivia (Comibol) is aiming to define and develop uranium resources at Potosi, in Tomas Frias province and in Santa Cruz province.
Peru generated 39.2 TWh in 2011, 14.0 TWh from gas and 21.6 TWh from hydro.
Plateau Uranium (formerly Macusani Yellowcake Inc) of Toronto in mid-2014 acquired the company holding adjacent resources on the Macusani Plateau in southeast Peru and is taking steps towards developing the project. It now reports 19,960 tU indicated and 27,730 tU inferred resources (NI 43-101). Exploration continues. A preliminary economic assessment for Macusani's deposits in December 2013, before the consolidation, suggested production costs at $21/lb U3O8, for output of 1654 tU per year over a ten-year mine life. Both open pit and underground mining would feed a central heap leach.
In 1976 with Soviet encouragement a twin VVER-440 plant was planned at Juragua on the south coast. A small city, Ciudad Nuclear was partly built nearby and opened in 1982. After the collapse of the Soviet Union the project was suspended in 1992 after $1.1 billion had been spent. In 1996 Cuba and Russia discussed reviving it, and Cuba also unsuccessfully sought other partners. In 2000 the two countries abandoned the project. The reactors were to be V-318, based on V-213, with full containment. Siemens was to provide I&C systems. The first reactor was supplied and 37% of the equipment was installed, with the civil construction largely complete. The main turbine was used elsewhere.
Sri Lanka generated 11.65 TWh in 2011, 5.85 TWh of this from oil and 4.6 TWh from hydro. In September 2010 the Sri Lankan government commissioned its Atomic Energy Authority and Ceylon Electricity Board to conduct a pre-feasibility study of using nuclear energy for power generation from about 2025, with technical corporation from the IAEA and following IAEA guidelines. It is revising its Atomic Energy Authority Act accordingly. Sri Lankan scientists and technical experts are being sent to Russia for training.
In 2011 Sri Lanka announced that it would establish an Atomic Energy Regulatory Council to allow for the introduction of nuclear power generation technology in the country, and also to address concerns over the security of radioactive sources and to deal with radiation emergencies.
In February 2015 the government signed a nuclear cooperation agreement with India. It is concerned with capacity building and training in peaceful application of nuclear energy, especially the use of radioisotopes, nuclear safety, radioactive waste management, radiation safety and nuclear security. In April 2015 it signed a nuclear cooperation agreement with Pakistan.
Bangladesh produced 44 billion kWh gross in 2011 from some 6.1 GWe of plant, giving per capita consumption of 280 kWh/yr. In 2011, 40.3 TWh of electricity was from natural gas. Electricity demand is rising rapidly, with peak demand 7.5 GWe, and the government aims to increase capacity to at least 7 GWe by 2014, meanwhile importing some 250 MWe from India. New small coal-fired plants are envisaged for 2 GWe of that, and 3 GWe by 2016. However, about half the population remains without electricity, and the other half experience frequent power cuts. Some 5.0% of government expenditure is being allocated to 'power and energy'.
Building a nuclear power plant in the west of the country was proposed in 1961. Since then a number of feasibility reports have affirmed the technical and economic feasibility. The Rooppur site in Pabna district about 200 km north of Dhaka was selected in 1963 and land was acquired.
With growth in demand and grid capacity since then, a large plant looked feasible, and in 2001 the government adopted a national Nuclear Power Action Plan. In 2007 the Bangladesh Atomic Energy Commission proposed two 500 MWe nuclear reactors for Rooppur by 2015. In April 2008 the government reiterated its intention to work with China in building the Rooppur plant under a 2005 agreement and China offered funding for the project. The International Atomic Energy Agency (IAEA) approved a Technical Assistance Project for Rooppur Nuclear Power Plant to be initiated between 2009 and 2011, and it then appeared that an 1100 MWe plant was envisaged.
Russia, China and South Korea had earlier offered financial and technical help to establish nuclear power, and Russia made a formal proposal to build a nuclear power plant in the country. In 2009 the government approved the Russian proposal to build a 1000 MWe nuclear plant at Rooppur for about $2 billion, though a year later this had become two such reactors by 2017. A nuclear energy bill was introduced into parliament in May 2012, with work to begin in 2013, and setting up a Bangladesh Atomic Energy Regulatory Authority. Parliament was told that 5000 MWe of nuclear capacity was envisaged by 2030.
