The World Nuclear Industry Status Report 2024 (HTML)

Foreword by

Andreas Molin

Former Director of the Division of Nuclear Co-ordination

Ministry of Climate Action, Environmeent, Energy, Mobility, Innovation and Technology,
Government of Austria

By

Mycle Schneider

Independent Consultant, Paris, France

Project Coordinator and Lead Author

And

Antony Froggatt

Independent Consultant, London, U.K.

Lead Author

With

Julie Hazemann

Director of EnerWebWatch, Paris, France

Documentary Research, Modelling and Datavisualization

Özgür Gürbüz

Independent Consultant

Türkiye

Contributing Author

Paul Jobin

Associate Research Fellow,

Institute of Sociology, Academia Sinica

Taipei, Taiwan

Contributing Author

Phil Johnstone

Senior Research Fellow,
Science Policy Research Unit,

University of Sussex

United Kingdom

Contributing Author

Timothy Judson

Independent Consultant

Syracuse, New York, United States

Contributing Author

Yuki Kobayashi

Research Fellow, Security Studies Program,

Sasakawa Peace Foundation

Tokyo, Japan

Contributing Author

Doug Koplow

Founding Director, Earth Track

Cambridge, United States

Contributing Author

Edwin Lyman

Director, Nuclear Power Safety,

Union of Concerned Scientists

Washington, DC, United States

Contributing Author

M.V. Ramana

Simons Chair in Disarmament, Global and Human Security with the School of Public Policy and Global Affairs (SPPGA), University of British Columbia

Vancouver, Canada

Contributing Author

Sebastian Stier

European Patent Attorney

Munich, Germany

Contributing Author

Andy Stirling

Professor, Science Policy Research Unit,

University of Sussex Business School

United Kingdom

Contributing Author

Tatsujiro Suzuki

Professor, Research Center for Nuclear Weapons Abolition, Nagasaki University (RECNA);

Former Vice-Chairman of the Japan Atomic Energy Commission, Japan

Contributing Author

Christian von Hirschhausen

Professor, Workgroup for Economic and Infrastructure Policy (WIP), Berlin University of Technology (TU)

and Research Director, German Institute for Economic Research (DIW)

Berlin, Germany

Contributing Author

Alexander James Wimmers

Research Associate at the Workgroup for Economic and Infrastructure Policy (WIP), Berlin University of Technology (TU), Berlin, Germany

Contributing Author

Hartmut Winkler

Professor, University of Johannesburg, South Africa

Contributing Author

Maahin Ahmed

Freelance Copyeditor

Vancouver, Canada

English Language Copyeditor

Nina Schneider

Proofreader and Translator

Paris, France

Fact-checker, Proofreader, Producer

Agnès Stienne

Artist, Graphic Designer, Cartographer

Le Mans, France

Graphic Design and Layout

Friedhelm Meinass

Visual Artist, Painter

Rodgau, Germany

Cover-page Design and Layout

Acknowledgments

The WNISR Coordinator and Publisher was lucky to have six new experts from Germany, Japan, Taiwan, Türkiye, the U.K., and the U.S. join the project team for the 2024 edition (at least!).

As one of only two other people who have been with the project from the start, Antony Froggatt has been a reliable partner in developing the report concept, drafting chapters, editing or proofing others, and presenting the outcome at numerous occasions. For reasons independent of this project, your role is likely to change in the future. Whatever path you are taking, thank you for everything, especially for being who you are, an exceptional energy policy analyst, a kind person, and a close friend.

At the core of the WNISR is its database designed and maintained by data manager and information engineer Julie Hazemann—the other person who has been there from day one. She also develops most of the drafts for the graphical illustrations and expanded her contributions significantly over the past few years, including pre-drafting statistical sections and analysis. As ever, no WNISR without her. Thanks a million.

This is the tenth edition in a row M.V. Ramana has contributed to, and the number of sections covered has significantly increased if compared with number one. I am very grateful he has again cut out time in his insanely busy schedule to support this project with expertise and advise. Thank you so much.

