Emerging Nuclear Energy Countries

  • About 30 countries are considering, planning or starting nuclear power programmes.
  • These range from sophisticated economies to developing nations.
  • Bangladesh, Egypt and Turkey are all constructing their first nuclear power plants.

About 30 countries are considering, planning or starting nuclear power programmes, and a further 20 or so countries have at some point expressed an interest. In the following list, links are provided for those countries that are covered by specific country pages:

  • In Europe: Albania, Serbia, Croatia, Norway, Poland, Estonia, Latvia, Lithuania, Ireland, Turkey.
  • In the Middle East and North Africa: Gulf states including Saudi Arabia, Qatar, Kuwait and Iraq; Yemen, Israel, Syria, Jordan, Egypt, Tunisia, Libya, Algeria, Morocco, Sudan.
  • In west, central and southern Africa: Nigeria, Ghana, Senegal, Kenya, Uganda, Tanzania, Zambia, Namibia, Rwanda, Ethiopia.
  • In Central and South America: Cuba, Chile, Ecuador, Venezuela, Bolivia, Peru, Paraguay.
  • In central and southern Asia: Azerbaijan, Georgia, Kazakhstan, Mongolia, Bangladesh, Sri Lanka, Uzbekistan.
  • In Southeast Asia and Oceania: Indonesia, Philippines, Vietnam, Thailand, Laos, Cambodia, Malaysia, Singapore, Myanmar, Australia.
  • 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 power programmes or plans have progressed:

1. Under construction = first concrete for reactor poured.
2. Planned = Approvals, funding or commitment in place, mostly expected to be in operation within the next 15 years.
3. Proposed = Specific programme or site proposals; timing very uncertain.

A July 2021 report by the International Atomic Energy Agency (IAEA) on International Status and Prospects of Nuclear Power1 said that some 28 member states without nuclear power plants “are considering, planning or actively working” to include nuclear into their energy mix. Of these 28 un-named countries, it said ten to twelve plan to operate nuclear plants by 2030-2035.

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 of the capacity of the grid (maybe 15% if there is high reserve capacity). This is so that the plant can be taken offline for refuelling 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 the UK, USA, France, Russia and China while they focus on building competence to license the actual operation of plants.

State-owned nuclear companies in Russia and China have taken the lead in offering nuclear power plants to emerging countries, usually with finance and fuel services. The following table charts the main influence in countries with various agreements but not yet any plants under construction (see also the relevant tables in the information pages on China and Russia):

Russia China Other
Jordan Sudan Poland
Egypt Kenya Lithuania
Tunisia Thailand Philippines
Algeria Cambodia Kenya
Morocco   Uganda
Sri Lanka    

IAEA support for new nuclear programmes

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.*

* See Safeguards to Prevent Nuclear Weapons Proliferation, and Liability for Nuclear Damage respectively.

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 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 programme, resulting in set up of a nuclear energy programme implementing organization (NEPIO). This deals with the programme, 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 evaluate the status of countries’ nuclear infrastructure development, building on member states’ self-evaluation. The first three were to Jordan, Indonesia and Vietnam. Since then, INIR reviews have been conducted in Bangladesh, Belarus, Egypt, Ghana, Kazakhstan, Malaysia, Morocco, Niger, Nigeria, Philippines, Poland, Saudi Arabia, Thailand, Turkey and United Arab Emirates. In 2013 an INIR mission was to South Africa – the first country with an operating nuclear power programme that has requested this service. 

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 programme 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.

IAEA Site and External Events Design (SEED) missions review the design and siting of nuclear plants against external hazards specific to the site. The programme arose from the Fukushima accident and involves the IAEA’s International Seismic Safety Centre (ISSC), which has conducted over 430 site external hazard evaluations since 1980.

The IAEA also has an Integrated Regulatory Review Service (IRRS) to scrutinize the regulatory structures in particular countries, upon invitation from the government. Though mostly used for countries with established nuclear power, it is also used for countries embarking upon nuclear power programmes, as in Iran in 2010, Poland early in 2013, Jordan and Vietnam in 2014, UAE and Indonesia in 2015, Bangladesh and Belarus in 2016, and the United Kingdom in 2019.

In March 2020 the IAEA published new guidance to countries planning to adopt nuclear power in a document titled Initiating Nuclear Power Programmes: Responsibilities and Capabilities of Owners and Operators. It takes into account more than ten years of experience and good practices in countries that are introducing nuclear power, as well as lessons learned during INIR missions, and IAEA technical assistance activities to newcomer countries. Together with the nuclear energy programme implementing organization (NEPIO) and the nuclear regulatory body, the nuclear plant owner-operator is one of the three key organizations identified in the 'milestone' approach. The publication is a significant revision of a document first issued in 2009. 

WANO and ASN support for new nuclear programmes

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 programme, particularly to address the situation of new plants in countries and organisations without previous nuclear power experience. 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.

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. ASN said it takes at least five years to set up the legal and regulatory infrastructure for a nuclear power programme, 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 is focused on helping to set up structures and systems to enable the establishment of civil nuclear programmes in countries wanting to develop them.

The rest of this page documents progress in a number of countries. Where an individual page on the particular country exists (as indicated), more details will be found there.



2020 production of 5.3 TWh, virtually all from hydro. 

Following droughts that limited power supply to four hours per day, the government in 2007 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.


2020 production of 13.4 TWh: 5.8 TWh hydro; 4.7 TWh fossil fuels; 1.7 TWh wind. 

The country imports over one-third of its electricity requirements and is co-owner with Slovenia of the Krsko nuclear plant close to the border. It has considered 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. In 2010 Croatia rejected an offer to invest in Bulgaria's Belene plant.


2021 production of 7.3 TWh in Estonia: 4.4 TWh fossil fuels; 1.9 TWh biofuels & waste; 0.7 TWh wind.

These countries had not been planning to build any nuclear capacity themselves and were participants in a stalled plan to build the new 3400 MWe Visaginas nuclear plant in Lithuania. This was planned to replace the Ignalina plant there with much larger capacity to serve the three Baltic states and Poland. See information pages on Nuclear Power in Lithuania, and Nuclear Power in Poland.

Estonia generates most of its electricity from shale oil at state-owned Eesti Energia's 2380 MWe Narva plant, with CO2 output of 1.2 kg/kWh.

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 required 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 got underway.

Fermi Energia was set up in February 2019 by a group of Estonian science and energy professionals including the former head of Eesti Energia to deploy small modular reactors (SMRs) in the country. It then signed an agreement with UK-based Moltex Energy to undertake a feasibility study to investigate how far the development of SMR technology has progressed, cost conditions, licensing and, in general, what future there might be for such a reactor in the Baltic country. In March 2020 Sweden's Vattenfall joined Finland's Fortum and Belgian Tractabel in the study which is expected to report early in 2021. Fermi Energia is including NuScale SMR, Terrestrial Energy ISMR-400, GE Hitachi BWRX-300 and Moltex SSR-W300 in its feasibility study. The company said that Estonia had "no other credible choice" than nuclear energy for security of power supply with shale oil power generation decreasing to 2030 – but that it would need to be from SMRs. Viru-Nigula on the north coast has offered to host a nuclear plant. In August 2022 NuScale Power signed a memorandum of understanding with Fermi Energia to consider the development of NuScale SMRs. In September it issued tender documents to NuScale Power, Rolls-Royce SMR and GE Hitachi, and in October it commenced a site selection feasibility study.