In May 2010 an intergovernmental agreement was signed with Russia, providing a legal basis for nuclear cooperation, and subsequent agreements with Rosatom were for two 1000 MWe reactors to be built by Atomstroyexport at Rooppur for the Bangladesh Atomic Energy Commission, including fuel supply and return of used fuel to Russia.
In February 2012 the Ministry of Science and Technology signed an agreement with Russia's Rostechnadzor related to regulation and safety "and the provision of advisory support to the Bangladesh Nuclear Regulatory Commission on regulation, licensing and supervision". Staff will be trained in Russia. A further agreement will be for Russian finance. Construction of the first unit is expected from 2013, with operation in about 2018.
The country has had a Triga 3 MW research reactor operational since 1986.
Bangladesh has had a safeguards agreement in force with the IAEA since 1982, and an Additional Protocol in force since 2001.
See also: Bangladesh paper for more up to date information.
Indonesia's population of 242 million is served by power generation capacity of only 35 GWe, producing 182 billion kWh in 2011. Of this, 81 TWh (44%) came from brown coal, 42 TWh (23%) from oil, 37 TWh (20%) from gas, 12 TWh (7%) from hydro and 9 TWh (5%) from geothermal. It has per capita electricity consumption: 475 kWh/yr, but 36% of the population in 2013 have no access to electricity. The government has targeted a 26% reduction in CO2 emissions by 2020.
With an industrial production growth rate of 10.5%, electricity demand is estimated to reach 450 billion kWh in 2026. At present a low reserve margin with poor power plant availability results in frequent blackouts. The Java-Bali grid system accounts for more than three quarters of Indonesia's electricity demand – 132 TWh in 2012. PT PLN (Persero), the Indonesia Electricity Corporation, projects 55 GWe new capacity by 2021, 38 GWe of this coal-fired. It also plans major grid enhancements on Java, on Sumatra, and Kalimantan, with a HVDC link Sumatra to Java.
About 43% of Indonesia's electricity is generated by oil and gas, so as well as catering for growth in demand in its most populous region, the move to nuclear power will free up oil for export. However, in mid-2012 the national Energy Council (DEN) said that nuclear power was an unlikely last resort in the country.
Following earlier tentative proposals, in 1989 the government initiated a study focused on the Muria Peninsula in central Java and carried out by the National Atomic Energy Agency (BATAN – Badan Tenaga Nuklir Nasional) established in 1958.
A 2001 power generation strategy showed that introduction of a nuclear plant on the 500 kV Java-Bali grid would be possible in 2016 for 2 GWe rising to 6-7 GWe in 2025, using proven 1000 MWe technology. The Java-Bali interconnected system accounts for more than three quarters of Indonesia's electricity demand.
Under the 2006 National Electricity Planning Scheme 2006-26 and Presidential Decree #43 in 2006 the project on the central north coast of Java was revived. Plans were to call tenders in 2008 for two 1000 MWe units, Muria 1 & 2, leading to decision in 2010 with construction starting soon after and commercial operation from 2016 and 2017, but these plans were put on hold. Fuel services would be purchased from abroad and fuel would preferably be leased. Used fuel would be stored centrally in the medium term.
In mid-2010 three sites were being considered for main plants: Muria (central Java), Banten (west Java) and Bangka Island (off southern Sumatra to NE, 2 locations: West Bangka and South Bangka). All are on the north shores, away from the tectonic subduction zone. BATAN has undertaken a feasibility study for Bangka, and it has signed an agreement with the Bangka-Belitung provincial government. Bangka is far from any active volcano, has low seismic hazard, no tsunami hazard (shallow sea), and low population.
BATAN’s focus in 2013 shifted to West Kalimantan, using small reactor units suited to the relative lack of grid infrastructure there and where most electricity is imported from Malaysia. In November 2013 the Research & Technology Ministry (RISTEK) affirmed its intention of building a small (eg 30 MWe) power reactor, at an unspecified place, possibly from 2015. In February 2014 the minister was quoted as saying that a 30 MW nuclear power plant would be built by BATAN at Serpong, near Jakarta.
BATAN has undertaken a pre-feasibility study for a small Korean SMART reactor for power and desalination on Madura island. However, this awaits the building of a reference plant in Korea.