Tatsu Suzuki, with whom I continue to enjoy—as with Ramana—cooperating under other organizational frameworks, has turned from a foreword author in 2014 into an indispensable member of the core team. Thank you for contributing some essential parts to the report for the third year in a row and for the first time in cooperation with Yuki Kobayashi who we welcome on the team. Thanks to both of you for continuing the development of the chapters you have taken on.

Christian von Hirschhausen, thank you again for mobilizing and organizing your team of young scientists around the WNISR Project. Alex Wimmers, in his third year, has not stopped taking on additional responsibilities. Thank you very much for the quality and unparalleled timeliness (!) of your contributions. You make our lives easier.

Doug Koplow, who was a key author of WNISR2009, has returned fourteen years later as a key author of WNISR2023. I am glad I could lur him into an—excellent—follow-up in 2024. Thank you for the quality of your work and your patience, not only concerning the report itself but also for the series of presentations that we have enjoyed with you.

Tim Judson has now contributed for the third year in a row and depth of his knowledge comes as a great value added to the WNISR Project. Thank you so much.

Hartmut Winkler joined the team in 2023… and expanded his excellent contributions in 2024 to two chapters. It is a real pleasure working with you, thank you very much.

What began with a “little blip” in WNISR2023 turned into a full-scale chapter in WNISR2024 drafted by my old buddy Sebastian Stier. Thank you for your expertise, advise, and incredible engagement into this work. Such a pleasure. Hopefully, we can build on this in the years to come.

Amongst the newcomers in the team, we are fortunate to count Özgür Gürbüz who contributed two well-researched pieces, Paul Jobin who provided a well-documented and well-written piece, Ed Lyman who drafted a short but incredibly insightful chapter on a difficult issue, as well as Andy Stirling and Phil Johnstone who drafted a chapter that follows up directly on work discussed in WNISR2018 (welcome back!) and presents original and thought-provoking research.

Andreas Molin has been a senior government official for decades. I could not have thought of a more qualified and appropriate author for the Foreword to WNISR2024. The result provides historical context and depth. It was also a fruitful and pleasant experience working with you. Thank you so much.

Nina Schneider’s meticulous proof-reading, source verification, and fact-checking is greatly appreciated by the entire team. Her production skills remain an essential ingredient to the overall outcome. Merci encore et toujours.

Freelance copyeditor Maahin Ahmed has managed very rapidly to find an intelligent, effective balance in the approach to English language copy-editing of the report. Only one regret: there was not enough time to profit of your skills for the entire text. Thank you so much for your excellent input.

Artist and graphic designer Agnès Stienne keeps innovating and improving our graphic illustrations that are praised—and reprinted—around the world. Thank you very much.

Arnaud Martin, web-designer and full-stack developer, is always there when needed, and his work on the dedicated WNISR Project website www.WorldNuclearReport.org is reliable, functional, and attractive. Thanks a million.

For the sixth time in a row, we owe idea, design, and realization of the original report-cover to renowned German painter Friedhelm Meinass, with Anne Redwanz on the Computer. His work has turned into a series of art pieces that is a display of different conceptual ideas, styles, and techniques—thoughtful and beautiful. Wholehearted thanks.

This work has greatly benefitted from partial proofreading, editing suggestions, comments, or other input by Pin-Syue Huang, Shi Ting Chen, Steve Thomas, Tobias Münchmeyer, Frank von Hippel, and others. Thank you all.

The authors wish to thank especially Jochen Ahlswede, Hendrik Schopmans, Gerrit Niehaus, Claudia Detsch, Stefan Thalhofer, Kristian Brakel, KunWoo Ro, Layla Al-Zubaidi, Rebecca Harms, Jutta Paulus, Christina Stober, Fabian Lüscher, Axel Harneit-Sievers (missing you already), Klaus Mindrup, and… Angela Schneider for their enthusiastic and sustainable support of this project.