Estonia has recently completed a 350 MW DC cable interconnector with Finland – Estlink – costing €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 had 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 50 years. The fuel has been returned to Russia.

In January 2023 a spatial analysis working group of the Estonian Ministry of Finance published an interim report proposing 16 possible coastal locations for nuclear power plants. The working group’s final analysis had been expected to be completed in March 2023, with the government’s final nuclear energy feasibility study to be issued at the end of the year.

In February 2023 Fermi Energia announced that it had chosen GE Hitachi's BWRX-300 as the technology for the planned SMR plant to be built by the early 2030s. In July 2023 Fermi Energia completed geological studies in the Viru-Nigula municipality of northeastern Estonia to assess the suitability of the area for the construction of an SMR plant. Fermi Energia is also considering a site in the neighbouring Lüganuse municipality.


2021 production of 31.9 TWh: 19.8 TWh fossil fuels; 9.7 TWh wind; 1.0 TWh hydro; 1.3 TWh biofuels & waste.

Ireland has committed to increasing the share of electricity generation from renewables to 70% of total generation by 2030. Additionally, all peat- and coal-fired power plants would be shut by 2023.

The push to develop renewable energies and to decommission alternative fossil fuel plants will result in an increased reliance on natural gas, as gas-fired power plants would be required to provide flexibility in electricity supply. From mid-2020s, a sharp decrease in domestic gas production is expected, and in the absence of any LNG infrastructure, nearly all of Ireland’s gas supply is likely to be imported through a single transit point in Scotland. A 2019 International Energy Agency report, Ireland: 2019 Review, noted Ireland’s “high reliance on a limited amount of gas infrastructure, raising concerns for security of gas supply in Ireland” – and, by extension, electricity supply.

In the 1970s, the Irish government considered building a 650 MWe nuclear power plant (PWR) at Carnsore Point, but the plan was dropped in the 1980s 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 at the time. To facilitate this plant, the 1971 Nuclear Energy Act was passed, which established the Nuclear Energy Board to pursue policy options to develop nuclear power. As nuclear power was not developed, the Board was replaced by the Radiological Protection Institute of Ireland, which is now part of the Environmental Protection Agency (EPA).

Ireland currently has two effective statutory bans on nuclear power: the 1999 Electricity Regulation Act and the 2006 Strategic Infrastructure Act, which legislate against the permitting of a nuclear fission plant and the planning approval of a nuclear fission plant, respectively. However, there have been repeated calls for debate of this topic since 2006.

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 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 continued into 2013 as the EPA 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 400 kV transmission infrastructure is in place.

In 2020, the call for public debate was renewed with the publication of Nuclear Energy Development in Ireland by 18for0. Also in 2020, the Irish Minister for Environment, Climate and Communications said that he had “not ruled out” nuclear development in Ireland.


2021 production of 287 TWh: 167 TWh fossil fuels (including 142 TWh natural gas); 46.8 TWh hydro; 25.0 TWh solar; 20.8 TWh wind; 20.6 TWh biofuels & waste; 5.9 TWh geothermal.

See information page on Nuclear Energy in Italy.


2021 production of 158 TWh: 144 TWh hydro; 11.8 TWh wind; 0.9 TWh fossil fuels.

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.

In November 2023 Norwegian energy company Østfolda established a new project company called Halden Kjernekraft AS to carry out initial investigations and surveys to aid the decision over the construction of SAMRs in Halden.


2021 production of 179 TWh: 148 TWh fossil fuels (including 130 TWh coal); 16.2 TWh wind; 8.5 TWh biofuels & waste; 3.1 TWh hydro.

See information page on Nuclear Power in Poland.


2020 production of 38.0 TWh: 27.0 TWh fossil fuels; 9.7 TWh hydro; 1.0 TWh wind.

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.

In 2019 Russia and Serbia signed an intergovernmental agreement on cooperation in the construction of a Centre for Nuclear Science, Technology and Innovation in Serbia.


2021 production of 331 TWh: 213 TWh fossil fuels; 55.7 TWh hydro; 31.1 TWh wind; 13.3 TWh solar; 10.8 TWh geothermal; 6.3 TWh biofuels & waste.

See information page on Nuclear Power in Turkey.

Middle East

Gulf states

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.

The GCC countries share a common grid apart from Saudi Arabia. Almost all electricity is from fossil fuels, and 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 programme. Saudi Arabia was leading the investigation and thought that a programme 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.


2020 production of 91.4 TWh: 54.2 TWh natural gas; 32.2 TWh oil; 4.9 TWh hydro.

Iraq has suffered with electricity shortages since the Iraq War in 2003.

The chairman of the Iraqi Radioactive Sources Regulatory Authority announced in June 2021 that Iraq planned to build eight reactors with about 11 GWe capacity and would seek funding from prospective partners for the $40 billion plan, paying back the costs over 20 years. It was considering South Korean and Russian vendors.


2021 production of 74.0 TWh: 68.1 TWh fossil fuels; 5.5 TWh solar.

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 Infrastructures 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 programme.


2020 production of 21.0 TWh: 16.8 TWh fossil fuels (including 16.0 TWh natural gas); 2.9 TWh solar; 1.4 TWh from wind.

See information page on Nuclear Power in Jordan.


2020 production of 74.8 TWh, virtually all from fossil fuels.

Kuwait was considering its own nuclear programme 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 €600 million equity (4.8%) in Areva. Kuwait also has nuclear cooperation agreements with the 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, a decision confirmed in 2016. 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 68 TWh production in 2015 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.


2020 production of 38.2 TWh, virtually all from fossil fuels.

Oman has 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 August 2017 Berkeley Energia arranged finance to bring its Salamanca uranium mine project in Spain into production through a $120 million convertible loan and option package with Oman’s sovereign wealth fund. This would see Oman become a substantial shareholder in the company.


2020 production of 49.3 TWh, all from natural gas.

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. In 2015 it produced 4 TWh, all from gas. In 2010 Qatar signed a nuclear cooperation agreement with Russia's Rosatom.

Saudi Arabia

2020 production of 395 TWh, virtually all from fossil fuels.

See information page on Nuclear Power in Saudi Arabia.


2020 production of 16.4 TWh: 15.6 TWh fossil fuels; 0.8 TWh hydro.

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.


2020 production of 2.9 TWh; 2.4 TWh fossil fuels; 0.5 TWh solar.

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.