The IAEA has been reviewing the safety aspects of both Muria and Madura proposals, with Indonesia's Nuclear Energy Regulatory Agency – Badan Pengawas Tenaga Nuklir (BAPETEN). It was then looking at the Bangka sites. BAPETEN was established in 1998 and reports directly to the President.
In November 2009 the IAEA undertook an Integrated Nuclear Infrastructure Review mission to Indonesia, and reported favourably. During the 1980s Indonesia trained many technical people in anticipation of nuclear power development then, many of these are still available for the new project.
Indonesia has a number of nuclear-related facilities in operation. BATAN operates three research reactors: in Serpong, Banten on the western outskirts of Jakarta (30 MW), Bandung, west Java (2 MW), and in Yogyakarta, central Java (100 kW).
There are some uranium resources in Kalimantan, and possibly West Papua. BATAN in September 2010 quoted 53,000 tonnes as high-cost resources: 29,000 t in West Kalimantan and 24,000 t in Bangka Belitung.
See also Indonesia paper for more detailed and up-to-date information.
The Philippines produced 69.2 TWh gross of electricity in 2011, 25.3 TWh came from coal, 20.6 TWh from gas, 3.4 TWh from oil, 9.7 TWh from hydro and 9.9 TWh from geothermal. Electricity consumption is increasing steadily (22% 2006 to 2011) and additional base-load capacity is required to avert shortages.
In response to the 1973 oil crisis, the Philippines decided to build the two-unit Bataan Nuclear Power Plant (BNPP). Construction of Bataan 1 – a 621 MWe Westinghouse pressurized water reactor – began in 1976 and it was completed in 1984 at a cost of $460 million. However, due to financial issues and safety concerns related to earthquakes, the plant was never loaded with fuel or operated. In April 2007, the Philippine government made the final payment for the plant. The government was considering converting it into a natural gas-fired power plant, but this was impractical, and the plant has simply been maintained at a cost of some $800,000 per year.
In 2007 the Philippines Department of Energy (DOE) set up a project to study the development of nuclear energy, in the context of an overall energy plan for the country. Nuclear energy would be considered in order to reduce the country's dependency on imported oil and coal. In its 2008 update of the national energy plan, 600 MWe was projected on line in 2025, with further 600 MWe increments in 2027, 2030 and 2034 to give 2400 MWe.
In 2008 an IAEA mission commissioned by the government advised that Bataan 1 could be refurbished and economically and safely be operated for 30 years. Refurbishment, with upgrade of safety and instrument & control systems, was estimated to cost $800 million to $1 billion. The IAEA was also to recommend a policy framework for nuclear power development in the country. In December 2008 the National Power Corporation (Napocor) commissioned Korea Electric Power Corp (KEPCO, parent company of KHNP) to conduct an 18-month feasibility study on commissioning Bataan. One factor in choosing KEPCO for this was its experience with Kori 2, a very similar unit in Korea. Its preliminary recommendation in December 2009 was that Bataan should be refurbished. Meanwhile, Toshiba has expressed interest in rehabilitating the plant. In May 2013 Napocor urged the government to refurbish and commission the plant to address power shortages. It estimated the $1 billion cost as being one-third of building equivalent coal-fired capacity. Following sharp rises in electricity prices, in January 2014 the DOE was reported to be studying the prospect of reviving BNPP.
Apart from Bataan, the government was considering two further 1000 MWe Korean Standard Nuclear Plant units, using equipment from the aborted North Korean KEDO project. KEPCO was reported to be offering this equipment for $1.1 billion.
The government established a working group with a view to proceeding along the same lines as Thailand, retaining engineering consultants to guide progress. The Department of Energy is considering how to rebuild local skills in nuclear sciences and engineering, and at the end of 2012 confirmed that nuclear remained a live option of the grounds of costs and clean air. (The state-owned Napocor originally had 710 nuclear engineers who were trained by Westinghouse and Ebasco Overseas Corp. in the 1980s, but this has declined to about one hundred, many of whom are due to retire in the next five to ten years.)
The Philippines' safeguards agreement with the IAEA under the NPT entered force in 1974 and it has signed but not ratified the Additional Protocol. In 1998 it signed the Joint Convention on the Safety of Spent Fuel Management and Radioactive Waste Management.