And everybody involved is grateful to the German Federal Office for the Safety of Nuclear Waste Management, Friedrich Ebert Foundation, Heinrich Böll Foundation, the Greens-EFA Group in the European Parliament, and the Swiss Renewable Energy Foundation for their financial support.

Note

This report contains a very large amount of factual and numerical data. While we do our utmost to verify and double-check, nobody is perfect. The authors are always grateful for corrections and suggested improvements.

Foreword

by Andreas Molin1

This is the 19th Edition of the World Nuclear Industry Status Report or WNISR. What started in 1992 became a remarkable success, and an indispensable source of reliable, fact-based information. Having worked some 30 years as a civil servant for the Government of the Republic of Austria, implementing Austria’s nuclear policy, I have come to particularly value the importance of empirical evidence, reliable data, and sound analysis of relevant developments. Since 2007 all of that has been provided by the WNISR on an annual basis.

For the global readership of the WNISR, it may be recalled that during the 1960s Austria had been embarking on a nuclear power program too. Groundbreaking for the Zwentendorf Nuclear Power Plant (NPP), located on the banks of the Danube River some 40 km upstream from Vienna, took place in 1972. Two more NPPs were at the planning stage, one in St. Pantaleon, also in Lower Austria, and one in Carinthia. Construction of the Zwentendorf NPP was finished in 1978 and the plant was slated for startup in the fall of the same year (fuel assemblies were onsite, but not yet loaded). But then, on 5 November 1978, the Austrian electorate decided in a very close referendum not to start the operation of the NPP (49.33% yes and 50.47% no). Within a month the Austrian Parliament passed an Anti-Nuclear Law prohibiting nuclear power in Austria, and the Zwentendorf NPP got mothballed.

Only a few months later, in March 1979, the wider consequences of an accident at the Three Mile Island NPP in the U.S. (INES-5)2 were seen by many in Austria as confirmation of the majority vote against nuclear power. But it took until 1985 for the consortium of public utilities owning the Zwentendorf NPP to decide on a “quiet” liquidation. As the NPP has been preserved almost entirely, today it is a tourist attraction and houses a vocational training facility. There are not many places in the world where you can visit a nuclear power plant free of any contamination.

After the catastrophic events in Chornobyl in 1986—Austria being among the most affected countries in Central Europe—the opposition to and concerns about nuclear power became deeply rooted in the Austrian population, at all levels of society. Information regarding the safety deficits of NPPs of Russian design, which became public after 1989, reinforced these apprehensions, leading to explicit government policy in 1990.

When I was entrusted with the implementation of Austria´s nuclear policy in 1991, it was difficult, if not almost impossible to get reliable information about nuclear power plants close to the Austrian border, and elsewhere. That is until Mycle Schneider and Antony Froggatt began to publish the WNISR, and thanks to their persistence and dedication it has been an annual publication for 17 years providing not only reliable and important data in an understandable and informative way but also a wealth of sound and profound analysis.

During my long professional career in the nuclear field, I have several “ups and downs” of the nuclear power sector. Sometimes it had been called a “nuclear renaissance”, sometimes “renewed interest in nuclear power.” But what really happened in the global and regional power markets, the WNISR tells us. Apart from a steady increase in installed capacity in Asia, in China in particular, the promise of nuclear never materialized. In the early years of the 21st century some construction projects were started or resumed, but they all went substantially over budget and have been plagued by technical difficulties and delays. More reactors have been retired than brought on-line. In fact, global production of nuclear power peaked already in 2006. I would not call that a “nuclear renaissance”.

In parallel, the urgency of reducing greenhouse gas emissions became increasingly evident. But as electricity production from renewable sources thrived, the global share of nuclear power declined, steadily.

To fight cost-overruns and delays, so-called “Small Modular Reactors” or SMRs receive a lot of attention nowadays. More or less “shop-fabricated”, proponents of SMRs claim they would be more or less “shop-fabricated”, licensing procedures would be shortened, cost predictable and step-by-step capacity additions possible. And, of course, they should play a major role in fighting climate change. And, finally, they should be safer, allowing their deployment also in densely populated areas.