In July 2015 an agreement was drafted by several countries for cooperation in the development of an integrated West African regional nuclear power programme, with a three-year action plan. The countries concerned at the Niger meeting were: Benin, Burkina Faso, Ghana, Mali, Niger, Nigeria, and Senegal, collectively the West African Integrated Nuclear Power Group (WAINPG). This followed the third African Conference on Energy and Nuclear Power held in April 2015 in Mombasa, Kenya, and also relates to plans by the Economic Community of West African States (ECOWAS) to implement a West Africa Power Pool (WAPP). This is stimulated by World Bank funding for the first phase of the $1.3 billion Eastern Africa power integration programme, with the intention of forming an Eastern African Power Pool (EAPP).

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: “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.”


2020 production of 79.2 TWh: 78.4 TWh from fossil fuels (including 78.1 TWh natural gas); 0.7 TWh solar.

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.” Another agreement with Rosatom was signed in April 2016, including the possibility of building a nuclear power plant, and a further agreement in September 2016 involved design, construction, operation and maintenance of nuclear power plants in Algeria with a view to the first being completed in 2026.

In May 2016 a preliminary cooperation agreement was made with China National Nuclear Corporation (CNNC), relating to a nuclear research centre, the Hualong One reactor, the ACP100 small reactor and renewable energy projects.

In September 2009 its National Mining Patrimony Agency put uranium exploration leases in the southern Tamanrasset province out for tender. The 2022 'Red Book' shows the country having 19,500 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 and was refurbished 2016-2019 by CNNC Zhongyuan, the Nur 1 MWt pool unit was built by INVAP of Argentina in the 1980s.


2020 production of 15.5 TWh: 14.9 TWh hydro; 0.6 TWh wind.

In June 2017 the Ministry of Science and Technology signed a broad agreement with Rosatom, including nuclear research centres with research reactors. Two further agreements were signed in April 2021.

In October 2019, Ethiopia and Russia signed an intergovernmental agreement on cooperation in the peaceful uses of nuclear energy.


2020 production of 192 TWh: 168 TWh fossil fuels (including 161 TWh natural gas); 15.0 TWh hydro; 4.5 TWh solar; 4.2 TWh wind.

See information page on Nuclear Power in Egypt.


2020 production of 19.7 TWh: 12.4 TWh fossil fuels; 7.3 TWh hydro.

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 is responsible for all the issues associated with the planning and implementation of a nuclear power programme, for coordinating the activities of all stakeholder institutions involved in the planning of it, and for developing legal and regulatory frameworks. Eight technical groups were set up to undertake planning and implementation. Three potential sites have been identified by the Energy Ministry.

In 2012 the Ministry of Energy & Petroleum signed a nuclear 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. In June 2015 a nuclear cooperation agreement with Rosatom was signed by the Ministry of Environment, Science, Technology and Innovation, to enable the development of contractual and legal frameworks for cooperation between the two countries in the nuclear sector. It also enables the promotion of Russian technology in West African markets and the practical start of joint nuclear projects, Rosatom said. Nigeria is open to the possibility of a foreign build-own-and-operate (BOO) project for nuclear power, such as is Russian policy.

In February 2015 Ghana is reported to have signed or ratified several IAEA conventions, including the Convention on Supplementary Compensation for Nuclear Damage (CSC). Ghana joined the Global Nuclear Energy Partnership (GNEP), now the International Framework of Nuclear Energy Cooperation (IFNEC), in September 2007.

The Nuclear Regulatory Power Act to establish an independent nuclear regulatory body, the Ghana Nuclear Regulatory Authority (NRA), was passed by parliament in August 2015, to take over from the Radiation Protection Board. Its seven members were appointed in January 2016. The Act is another prerequisite for operating a nuclear power plant. In January 2017 Ghana hosted an IAEA Integrated Nuclear Infrastructure Review (INIR) mission to evaluate the situation against the IAEA 'milestones approach' for such countries. It reported in May 2017, and in October 2019 a follow-up mission reported good progress in the implementation of the initial mission's recommendations. In 2018 Nuclear Power Ghana (NPG) was set up to manage the country's first nuclear power project. It was registered as a company in July 2019. In June 2020 Ghana passed the first IAEA pre-project milestone. In August 2021 NPG said that it expected to start producing nuclear electricity in 2030 at $50 to $80/MWh.

In September 2021 Ghana’s Minister of Environment, Science, Technology and Innovation said that five vendors – from the USA, Russia, Canada and South Korea – had responded to a request for interest issued to help the country build its first plant. The expectation is that a contract will be signed for a 1 GWe plant sometime in 2024/2025.

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 (MNSR), operated since 1994 by GAEC’s National Nuclear Research Institute (NNRI). This was converted by the China Institute of Atomic Energy (CIAE) to run on low-enriched uranium (LEU) in 2017, the first of five Chinese-supplied research reactors outside China to be converted to LEU. It originally used 90%-enriched fuel, which was returned to China.

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. This is represented as the designated centre for nuclear science education in west Africa.

In September 2023 NPG announced that it selected Nsuban in Ghana’s Western Region as its preferred nuclear power plant location, with Obotan in the Central Region as a backup site.


2020 production of 11.6 TWh: 5.1 TWh geothermal; 4.2 TWh hydro; 1.3 TWh wind; 0.8 TWh oil; 0.1 TWh biofuels; 0.1 TWh solar.

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. In 2016 Kenya's installed electricity generation was 2300 MWe, and the Energy Regulatory Commission plans 6766 MWe capacity by 2020. The 960 MWe Lamu coal-fired plant is expected on line in 2017.

The annual demand growth has reached 7% and on one projection is expected to increase to 15% as the Vision 2030 projects are implemented. Demand was 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. Another projection has 19,000 MWe on line in 2033 including 4000 MWe nuclear, and a lower one projects 6000 MWe demand in 2030, providing 36 TWh with no nuclear contribution. In 2020 demand growth and projections were lower.

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 the Nuclear Electricity Project Committee, which became the Kenya Nuclear Electricity Board (KNEB) in May 2014, and subsequently the Nuclear Power and Energy Agency (NuPEA). It aims to replace some oil and gas-fired capacity with nuclear power. It is charged with fast-tracking the development of nuclear electricity generation in Kenya with a mission to promote "safe and secure application of nuclear technology" for sustainable electricity generation and distribution. In 2016 an IAEA integrated regulatory review (IRR) of Kenya’s Radiation Protection Board was undertaken. The goal of having 1000 MWe of nuclear capacity online by 2025 and 4000 MWe by 2033 was reaffirmed in 2016. In 2020 NuPEA said that the timeline for an initial plant would extend to 2035 and the focus would shift to include small reactors.

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, and an IAEA Integrated Nuclear Infrastructure Review (INIR) mission visited in 2015 to advise the KNEB. Its leader said that "Kenya has given thorough consideration to the infrastructure that will be necessary should the country decide to proceed with the development of a national nuclear power programme." Later reports referred to “towns bordering Lake Turkana, the Indian Ocean and Lake Victoria” as potential sites.