Electricity demand growth has been 14% pa and is expected to be 15% pa to 2015, then slowing to 2020. A 500 kV grid runs the length of the country and some 95% of the rural population has access to electricity. Over one third of its electricity comes from hydro, one third from gas and the rest from coal or imported from China.
Projections of power demand escalate from 21 GWe in 2010, with 95.5 GWh expected, to 64.8 GWe in 2020 (28% hydro, 35% coal, 17% gas, 1.5% nuclear), and 125 GWe in 2030, including 8% nuclear (with nuclear share then increasing to 20%).
In the early 1980s two preliminary nuclear power studies were undertaken. In February 2006 the government announced that a 2000 MWe nuclear power plant should be on line by 2020. This general target was confirmed, with the target being raised to a total of 8000 MWe nuclear by 2025.
Since October 2008, two reactors total 2000 MWe have been planned at Phuoc Dinh in the southern Ninh Thuan province. A further 2000 MWe was planned at Vinh Hai in the north-central Ha Tinh province, followed by a further 6000 MWe by 2030.
Atomstroyexport, Westinghouse, EdF, Kepco, a Japanese consortium and China Guangdong Nuclear Power Group (CGNPC) all expressed strong interest in supplying the first two twin-unit plants. The plants will be state-owned under EVN, with no private equity.
The main focus is now on the initial 2000 MWe power plant in Ninh Thuan province. In October 2010 an intergovernmental agreement was signed for Atomstroyexport to build the Ninh Thuan 1 nuclear power plant, using two VVER-1000 or 1200 reactors. It is to be constructed from 2014 as a turnkey project and come into operation from 2020. Rosatom has confirmed that Russia's Ministry of Finance is prepared to finance at least 85% of this first plant, to supply the fuel and take back the used fuel for the life of the plant, as is normal Russian policy for non-nuclear-weapons states.
On the same day in October 2010 an intergovernmental agreement with Japan was signed for construction of a second nuclear power plant in Ninh Thuan province, with its two reactors to come on line in 2024-25. Japan's Ministry of Economy, Trade and Industry (METI), said that Japan Atomic Power Co. (JAPC) and the International Nuclear Energy Development of Japan Co. Ltd. (JINED), would work with EVN on the nuclear power plant project. This will involve financing and insurance of up to 85% of the total cost. In February 2011 JAPC signed an agreement with EVN to advance the feasibility study, and in mid 2011 Tepco confirmed that it would remain part of the Japanese project.
Since 2006, nuclear cooperation agreements have been signed with France, China (in particular with CGNPC), South Korea, Japan, Russia, USA and Canada. In June 2010 the Japan Atomic Energy Agency signed an agreement with the Vietnam Agency for Radiation and Nuclear Safety & Control (VARANS) for infrastructure development for safeguards and nuclear security in respect of nuclear nonproliferation. VARANS is also actively cooperating with NISA (Japan) and Rostechnadzor (Russia), which will set the main regulatory arrangements for the first plant.
An early nuclear cooperation agreement with Russia relates principally to Vietnam's 500 kW Da Lat research reactor, built in 1980. This replaced an earlier US Triga MkII reactor which started in 1963 but was dismantled by the USA in the early 1970s. In 2007 the USA helped convert the DaLat reactor to use low-enriched fuel.
Vietnam's new Atomic Energy Law was passed in June 2008 and came into effect early in 2009. Under this, a national nuclear safety commission responsible to the Prime Minister for safety and licensing was established in July 2010.
The Vietnam Atomic Energy Commission was established in 1976 and is under the Ministry of Science & Technology. A national steering committee with the role of Implementing Organisation, and including the representatives of the different ministries and governmental organizations, was established in May 2010 by the Prime Minister. Electricity of Vietnam (EVN) will be the company responsible for building and operating the plants, and will be the sole investor for the first two plants (each nominally 2 x 1000 MWe).
There are plans to mine uranium in the central Quang Nam province, where resources of 8000 tU are quoted. Canadian company NWT Uranium Corp has been asked to help assess prospects.
Vietnam's safeguards agreement with the IAEA under the NPT entered force in 1990 and it has signed but not ratified the Additional Protocol.
See also Vietnam paper for more up to date information.
In 2009 some 145 billion kWh gross was generated. About 72% was from natural gas, 20% from coal (lignite and imported black coal). Installed capacity in 2009 was 29.2 GWe, half of it gas-fired. For 2020, 45 GWe capacity is planned, and more than half of the electricity will still come from gas. Thailand has the potential to be a regional electricity hub for ASEAN countries, though power imports are expected to rise from 5% in 2010 to 14% in 2020 and 18% in 2030.