Though most of the technological concepts are not new at all, technological advances should now render possible what was not achievable earlier. And indeed, the OECD’s Nuclear Energy Agency (NEA) lists altogether 56 models in its SMR Dashboard—impressive really. But how many reactors are in operation or under construction, or have at least their design licensed? The NEA informs on its webpage that “the first SMRs are expected to be built this decade, followed by accelerated deployment around the world in the 2030s.”3 The thorough analysis, drafted by M. V. Ramana and annualized since WNISR2019, sheds some doubts on this. But climate experts urge us to reduce greenhouse gas emissions fast, very fast. The European Union’s target is a 55-percent reduction by 2030 (compared to 1990), 90 percent by 20404. It is difficult to imagine that SMRs could play a significant role in achieving these targets.

There is a more fundamental problem though, that is the aging fleet of reactors and operators’ efforts to extend the operating times of their reactors well beyond the limits envisaged at the time of construction and licensing. This is an enormous challenge for the nuclear power sector. Of course, operators as well as regulators subscribe to the concept of continuous improvement of nuclear safety. But nuclear safety is an extraordinarily complex issue, comprising not only technology but also human factors or institutional frameworks, to name just a few principal elements. Consequently, it is a legitimate question, if nuclear safety has improved over time. What can be observed is that more or less ambitious upgrading or improvement plans are delayed in many cases. For the European Union, the European Nuclear Safety Regulators Group’s (ENSREG) 2021-Status Report on the Post-Fukushima National Action Plans5 provides convincing evidence in this regard. Likewise, the Western European Nuclear Regulators Association’s (WENRA) 2023-report on “reasonably practicable safety improvements and benchmarking”6 shows that there is room for improvement in implementing already agreed upon safety upgrades. But, as you can see also from WNISR2023, the economic pressure for operators is quite substantial. Competent, strong, and independent regulators, backed by adequate national and international legal frameworks as well as sufficient resources, are indispensable in such a situation. Let us hope that in operating states, governments, parliaments, and the society as a whole are aware of this and act appropriately.

Key Insights

Executive Summary and Conclusions

The World Nuclear Industry Status Report 2024 (WNISR2024) provides a comprehensive overview of nuclear power plant data, including information on age, operation, production, and construction of reactors. WNISR2024 includes various topical focus chapters. Russia Nuclear Dependencies looks at the global nuclear industry’s relationship with Russian companies with a particular focus on nuclear fuel supplies. Civil-Military Cross-Financing in the U.K. Nuclear Sector presents the result of an independent study that assesses the undeclared financing streams by tax- and ratepayers to the civil and military nuclear sectors. Militarization of Civil Nuclear Reactors: Tritium for Nuclear Weapons looks at the U.S. precedent for a recent, similar decision in France.

The Focus Countries chapter includes a detailed overview of developments in 14 of the 32 nuclear countries and on potential newcomer countries Poland and Türkiye. The chapter on Potential Newcomer Countries includes an Africa Focus that assesses the status of planning in selected countries and raises some feasibility issues.

The situation of Small Modular Reactor (SMR) development is analyzed in a dedicated chapter. The status of onsite and offsite challenges is discussed in the Fukushima Status Report. The Decommissioning Status Report provides an overview of the current state of nuclear plants that have been permanently closed. The chapter on Nuclear Power vs. Renewable Energy Deployment offers comparative data on investment, capacity, and generation from nuclear, wind, and solar energy, as well as other renewables around the world. That overview is complemented by a new analysis on Power Firming and Competitive Pressure on Nuclear that assesses the increasing implementation of hybrid systems—especially solar plus storage—that are falling in cost, already less expensive than new nuclear, increasingly competitive with existing nuclear and fossil fuel plants and could rapidly become game changers in the energy-system landscape.

Finally, Annex 1 presents overviews of nuclear power programs in the countries not covered in the Focus Countries chapter.