The Energy Ministry noted that a South Korean plant would cost about $3.5 billion, but would provide cheaper electricity than some 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 aimed 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 expected total 2030 Kenya capacity to be almost 18 GWe, with IPPs. It was seeking a partner to produce nuclear power to help meet rising demand and diversify from hydropower, which has little potential for expansion.

In September 2015 an agreement was signed by Kenya Nuclear Electricity Board (KNEB) with China General Nuclear Power (CGN) to investigate building a Hualong One reactor in Kenya. The agreement is to enable Kenya to "obtain expertise from China by way of training and skills development, technical support in areas such as site selection for Kenya's nuclear power plants and feasibility studies," according to KNEB. KNEB is conducting a technology assessment including size and water requirements. A further agreement with CGN was signed in March 2017.

In May 2016 Rosatom signed an agreement covering a wide range of areas, including: assistance in the development of a nuclear energy infrastructure in Kenya; basic and applied research; design, construction and operation of nuclear power and research reactors; production and use of radioisotopes in industry, medicine and agriculture; radioactive waste management; and education and training of specialists in the field of nuclear physics and nuclear energy. The two countries will also continue talks on the practical aspects of constructing the first nuclear power plant in Kenya.

In February 2017 the French minister for economy and finance said that France was keen to help Kenya’s nuclear power development.

In August 2016 KNEB signed an agreement with Korea Electric Power Corporation (KEPCO) to cooperate on construction of nuclear power plants.

The Nuclear Electricity Board said in November 2016 that it planned to start building about 1000 MWe of nuclear capacity in 2021, for operation from 2027. Though costing about $5 billion, it would be to reduce the price of electricity and enable exports in the Eastern Africa Power Pool. A feasibility study was underway.

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. Only 30% of the country’s 44 million people have electricity from the grid.

In September 2023 NuPEA announced that it planned to begin construction of a 1000 MWe nuclear plant located in either Kilifi or Kwale in 2027. The organization was planning to launch an international tender process, with a bidding stage between 2026 and 2027.


2020 production of 29.5 TWh, virtually all from fossil fuels.

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 was to supply this, with some involvement of the French CEA. 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 tentatively selected a site for both power and desalination.

In 2003 Libya had halted a clandestine programme 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 multi-effect distillation and reverse osmosis (MED-RO) system.


2020 production of 40.1 TWh: 31.4 TWh fossil fuels; 4.6 TWh wind; 1.5 TWh solar; 1.3 TWh hydro.

Morocco has a growing electricity demand and requirements for desalination.

In October 2007 a partnership with France to develop a nuclear power plant near Marrakesh was announced and a nuclear energy cooperation agreement was later signed. A further cooperation agreement was signed in mid-2010. A 600 MWe nuclear power plant was to be sited on the coast between the cities of Essaouira and Safi, 130 km from Marrakesh.

The government then had plans for building an initial nuclear power plant in 2016-17 at Sidi Ghouzia, near Safi, and Atomstroyexport assisted with feasibility studies for this. It was also setting up the infrastructure to support a nuclear power programme, including establishment of a nuclear safety authority and a radiation protection authority.

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, but has not done so.

In January 2011 the government approved plans to set up a nuclear safety agency and draft a law on nuclear security. An IAEA INIR review took place in 2015.

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.

Morocco has a 2 MW Triga research reactor under construction at Mamoura near Rabat.

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 byproduct 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.


2020 production of 2.0 TWh: 1.5 TWh hydro; 0.4 TWh solar.

A natural gas-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. The government had articulated a policy position of supplying its own electricity from nuclear power by about 2018, but there was no evident progress towards this. The country faces severe challenges in power supply.

See also information page on Uranium in Namibia for further information.


2020 production of 32.4 TWh: 24.7 TWh natural gas; 7.7 TWh hydro.

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 privatizes new generation and transmission projects. In the first phase of its liberalization 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 were contractually obliged to increase generation for each plant over five years. An additional 2 GWe increase was 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. In June 2015 Geometric Power announced that it planned to build a 1080 MWe power plant in Abia state, in the southeast, in partnership with GE.

In November 2019 the Senate of Nigeria called on the government to consider the inclusion of nuclear power in the country's energy mix.

The government is planning to increase the use of solar power, and an agreement was signed in May 2014 to build 3 GWe of utility-scale solar PV capacity in a $5 billion public-private partnership project with Skypower FAS Energy. A feed-in tariff (FIT) regime was 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 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 for its nuclear energy programme, 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 startup. 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, which took place in 2015.

The Nigerian Nuclear Regulatory Authority (NNRA) has been set up for regulatory oversight on all uses of ionizing radiation, nuclear materials and radioactive sources under the federal Ministry of Science & Technology.

The Nigerian Atomic Energy Commission (NEAC) set up under 1976 legislation 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 southeast, Agbaje, Okitipupa in Ondo state in the southwest zone and Lau in Taraba state in the northeast zone. The first two sites, Geregu and Itu, were evaluated in 2014-15 and confirmed as preferred. Preliminary licensing was expected by the NNRA in 2016. Rosatom said it expected two reactors to be built at each site.

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. A further three nuclear plants were 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 programme 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 confirmed that Russian financing options would be available to Nigeria, whose preferred option is a build-own-operate (BOO) arrangement with majority Rosatom equity. This was to be confirmed in a further intergovernmental agreement. Early in 2015 the intention was to have a first unit online 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. No more has been heard of this.

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 highly 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.


2020 production of 0.9 TWh: 0.5 TWh hydro; 0.3 fossil fuels.

In December 2018 Russia and Rwanda signed an intergovernmental agreement on the use of nuclear energy. Electricity generating capacity in 2018 was 218 MWe, with about 35% access to electricity. Increased urbanisation to 35% with full household access (including almost half being off-grid) and full productive user access is expected by 2024. Projected generating capacity by 2024 is 282-376 MWe. Regional integration is increasing and almost full interconnection is expected by 2022.

In October 2020 Rwanda’s government approved the establishment of the Rwanda Atomic Energy Board (RAEB), which is intended to coordinate research and development of nuclear energy activities in the country.

In September 2023 the RAEB signed an agreement with Dual Fluid Energy, a Canadian-German nuclear technology company founded in 2021, for the construction of a demonstration Dual Fluid reactor. Dual Fluid Energy said the first-of-a-kind unit – a liquid fuel, lead-cooled, high-temperature fast reactor – is expected to be completed in 2026, with full startup envisioned by 2028.


2020 production of 5.8 TWh: 5.0 TWh fossil fuels; 0.4 TWh solar; 0.1 TWh wind; 0.1 TWh biofuels.

Early in 2010 Senegal announced that as part of its policy to replace oil for power generation, and to integrate with the West African Power Pool (WAPP), it was considering a nuclear power plant by about 2020. The energy minister was keen to establish an African Commission for Nuclear Energy with headquarters in Dakar. However then in 2011 the President said that he had cancelled plans for nuclear power. Domestic demand is only 550 MWe, but is growing at 7% per year. France in 2010 offered technical assistance.