Tentative plans to embark on a nuclear power program have been revived by a forecast growth in electricity demand of 7 per cent per year for the next twenty years. As gas prices rose, the Atomic Energy Commission and its Office of Atoms for Peace (OAP) however have been assessing the feasibility of nuclear power, and any initial plants would probably be built by the Electricity Generating Authority of Thailand (EGAT). Independent power producers have also expressed interest. The Ministry of Science & Technology is responsible for the issue.
Thailand's National Energy Policy Council commissioned a feasibility study for a nuclear power plant in the country and in 2007 approved a Power Development Plan for 2007-2021 including the construction of 4000 MWe of nuclear generating capacity, starting up in 2020-21. In the new Power Development Plan 2010-30 which was approved in 2010, there is 5000 MWe envisaged, with 1000 MWe units starting up over 2020-28. The first power plant will be internally financed.
In June 2007 cabinet set up under the National Energy Policy Council a Nuclear Power Program Development Office and appointed an Infrastructure Establishment Committee, the Nuclear Power Utility subcommittee of which is supervising EGAT in this project. The Energy Minister budgeted some US$ 53 million over 2008 - 2011 on preparatory work, half of it coming from oil revenues. Construction of the first unit by EGAT is to commence in 2014. The capital cost is expected to be US$ 6 billion and electricity cost about USD 6 cents/kWh, slightly less than from coal. The pre-project phase involves the 3-year feasibility study leading to a firm government decision to proceed (or not) is due to conclude in 2011.
The government plans to establish safety and regulatory infrastructure by 2014 and commissioned a formal 3-year feasibility study early in 2008. Then in October 2008 the engineering firm Burns & Roe was commissioned to undertake a 20-month study to recommend siting, technology and reactor size for the first plant. The project will then go out to tender with a view to starting construction in 2014. The EGAT feasibility study listed five possible sites for the project. Three were on the southern peninsula near Surat Thani and Nakhon Si Thammarat, but these were ruled out in 2010 due to local resistance. Ubon Ratchathani in the east near Laos and Nakhon Sawan 200 km north of Bangkok were also listed and have now been selected, subject to cabinet approval in 2011. There were significant difficulties in assessing potential sites due to local opposition based on past experience with industrial developments compounded by the political situation in the country. Public information and community consultation are identified as very high priority areas for attention. Following the Fukushima accident, plans were put on hold so that the first reactor is now expected on line in 2023.
In November 2009 EGAT and CLP Holdings Ltd signed an agreement with China Guangdong Nuclear Power Corporation regarding nuclear power development. In November 2010 EGAT signed an agreement with Japan Atomic Power Co to provide support on building nuclear power plants. It will provide advice on compiling specifications, on bidding procedures and training engineers. In September 2014 the Thailand Institute of Nuclear Technology signed a nuclear cooperation agreement with Rosatom including radioisotopes, nuclear safety, physical and radiation protection, nuclear fuel cycle services, and radioactive waste management.
Thailand has had an operating research reactor since 1977 and a larger one was under construction but is apparently halted. They are under OAP.
Thailand's safeguards agreement with the IAEA under the NPT entered force in 1974 and it has signed but not ratified the Additional Protocol.
Malaysia produced 130 billion kWh gross in 2011, 58 (45%) of this from gas, 53 (41%) from coal, 7.6 (6%) from hydro and 10 (8%) from oil. The Energy Commission showed 28.4 GWe capacity in 2011, 51.6% of this gas and 27% coal. Government policy is to reduce reliance on natural gas by building coal-fired capacity, and in 2014 further coal-fired plants were being built. It is noteworthy that Singapore has about 12 GWe of (mostly gas) capacity, and any Malaysian project could be related also to that market.
What is now the Malaysian Nuclear Agency (MNA) was established in 1972 with a research focus, and has operated the Puspati Triga research reactor since 1982. The Atomic Energy Licensing Board was set up in 1985 under the Ministry of Science to supervise.