Production and Role of Nuclear Power

Reactor Operation and Capacity. As of 1 July 2024, a total of 408 reactors—excluding Long-Term Outages (LTOs)—were operating in 32 countries, one unit more than in WNISR2023,7 ten less than in 1989, and 30 below the 2002-peak of 438. At the end of 2023, the operating nominal net nuclear electricity generating capacity stood at 364 GW. As of mid-2024, operating nominal capacity reached 367.3 GW, 0.2 GW more than the previous 2006 end-of-year record of 367.1 GW.

IAEA versus WNISR Assessment. Between September 2022 and April 2023, the International Atomic Energy Agency (IAEA) significantly modified its statistics—including retroactively—in its online-Power Reactor Information System (PRIS). This in turn impacts the perception of nuclear industry trends. Until September 2022, PRIS showed a historic peak in officially operating reactors, both in terms of number (449) and capacity (396.5 GW), in 2018.

In July 2024, PRIS showed the peak in the number of units occurring as early as 2005 at a maximum of 440 and the maximum end-of-year capacity still in 2018 at 374 GW. PRIS showed 416 units as operating with 374.7 GW of capacity as of mid-2024, just, slightly exceeding the 2018 peak. It is also likely that a new, record end-of-year capacity will be reached in 2024.

Until September 2022, the IAEA had included 33 units in Japan in its total number of reactors “in operation” in the world while only 10 of these units had effectively restarted and 23 have not produced electricity at least since 2010–2013 (of which, three since 2007). As of mid-2023, the IAEA had pulled those 23 units, together with four reactors in India, from the list of operating reactors retroactively since shutdown and added them to a new category labeled “Suspended Operation”. As of mid-2024, the IAEA classified 21 reactors in Japan and four units in India as suspended.

As of mid-2024, WNISR classified 34 units as in LTO, of which 21 were in Japan, six in Ukraine, four in India, and one each in Canada, China and South Korea—the number increased by three compared to WNISR2023.

Nuclear Electricity Generation. In 2023, the world nuclear fleet generated 2,602 net terawatt-hours (TWh or billion kilowatt-hours) of electricity. Production increased by 2.2 percent compared to 2022—still below the levels of 2021 and 2019. China continued to generate more nuclear electricity than France for the fourth year in a row. Considering the continued difficulties of the ageing French fleet and the continuous expansion of the Chinese program, it seems now impossible for France to catch up, making China second only to the United States (U.S.) in nuclear generation for the foreseeable future. Outside China, nuclear production increased by 2.1 percent in 2023, remaining at a level last seen in the mid-1990s.

Share in Electricity/Energy Mix. Nuclear energy’s share of global commercial gross electricity generation declined slightly to 9.15 percent in 2023 compared to 9.18 percent in 2022, down from the peak of 17.5 percent in 1996.

Reactor Startups and Closures8

Startups. In 2023, five reactors were connected to the grid, one each in Belarus, China, Slovakia, South Korea, and the U.S. In the first half of 2024, four units were connected to the grid, one each in China, India, United Arab Emirates (UAE), and the U.S.

Closures.9 In 2023, five reactors were closed, three in Germany and one each in Belgium and Taiwan. In the first half of 2024, one unit was closed in Russia.

Over the two decades 2004–2023, there were 102 startups and 104 closures. Of these, 49 startups were in China which did not close any reactors. As a result, outside China, there has been a drastic net decline by 51 units over the same period, and net capacity declined by 26.4 GW.

Construction Data10

As of 1 July 2024, 59 reactors (60 GW) were under construction, that is one more (1.2 GW) than in WNISR2023, but 10 fewer than in 2013 (five of which have subsequently been abandoned).

Thirteen countries are building nuclear plants, three less than in WNISR2023. The UAE and the U.S. completed their last construction projects and Brazil suspending (again) its only building project. Only three countries—China, India, and Russia—have construction ongoing at more than one site.