2020 production of 17.3 TWh: 10.3 TWh hydro; 7.0 TWh oil.

In 2007 a nuclear power programme 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 consulted the IAEA. The Ministry of Electricity and Water Resources 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 then was to have a nuclear plant with four 300-600 MWe units, or 4400 MWe, operating by 2030, but in 2015 two 600 MWe PWR units by 2027 was the aim. There is an Atomic Energy Act, but radioactive waste and transport functions will be under a comprehensive new draft nuclear act incorporating IAEA safety and other principles. In May 2016 a framework agreement was signed with China National Nuclear Corporation for construction of one or two 600 MWe nuclear power reactors, and formulation of a nuclear cooperation roadmap for the next ten years.

A June 2017 nuclear cooperation agreement with Rosatom included assessing the feasibility of both a nuclear science and technology centre with a research reactor, and also a nuclear power plant. In September 2018, the IAEA completed an INIR mission and concluded: "It is evident that there is a strong commitment ... to developing the infrastructure needed for a safe, secure and peaceful nuclear programme."

Earlier in July 2015 the government’s Geological Research Authority said that uranium exploration was a high priority and, with any mining, would be undertaken by Russian companies.

Sudan has been an IAEA member since 1958 and has had a safeguards agreement with the IAEA under the NPT since 1975.


2020 production of 8.0 TWh: 4.7 TWh fossil fuels; 3.1 TWh hydro.

The government has expressed an intention to investigate the use of nuclear power. In late 2015 the country’s generation capacity was 1246 MWe – 562 MWe hydro, 441 MWe gas and 243 MWe oil. There are imports via transmission links as part of the Eastern Africa Power Pool (EAPP). Overall 24% of the population is serviced by the grid, but in rural areas it is only 7%. The 2015 National Energy Policy is addressing challenges. The country has substantial gas resources.


2020 production of 21.6 TWh: 20.6 TWh fossil fuels; 0.5 TWh wind; 0.3 TWh solar.

The government is reported to be evaluating the possible construction of a 600-1000 MWe nuclear plant costing $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 the 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. The 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 byproduct.

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 June 2015 a nuclear cooperation agreement was signed with Russia, covering: the design, construction and operation of nuclear power plants and research reactors; the production and use of radioisotopes in industry, medicine and agriculture; radioactive waste management; and the training of specialists in nuclear physics and nuclear energy. A further intergovernmental agreement with Russia was signed in 2016. In February 2017 China National Nuclear Corporation (CNNC) signed a cooperation agreement with Tunisia's National Centre of Nuclear Sciences and Technology.


2020 production of 4.4 TWh: 4.1 TWh hydro; 0.2 TWh biofuels; 0.1 TWh solar.

Uganda's Atomic Energy Bill came into effect in 2008, to regulate the use of ionizing radiation and provide a framework to develop nuclear power generation. The government then signed an agreement with the IAEA to initiate moves in that direction. The Uganda Vision 2040 roadmap launched in April 2013 incorporates the development of significant nuclear capacity as part of the country's future energy mix. The Uganda Atomic Energy Council is under the Ministry of Energy and Mineral Development. The Nuclear Power Roadmap Development Strategy was approved by the cabinet in April 2015, identifying key infrastructure issues for nuclear power development and proposed mechanisms to address them. Potential sites are in the Kyoga, Kagera and Aswa regions. In May 2022 it was reported that the government had acquired land on which to site a nuclear power plant. The base case scenario is for two 1000 MWe units by 2031 with an expected cost of $9 billion.

The ministry signed a nuclear energy cooperation agreement in May 2017 with China Central Plains Foreign Engineering Company and China Nuclear Manufacturing Group, as well as a draft agreement with CNNC. A Ugandan delegation visited China then, organized by CNNC subsidiary China Zhongyuan Engineering Corporation.

In May 2018, the ministry signed a memorandum of understanding on cooperation in the peaceful uses of nuclear energy with CNNC.

Earlier in October 2016 a framework agreement was signed with Rosatom. In June 2017 the Ministry of Energy and Mineral Development signed a further agreement with Rosatom, covering nuclear infrastructure and nuclear research centres with research reactors.

In August 2023 Ugandan President Yoweri Museveni announced that Russia and South Korea had been selected to build two nuclear power plants with a combined capacity of 15 GWe.

Installed generating capacity in 2021 was 1347 MWe, of which 1073 MWe (80%) was from hydro.


2020 production of 15.2 TWh: 12.8 hydro; 2.2 TWh fossil fuels; 0.2 solar.

In May 2016 Rosatom signed an intergovernmental agreement on cooperation in the peaceful uses of nuclear energy, which provides a framework for opportunities to construct nuclear power facilities. Further cooperation agreements were signed with Rosatom in December 2016 and in June 2017. The first is for the training of Zambian specialists in Russia so that within 15 years, Russia will assist Zambia train young nuclear energy engineers, plan for nuclear power plant personnel, develop a nuclear energy regulator and build a research reactor, which will provide medicine, agricultural services and energy. Zambia aims to become a regional centre for nuclear medicine. In respect to energy, nuclear power is needed to prevent load shedding due to unreliable supply.

The second 2016 agreement was between the Ministry of Health and Rostechnadzor, for cooperation in nuclear safety and regulation and to enhance the capacity of the Radiation Protection Authority by developing a regulatory framework appropriate for heightened nuclear and radiation activities. A third agreement is between the Ministry of Information and Broadcasting Services and Rosatom on cooperation in raising public awareness of nuclear energy in Zambia by developing educational materials in both English and local languages to promote nuclear energy.

Finally there is a 2016 project development agreement between JSC Rusatom Overseas and the Ministry of High Education for the construction of the Centre for Nuclear Science and Technology in Zambia, with a 10 MW research reactor. An intergovernmental agreement covering this was signed in February 2017 by the government and Rosatom, and in June 2017 a further agreement with Rosatom to establish a nuclear science and technology centre was signed.

South and Central America


2020 production of 10.0 TWh: 6.4 TWh fossil fuels (including 6.3 TWh natural gas); 2.9 TWh hydro; 0.3 TWh solar; 0.2 TWh biofuels.

The government set up Agencia Boliviana de Energía Eléctrica (ABEN) – the Bolivian Nuclear Energy Agency – under the Ministry of Hydrocarbons and Energy and planned to establish a nuclear reactor programme 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. A nuclear regulatory body, IBTEN, was also set up and now collaborates with Rostechnadzor.

In March 2015 the government signed a cooperation agreement with Argentina to promote and develop infrastructure and institutions for the peaceful uses of nuclear energy, following one signed in May 2013. Argentina's support was to include the design, construction and operation of nuclear power plants and research reactors, as well as radioactive waste management.

In July 2014 Russia offered Bolivia "a comprehensive plan for the development of nuclear energy for peaceful purposes," and in October 2015 a preliminary nuclear cooperation agreement was signed, with a view to possibly building Russian nuclear power plants. Also the $300 million Center for Nuclear Science & Technology was announced, to be built in Al Alto, near La Paz and 4000 metres above sea level, by 2020 with Russian assistance. A further agreement on this was in March 2016, and in September 2017 a construction contract was signed between Rosatom's Specialised State Institute of Design (GSPI) and jointly managed by Rusatom Overseas.