A comprehensive energy policy study has been undertaken and in June 2009 the government decided formally to consider nuclear power. A Nuclear Power Development Steering Committee was set up, to plan and coordinate the nuclear power development program through three working groups. Late 2013 was set as target date for the steering committee's Nuclear Power Infrastructure Development Plan (NPIDP), at which point the government would decide whether to proceed. In May 2010 the Energy Minister said that nuclear power was the only viable energy option long-term. Under the NP Steering Committee are three bodies: Nuclear Power Program Working Group under the Malaysian Nuclear Energy Agency (MNA), the Nuclear Power Project Working Group under the utility Tenaga Nasional Berhad (TNB, which has one quarter of the country's installed capacity), and a Legal and Regulatory Coordination Working Committee involving the Atomic Energy Licensing Board (AELB) and the Energy Commission.
In January 2011 the Malaysia Nuclear Power Corporation (MNPC) was commissioned under the new Economic Transformation Program (ETP) to spearhead the eventual deployment of nuclear power plants in a 12-year time frame. It is the Nuclear Energy Program Implementing Organisation (NEPIO) under IAEA ‘milestone’ guidelines. The technical support organisation (TSO) under those guidelines is likely to be MNA. The TSO is to support the regulator, the plant operator, and local industry, as well providing advice to government including on technology transfer and waste policies. A new nuclear law is expected about the end of 2014.
Malaysia wants a proven type of 1000 MWe-class reactor which is already deployed. Plans are to be presented to the government in 2015. In July 2014 the minister responsible for MNPC announced a feasibility study including ‘public acceptance’ on building a nuclear power plant to operate from about 2024. Then 3-4 reactors providing 10-15% of electricity by 2030.
(Prior to all this, in August 2006 the Atomic Energy Licensing Board said that plans for nuclear power after 2020 should be brought forward and two reactors built much sooner. In July 2008 the government had directed TNB to set up a task force to look at the feasibility of nuclear power. In September 2008 the government announced that it had no option but to commission nuclear power due to high fossil fuel prices, and it set 2023 as target date. It then sent a draft energy policy blueprint back to the Energy Commission as it was not comprehensive enough. The ETP is the latest attempt to forge a national energy policy including nuclear power.)
As of early 2010 the government had a $7 billion budget to build a nuclear power plant, and in May the Ministry of Energy, Green Technology and Water was told to find a suitable site so that the first unit could be in operation by 2021. Five possible locations on peninsula Malaysia have been identified. The next step was to be the appointment of consultants to prepare a feasibility study, along with developing the regulatory framework, the soft infrastructure, and winning public support. The government is working with other SE Asian countries to harmonise regulations relating to nuclear power development.
In May 2010 the chairman of the Malaysian Nature Society recommended that the state of Sabah consider nuclear energy as an alternative to coal.
The Malaysian Institute for Nuclear Technology Research has operated a 1 MW Triga research reactor since 1982. In April 2007 MINT was renamed the Malaysian Nuclear Agency (MNA, or Nuclear Malaysia) to reflect its role in promoting the peaceful uses of atomic energy through active public information and publications. The reactor was refurbished and modernised over 2000-13.
Malaysia's safeguards agreement with the IAEA under the NPT entered force in 1972 and it has signed but not ratified the Additional Protocol. For some years Malaysia was a unregulated transhipment point for nuclear technology smuggling by Iran, Pakistan and North Korea, but in April 2010 it adopted an export control law to thwart this activity.
Singapore has relatively high power demand (peak 14 GWe) for its size, and is 80% dependent on gas-fired generation for 38 TWh/yr, the fuel being piped from Indonesia. It is considering the prospects of using nuclear power, but is more likely to join with Malaysia in any project there, due to siting constraints. In November 2010 the prime minister said that Singapore "cannot afford to dismiss the option of nuclear energy altogether." In October 2012 a government study concluded that while Singapore needs to keep monitoring nuclear energy technology developments and should strengthen its capabilities in that field, present technologies are not suitable for the island. “The risks to Singapore, given that we are a small and dense city, still outweigh the benefits at this time.”
Australia produces about 80% of electricity from coal-fired plant, 12% from gas and 7% from hydro. This gives it a high output of CO2, which is the main reason for consideration of possible nuclear generation in the future. Low-cost power has been a competitive advantage of the country, and nearly 10% of its electricity is embedded in aluminium exports. Australia joined the Global Nuclear Energy Partnership (GNEP) in September 2007.