Building vs. Vendor Countries

• As of mid-2024, China had by far the most reactors under construction with 27 units or 46 percent of the total. However, China is currently not building anywhere outside the country.
• Russia is the dominant supplier on the international market with 26 units under construction in the world as of mid-2024. Six of these are being built domestically. The remaining 20 units are being constructed in seven countries, including four each in China, Egypt, India, and Türkiye.11 It remains uncertain to what extent these projects have been or will be impacted by sanctions imposed on Russia and other consequential geopolitical developments following Russia’s invasion of Ukraine.
• Besides Russia’s Rosatom, only France’s EDF is acting as lead-contractor building a nuclear power plant abroad (two units in the U.K.).

Construction Times

• For the 59 reactors being built, on average 5.9 years have passed since construction start—almost identical to the mid-2023 average of 6 years—but many remain far from completion.
• All reactors under construction in at least nine of the 13 builder-countries have experienced, often year-long, delays.
• Of the 23 reactors documented as behind schedule, at least 10 have reported increased delays and two were reported as delayed for the first time over the past year.
• WNISR2022 noted a total of 12 reactors scheduled for startup in 2023. At the beginning of 2023, nine were still planned to be connected to the grid within the year (including three pushed back from 2022 to 2023) but only five of these generated first power; the other four were delayed at least into 2024.
• Grid connection of the Mochovce-4 reactor in Slovakia has been further delayed, currently to 2025, that is 40 years after its initial construction start. Bushehr-2 in Iran originally started construction in 1976, over 48 years ago, and resumed construction in 2019 after a 40-year-long suspension. Grid connection is currently scheduled for 2028, 52 years after construction started initially.
• Six additional reactors have been listed as “under construction” for a decade or more: the Prototype Fast Breeder Reactor (PFBR) and Rajasthan-7 & -8 in India, Shimane-3 in Japan, Flamanville-3 (FL3) in France, and CAREM in Argentina12.

Construction Starts

• Construction started on six reactors in 2023, down from 10 in 2022, both included five in China. Russia began work on one more reactor in Egypt.
• Construction of four reactors started in the first half of 2024, two of them in China, and one each in Russia and Egypt, both implemented by the Russian industry.
• Chinese and Russian government-owned or -controlled companies launched all 35 reactor constructions in the world over the 54-month period from the beginning of 2020 to mid-2024.

Operating Age

• The average age (from grid connection) of the 408 operating nuclear reactors has been increasing since 1984 and stands at 32 years as of mid-2024, up from 31.4 years in mid-2023.
• A total of 269 reactors—four more than mid-2023—two-thirds of the world’s operating fleet, have operated for 31 or more years; of these, 127—more than a quarter of the world’s operating fleet—have operated for at least 41 years.
• If all currently licensed lifetime extensions were maintained, all construction sites completed as planned, and all other units operated for a 40-year lifetime (unless a firm earlier or later closure date has been authorized), in the years to 2030, the net balance of operating reactors would turn negative as soon as 2025, and slightly positive for the years 2026–2027. Overall, an additional 65 new reactors (43 GW)—almost one unit or 1 GW per month—would have to start up or restart to replace closures. This would necessitate almost doubling the annual startup rate of the past decade from six to eleven until 2030 just to maintain the current number of reactors in the world. Considering the long lead times, this is a highly unrealistic scenario. However, it is increasingly likely that at least one third of the 126 reactors slated for closure under this scenario will secure lifetime extension beyond 2030. Only further lifetime extension will avoid the world nuclear fleet to decline by 2030 and thereafter.

Focus Countries

The following 16 Focus Countries include 14 of the current 32 nuclear countries as well as potential newcomer countries Poland and Türkiye. Some key developments in 2023 and the first half of 2024:

Belgium. Nuclear generation dropped by 25 percent in 2023. Under the 2003-phaseout policy, one reactor was closed in September 2022 and another one in January 2023. Five reactors remain operational. The current plan is to close three by 2025 and extend operation by 10 years for the two most recent ones to 2035 or up to end of 2037 at the latest depending on the restart date following major upgrading. A legally binding agreement between the government and operator was signed and the Parliament passed a legislative amendment; implementation is awaiting European Commission approval and the final green light of the national safety authorities.