The first part of the project, notably the Preclinical Cyclotron Radiopharmacy Complex (PCRC) and the Multipurpose Irradiation Centre (MIC) with a commercial gamma-ray unit for the treatment of medical devices and agricultural products, is expected to be completed in 2021, along with an engineering department, and several research laboratories. The centre will have a pool-type research reactor of between 100 and 200 kWt, and first concrete for this was poured in July 2021. Commissioning is expected in 2024. It will facilitate the use of radiation technologies in agriculture, medicine, industry, and other areas. Rosatom sees it as a reference facility for similar centres in other countries.

The Mining Corporation of Bolivia (Comibol) was aiming to define and develop uranium resources at Potosi, in Tomas Frias province and in Santa Cruz province. However, in November 2015 the government said it would not proceed with uranium mining and would import nuclear fuel from France, Canada and Australia.


2020 production of 84.0 TWh: 43.1 TWh fossil fuels; 21.9 TWh hydro; 8.0 TWh solar; 5.6 TWh wind; 5.2 TWh biofuels.

Chile imports over 60% of its primary energy, mostly as hydrocarbons, notably LNG from SE Asia. There is a need to build a further 5 GWe by 2020 to secure a measure of energy security. Per capita consumption is 3350 kWh/yr. About one-third of electricity comes from hydro, depending on seasonal rain, and in 2013, 24 TWh came from hydro, 11 TWh from imported natural gas, and 30 TWh from coal. There are proposals for new coal-fired plants, along with major expansion of non-hydro renewables.

The country’s National Energy Strategy 2012-2030 (Estrategia Nacional de Energía, ENE) states that by 2050, 70% of all electricity should be produced from hydro. However, there is a lot of local opposition to further large-scale hydro development, along with the problem of lower rainfall in recent years. Integration of the two main grids, northern and central, is expected to lower power prices. A December 2015 agreement with Argentina sets up gas and electricity exports eastwards.

In February 2007 the Energy Ministry announced that it was beginning technical studies into the development of nuclear power. A major business group had 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: Antofagasta region, 1400 km north of Santiago, with a dense population as well as extensive mining activity and a major ($3.43 billion) desalination plant which came online 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.

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 May 2018 Rosatom America Latina, part of Rusatom International Network, signed a memorandum of understanding to promote cooperation in the nuclear and lithium sectors in Chile with CCHEN. The MoU includes the modernisation and life extension of Chile's 5 MWt research reactor which started operation in 1974, and the application of radiation technologies in medicine, agriculture, science and other related fields.


2020 production of 20.5 TWh: 19.5 TWh fossil fuels; 0.5 TWh biofuels; 0.2 TWh solar; 0.1 TWh hydro.

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.

In September 2016 Rosatom signed a new agreement with Cuba creating "the legal basis for further bilateral cooperation in civil nuclear power." The scope included: "Medicine and radiation technology; training of nuclear specialists; fundamental and applied research, [and] management of radioactive wastes."


2020 production of 31.3 TWh: 24.3 TWh hydro; 6.4 TWh fossil fuels; 0.5 TWh biofuels.

In August 2009 the government signed a nuclear cooperation agreement with Russia's Rosatom with a view to developing a nuclear power programme and related projects.


2020 production of 46.4 TWh, virtually all from hydro.

Paraguay signed an agreement with Rosatom in October 2016 to develop nuclear power infrastructure in the country. The agreement also covers: the application of radioisotopes and radiation technology in industry, medicine and agriculture; nuclear and radiation safety and security; and development of programmes aimed at raising public awareness about nuclear technologies and their applications, including organization of information centres. Construction of a nuclear science and technology centre with a research reactor is envisaged. The agreement was with the Radiological and Nuclear Regulatory Authority of Paraguay. A further nuclear cooperation agreement was signed by both in September 2017, establishing a legal framework for civil nuclear cooperation between Russia and Paraguay. The agreement covered multiple areas, including building and improving Paraguay's nuclear infrastructure in line with global practices.

In May 2015 Texas-based Uranium Energy Corporation (UEC) was granted regulatory approval to advance its Yuty in-situ leach uranium project in southeast Paraguay from the exploration phase to justifying its mining potential. The Yuty project has NI 43-101 compliant measured and indicated resources of 3430 tU at an average grade of 0.044%, with an inferred resource of 860 tU at an average grade of 0.04%. The deposit – some 200 km southeast of Asuncion – is located within the Parana Basin, which is host to a number of known uranium resources, including Figueira and Amorinopolis in Brazil. UEC also has the Oviedi project in Paraguay.


2020 production of 52.8 TWh: 30.5 TWh hydro; 19.1 TWh fossil fuels; 1.8 TWh wind; 0.8 TWh solar; 0.5 TWh biofuels.

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 consolidated project. In March 2018 the company changed its name to Plateau Energy Metals, and was acquired by American Lithium in May 2021. In December 2022 American Lithium said it would spin-off its Macusani Uranium Project into an independent company, but later in July 2023 announced it would postpone the spin-off and continue developing the project. A January 2016 preliminary economic assessment of Macusani's deposits suggests low production costs – $17.28/lb U3O8. Both open pit and a small amount of underground mining from three orebodies – Colibri, Kihitian and Isivilla – would feed a central heap leach, producing about 2300 tU per year over a ten-year mine life. Uranium resources are 20,000 tU indicated and 27,700 tU inferred to $80/kgU.


2020 production of 74.3 TWh: 62.5 TWh hydro; 11.7 TWh natural gas.

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 programme, 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.

Asia and South East Asia


2020 production of 25.8 TWh: 24.4 TWh fossil fuels (virtually all natural gas); 1.1 TWh hydro; 0.2 waste.

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.


2020 production of 84.8 TWh: 83.5 TWh fossil fuels; 0.9 TWh hydro; 0.4 TWh solar.

See information page on Nuclear Power in Bangladesh.


2020 production of 9.0 TWh: 4.5 TWh fossil fuels; 4.1 TWh hydro; 0.3 solar.

In November 2015 Rosatom signed a nuclear cooperation agreement with Cambodia, focused on a possible research reactor, but with consideration of nuclear power. Cambodia was seeking $3 billion in foreign investment, especially from China, to build six hydroelectric plants by 2018 to keep up with rising domestic power demand. A further cooperation agreement was signed in March 2016, and in May Rosatom and the National Council for Sustainable Development of Cambodia (CDC) signed memoranda to establish a nuclear energy information centre in Cambodia and set up a joint working group on the peaceful uses of atomic energy.

In mid-2016 the Ministry of Industry, Mines and Energy held discussions with China National Nuclear Corporation (CNNC) on building a nuclear power plant and establishing the regulatory and legal infrastructure for that, in collaboration with the IAEA. In September 2017 a nuclear cooperation agreement was signed with CNNC, proclaimed as part of implementing China's 'One Belt, One Road' strategy and strengthening cooperation with ASEAN countries. The agreement is focused on human resources development.