Australia has operated a research reactor since 1956 and has now commissioned its 20 MWt replacement.
About 1970 the Australian government sought tenders for building a nuclear power reactor at Jervis Bay, NSW. Designs from UK, USA, Germany and Canada were short listed, but a change in leadership led to the project being cancelled in 1972. However, until 1983 there were various plans and proposals for building an enrichment plant.
At the end of 2006 the report of the Prime Minster's expert taskforce considering nuclear power was released. It said nuclear power would be 20-50% more expensive than coal-fired power and (with renewables) it would only be competitive if "low to moderate" costs are imposed on carbon emissions (A$ 15-40 - US$ 12-30 - per tonne CO2). "Nuclear power is the least-cost low-emission technology that can provide base-load power" and has low life cycle impacts environmentally. The first nuclear plants could be running in 15 years, and looking beyond that, 25 reactors at coastal sites might be supplying one third of Australia's (doubled) electricity demand by 2050. Certainly "the challenge to contain and reduce greenhouse gas emissions would be considerably eased by investment in nuclear plants." "Emission reductions from nuclear power could reach 8 to 18% of national emissions in 2050".
See also: Australia and Australia's Electricity papers.
The Democratic People's Republic of Korea (DPRK, aka North Korea) generated 34 TWh in 2002, 19 TWh in 2003 and 19 TWh in 2012 – 13.5 TWh from hydro, 5.2 TWh from coal and 0.6 TWh from oil. Consumption in 2012 was 14.4 TWh among 25 million, so per capita consumption was less than 600 kWh, much less than ten years earlier. Recent estimates suggest that operable generating capacity is 2000-3000 MWe.
In 1985, it brought into operation a small gas-cooled, graphite-moderated, natural-uranium (metal) fuelled "Experimental Power Reactor" of about 25 MW (thermal) at Yongbyon. It exhibited all the features of a plutonium production reactor for weapons purposes and produced only about 5 MWe as an incidental feature. North Korea also made substantial progress in the construction of two larger reactors designed on the same principles, a prototype of about 200 MWt (potentially 50 MWe) at Yongbyon, and a full-scale version of about 800 MWt (potentially 200 MWe) at Taechon.
In 1999 a contract to build two 1000 MWe light-water reactors was signed as part of an international deal to dissuade North Korea from its weapons program. The agreement was between the Korean Energy Development Organisation (KEDO), the international organisation in charge of the project, and the South Korean utility KEPCO, bringing technology to build a nuclear power plant which is not amenable to misuse. KEDO was set up following the 1994 agreement involving the USA to head off the production of weapons plutonium from the small gas-graphite reactor and to provide much needed energy – in the short term fuel oil, but eventually electricity.
KHNP is the prime contractor for KEDO which was starting to build the two reactors at Kumho in North Korea. If completed, these would have been the last basic KSNP units commissioned. In 2005 South Korea offered 2000 MWe from the grid to North Korea.
Construction of the reactors under KEDO was suspended late in 2003, and this suspension was renewed in 2004 and 2005. The KEDO board terminated the project in May 2006. Most of the fabrication of steam generators, pressure vessels and other equipment for both reactors was complete, and the parts were in storage. This equipment belongs to KEPCO and is likely to be sold off to other nuclear projects, including South Korean export ones.
North Korea is not currently considered as having serious intentions to deploy nuclear power for electricity.
DPRK was a party to the Nuclear Non-Proliferation Treaty (NPT) as a non-nuclear weapons state, but it delayed concluding its safeguards agreement with the IAEA, and in April 2003 it withdrew from the NPT. In October 2006 it exploded a nuclear device underground.
In February 2007 DPRK agreed to shut down and seal the Yongbyon reactor and related facilities including reprocessing plant within 60 days and accept IAEA monitoring of this, in return for assistance with its energy needs. Further assistance would follow the irreversible disabling of the reactor and all other nuclear facilities.
In May 2009 it exploded another nuclear device underground, more successfully (ie yield was apparently in line with probable design, unlike the test in 2006).
See also: Iraq, North Korea & Iran - Implications for Safeguards- Appendix to Safeguards paper.
IAEA 2004, Country Nuclear Power Profiles.
IAEA 2010, International Status and Prospects of Nuclear Power
OECD/IEA 2007, Energy statistics of non-OECD countries
McCloskys country profiles on Jordan and Egypt.