The CDC reports that only 22.5% of Cambodian households have grid electricity, though 60% are in urban areas. The state-owned enterprise Electricité du Cambodge hopes to provide electricity to all villages by 2020 and to 70% of all rural households by 2030. The CDC says Cambodia relies chiefly on hydropower, coal and imported electricity to attempt to meet demand.


2020 production of 11.2 TWh: 8.3 TWh hydro; 2.8 TWh natural gas; 0.1 TWh wind.

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.


2020 production of 292 TWh: 237 TWh fossil fuels; 24.3 TWh hydro; 15.6 TWh geothermal; 14.5 TWh biofuels.

See information page on Nuclear Power in Indonesia.


2020 production of 111 TWh: 98.7 TWh fossil fuels; 9.7 TWh hydro; 1.5 TWh solar; 1.0 TWh wind.

Kazakhstan has no national electricity grid, but a northern grid links to Russia and a southern one links to Kyrgyzstan 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 Russian nuclear plant at Kurchatov and another plant near Lake Balkhash in the south of the country, north of Almaty, possibly involving Japan. A Kazakhstan high-temperature gas-cooled reactor (HTR) of about 50 MW is also planned at Kurchatov.

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.

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 TVEL, confirmed in 2008, gives a share in the 10 million SWU/yr uranium enrichment plant at Novouralsk in Russia. Kazatomprom also has a 10% share in the Angarsk International Uranium Enrichment Centre (IUEC).

Over 2006-08 China Guangdong Nuclear Power Group Holdings (CGN) 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 CGN. 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 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.  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), now the International Framework for Nuclear Energy Cooperation (IFNEC), in September 2007.

See also information page on Uranium in Kazakhstan for more information.


2020 production of 40.0 TWh: 28.5 TWh hydro; 11.4 TWh coal.

In September 2015 it was reported that Rosatom was planning to build two 1000 MWe nuclear power reactors in Laos on a build-operate-transfer basis. Power exports to Singapore were envisaged. In April 2016 Rosatom signed an agreement with the ministry of energy and mines to cooperate in the design, construction and operation of nuclear power plants and research reactors. Rosatom said the two parties plan to develop and prepare for the signing of an intergovernmental agreement on nuclear energy cooperation. In September 2017 the two parties signed a further agreement – a roadmap on cooperation in peaceful uses of atomic energy – which includes studying the potential implementation of a nuclear power project, and the use of non-power radiation technologies. In July 2019 two further agreements were signed between Rosatom and the Ministry of Energy and Mines, outlining cooperation in education, personnel training and shaping public opinion on the use of nuclear energy. 


2020 production of 183 TWh: 153 TWh fossil fuels; 26.2 TWh hydro; 2.3 TWh solar; 1.0 TWh biofuels.

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 14 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 programme 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 set up 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 programme implementing organization (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.

Malaysia wants a proven type of 1000 MWe-class reactor which is already deployed. Plans were 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 were envisaged 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.)

Early in 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 were 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 was working with other Southeast Asian countries to harmonise regulations relating to nuclear power development. In October 2016 the IAEA undertook an integrated nuclear infrastructure review (INIR).

In 2017 a bill to replace the Atomic Energy Licensing Act 1984 was to transform the Atomic Energy Licensing Board into the Malaysia Atomic Energy Regulatory Commission and pave the way for the country to have its own nuclear power generator as early as 2030, according to the MNPC. In June 2018 the Atomic Energy Licensing Board was used by the IAEA in helping nuclear security for Middle Eastern countries “due to its mature programme and well-developed nuclear security infrastructure.”

In mid-2018 the new government said that it would not proceed with developing nuclear power in the country and would close down the MNPC.

The Malaysian Institute for Nuclear Technology Research (MINT) has operated a 1 MW Triga research reactor since 1982. The reactor was refurbished and modernised over 2000-13.

In April 2007 MINT was renamed the Malaysian Nuclear Agency (MNA, or Nuklear Malaysia) to reflect its role in promoting the peaceful uses of atomic energy through active public information and publications. Its role includes technology assessment and support for the MNPC.

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 an 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.


2020 production of 6.6 TWh: 6.0 TWh fossil fuels; 0.5 TWh wind.

Russia is reported to be examining the feasibility of building nuclear power plants in Mongolia, and Mongolia's Nuclear Energy Agency had 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.

See also information page on Uranium in Mongolia for more information.


2020 production of 20.0 TWh: 10.5 TWh hydro; 9.4 TWh fossil fuels.

In June 2015 Russia and Myanmar signed a preliminary agreement to cooperate in the peaceful uses of nuclear energy. It was signed by Rosatom and Myanmar's minister of science and technology. It follows an agreement to set up a nuclear research centre. The country is in the process of drafting domestic laws related to nuclear energy.

A country programme framework (CPF) was signed with the IAEA in 2009. In September 2013, Myanmar signed the IAEA Additional Protocol, which has yet to be ratified.

In February 2023 Myanmar signed an intergovernmental agreement with Russia, calling for the two nations to work together to construct an RITM-200 55 MWe SMR.

North Korea

2020 production of 15.2 TWh; 12.8 TWh hydro; 2.4 TWh fossil fuels.

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 programme. 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 was 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 South Korean 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 but have subsequently been redeployed in various directions by KEPCO

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 (i.e. yield was apparently in line with probable design, unlike the test in 2006).

See also Appendix to information paper on Safeguards to Prevent Nuclear Proliferation, Nuclear Proliferation Case Studies.


2020 production of 102 TWh: 80.1 TWh fossil fuels; 10.8 TWh geothermal; 7.2 TWh hydro; 1.4 TWh solar; 1.3 TWh biofuels & waste; 1.0 TWh wind.

See information page on Nuclear Power in the Philippines.


2020 production of 53.4 TWh: 51.6 TWh fossil fuels (including 50.9 TWh natural gas); 1.3 TWh biofuels & waste; 0.5 TWh solar.

Singapore has relatively high power demand (peak 14 GWe) for its size, and is almost entirely dependent on gas-fired generation for around 50 TWh/yr, the fuel being piped from Indonesia or imported as LNG. It is considering the prospect of using nuclear power, but could otherwise join with Malaysia in any project there, due to siting constraints on the island. In 2015 there was no electricity import or export. In November 2010 the prime minister said that Singapore "cannot afford to dismiss the option of nuclear energy altogether." In October 2016 the minister for trade and industry said that Singapore would keep “well informed on trends” and had “never ruled out the option of using nuclear power.” In 2012 the Singapore Nuclear Research and Safety Initiative (SNRSI) was established at the National University of Singapore (NUS), to provide a focus for expertise.

Sri Lanka

2020 production of 15.6 TWh: 10.0 TWh fossil fuels; 5.0 TWh hydro; 0.3 TWh wind; 0.1 TWh solar.

In August 2017 installed capacity was 4043 MWe, with generation and transmission the responsibility of the Ceylon Electricity Board (CEB). A 600 MWe nuclear plant is included from 2030 in the 'Energy Mix with Nuclear Case' of the CEB Long Term Generation Expansion Plan 2015-2034, which keeps the coal share to about 50% of the total. Nuclear then provides about 12%. A 500 MW HVDC transmission link to India from 2025 is being considered in collaboration with the Power Grid Corporation of India Ltd.

The draft of the Long Term Generation Expansion Plan 2020-2039 included a 600 MWe nuclear unit starting up in 2035 and another one in 2037 in the 'Energy Mix with Nuclear Power Development' scenario.

In September 2010 the Sri Lankan government commissioned its Atomic Energy Authority and CEB to conduct a pre-feasibility study of using nuclear energy for power generation from about 2025, with technical cooperation from the IAEA and following IAEA guidelines. It revised its Atomic Energy Authority Act accordingly and in 2014 established the Sri Lanka Atomic Energy Board under the Ministry of Power and Energy, to promote and encourage the use of nuclear science and technology for national development purposes. Sri Lankan scientists and technical experts are being sent to Russia for training.

The Sri Lanka Atomic Energy Regulatory Council was also established in 2014, for the regulation and licensing of applications of ionizing radiation, the safety and security of sources, and the administration of non-proliferation safeguards. It will allow for the introduction of nuclear power generation technology in the country.

The country’s Atomic Energy Authority (AEA) has an International Cooperation Division which provides liaison with the IAEA. In February 2015 the government signed a nuclear cooperation agreement with India. It is concerned with capacity building and training in the 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.


2020 production of 179 TWh: 150 TWh fossil fuels; 16.6 TWh biofuels & waste; 5.0 TWh solar; 4.7 TWh hydro; 3.2 TWh wind.

Thailand has the potential to be a regional electricity hub for ASEAN countries, though power imports are expected to rise from 7% in 2013 to 14% in 2020 and 18% in 2030.

Tentative plans to embark on a nuclear power programme have been revived by a forecast growth in electricity demand of 7% per year for the next 20 years. As gas prices rose, the Atomic Energy Commission and its Office of Atoms for Peace (OAP) 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.

In June 2007 the cabinet set up the Nuclear Power Program Development Office under the National Energy Policy Council and appointed an Infrastructure Establishment Committee, the Nuclear Power Utility subcommittee of which is supervising EGAT in this project. The energy minister budgeted some $53 million over 2008-2011 on preparatory work, half of it coming from oil revenues. Construction of the first unit by EGAT was to commence in 2014. The capital cost was expected to be $6 billion and electricity cost about 6 cents/kWh, slightly less than from coal. The pre-project phase involving the three-year feasibility study leading to a firm government decision to proceed (or not) was due to conclude in 2011.

The government planned to establish safety and regulatory infrastructure by 2014 and 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 would 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 selected. 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 March 2011 accident at the Fukushima nuclear plant in Japan, plans were put on hold. A 2015 power development plan had two 1000 MWe plants coming online in 2035-36 to “diversify fuel sources and mitigate risk.” In January 2016 EGAT confirmed this as being PWR capacity, but no site was mentioned.

In November 2009 EGAT and CLP Holdings Ltd had signed an agreement with China Guangdong Nuclear Power Corporation (CGN) regarding nuclear power development. In December 2015 CGN and Guangxi Investment Group signed an agreement with Ratch China Power Ltd, a subsidiary of Thailand's Ratchaburi Electricity Generating Holding Public Company, a subsidiary of EGAT, to establish a joint venture – Guangxi Fangchenggang Nuclear Power (II) Co Ltd – to develop, construct and operate the next stage of the Fangchenggang plant with units 5&6 Hualong One reactors. Ratch China will hold 10%, CGN 51% and Guangxi 39%. Thailand has added Hualong One to its technology shortlist. Ratch will invest THB7.5 billion ($210 million) in the project over the next five years under a 30-year power purchase contract.

Ratch said: "It is an opportunity for Thai technical personnel in developing and enhancing their skills and experience by sharing nuclear-related knowledge and techniques with CGN, which has more than 30 years of expertise in this field. CGN's achievements and experience in low-carbon environment management is another area for learning because it is important for dealing with the climate change issue."

In November 2010 EGAT signed an agreement with Japan Atomic Power Co to provide support on building nuclear power plants. It was to 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.

In its 2015 Power Development Plan (PDP2015), the Ministry of Energy outlined 2000 MWe of nuclear power to be added by 2036.

In April 2017 Thailand signed an agreement with China to cooperate on the peaceful use of nuclear energy.

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 into force in 1974 and it has signed but not ratified the Additional Protocol.


2020 production of 66.5 TWh: 61.5 TWh fossil fuels (including 58.4 TWh gas); 5.0 TWh hydro.

In December 2017 Uzbekistan and Russia signed an intergovernmental agreement on cooperation in the use of nuclear energy for peaceful purposes. In September 2018 a further intergovernmental agreement was signed for construction by Rosatom of two VVER-1200 reactors to be commissioned about 2028 at a site on the shore of Lake Tudakul. Rosatom expects construction to start in either 2020 or 2021.

Uzbekistan has considerable mineral deposits, including uranium. See also information page on Uranium in Uzbekistan for more information.


2020 production of 240 TWh: 155 TWh fossil fuels; 72.9 TWh hydro; 9.6 solar; 1.7 TWh biofuels; 1.0 TWh wind.

See information page on Nuclear Power in Vietnam.


2021 production of 266 TWh: 195 TWh fossil fuels; 27.7 TWh solar; 24.5 TWh wind; 15.2 TWh hydro; 3.3 TWh biofuels.

Australia's electricity mix 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 shortlisted, 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 Minister'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."

In May 2016 the South Australian Royal Commission into the Nuclear Fuel Cycle reported. It found that it would not be commercially viable to develop a nuclear power plant in the state under current market rules, but noted that as "a low-carbon energy source comparable with other renewable technologies," nuclear may be required in the future. It therefore recommended that the South Australian government should "pursue removal at the federal level of existing prohibitions on nuclear power generation to allow it to contribute to a low-carbon electricity system, if required." It also called for the removal at the federal level of prohibitions on the licensing of fuel cycle facilities, although it noted that in a currently oversupplied market the provision of such services would not be commercially viable in the next decade. Meanwhile, “the South Australian Government [should] promote and collaborate on the development of a comprehensive national energy policy that enables all technologies, including nuclear, to contribute to a reliable, low-carbon electricity network at the lowest possible system cost.”

See also information pages on Australia's Uranium and Australia's Electricity for further information.

Notes & references


1. International Status and Prospects for Nuclear Power 2021, IAEA (July 2021) [Back]

General sources

IAEA, Country Nuclear Power Profiles
OECD/IEA Electricity Information (annual)

New Zealand
Saudi Arabia
United Arab Emirates