China. Nuclear power generation increased by 2.8 percent—a modest development compared to the 11-percent boost in 2021—and provided a stable 4.9 percent of total electricity generation, marginally lower than the 5 percent in 2022. While nuclear capacity grew by 1 GW, solar capacity alone grew by over 200 GW. Non-hydro renewables produced 17.6 percent of national gross power generation, 3.6 times more than the nuclear contribution.

Czech Republic. Czech nuclear production was stable. Newbuild projects remain embroiled in legal battles without any final decisions on builders for either large reactors or small modular reactors.

France. Following 2022, “annus horribilis”, in the words of an EDF director, nuclear power generation recovered by 15 percent, but at 320 TWh remained still far from the 400 TWh considered normal a decade ago. Nuclear power represented 65 percent of the total power generation but only 16.3 percent of final energy. While the declared “planned” outage-days at zero-production dropped significantly in 2023 to (still remarkable) 127 days or four months per reactor, the declared “forced” outages have increased by 43 percent from 278 to 399 days exceeding any of the four previous years.

Hungary. The four Russian-designed VVERs generated almost 49 percent of the country’s power, the fourth highest share in the world. The country is highly dependent on Russia for its energy supplies and has been instrumental in blocking E.U. attempts to include the nuclear sector in sanction packages. Construction start of a newbuild project, Paks II, implemented by Rosatom, could happen before the end of the year 2024.

Japan. Two additional reactors were restarted in the second half of 2023 bringing the total to 12 operating units while 21 reactors remain in LTO. Nuclear power generation surged by 49 percent, but the nuclear share in total electricity nevertheless dropped again slightly, from 6.1 percent to 5.6 percent. The Noto Peninsula earthquake (1 January 2024), of recorded magnitude 7.6, caused damage to the Shika nuclear power station, shut down since 2011, and raised concerns in the local community.

Netherlands. The country operates one over 50-year-old reactor, the oldest in the E.U., that provided 3.4 percent of total electricity. The incoming government envisages the construction of two to four large reactors and has invited South Korean KEPCO’s subsidiary KHNP, Westinghouse, and EDF to carry out feasibility studies. The lower house of the Dutch Parliament voted a resolution to allow for the extension from two to four units. Meanwhile, the Netherlands has built up the largest installed per-capita solar capacity in the E.U.

Poland. In December 2023, a new administration was sworn in that, while in favor of the nuclear program, had previously expressed skepticism as to its feasibility, considering it was “not based on a robust economic analysis and lacks a business plan.” A first startup is thought possible by 2035 with construction starting in 2028. Meanwhile, over the year, solar capacity grew by 30 percent to 15.8 GW and contributed 7.25 percent to the national power consumption, a 17-fold increase in four years.

Russia. Seventy years ago, in 1954, the Soviet Union/Russia became the first country to connect a nuclear power plant to the grid. Today, Russia’s Rosatom is the leading nuclear power plant builder in the world with 26 units under construction in eight countries (including six in Russia) as of mid-2024. Rosatom also maintains its pro-active role in the hostile military occupation of Europe’s largest nuclear power plant, Zaporizhzhia, in Ukraine.

South Korea. The country operates the fifth largest nuclear power program (by capacity and production) in the world. Its 25 operating reactors generated a record 171.6 TWh in 2023. The national nuclear utility is responding to calls for tender for reactor construction in various countries but has refused to reveal financial records on the sole previous foreign deal with the UAE. By mid-2024, KEPCO’s debt load stood at an unparalleled US$147 billion.

Sweden. Nuclear power generation decreased by 6.7 percent, reaching 47 TWh accounting for just under 29 percent of national power production. The current government is determined to relaunch a nuclear newbuild program that should lead to at least 2.5 GW new capacity on the grid by 2035. However, so far, no design, provider, or site have been selected, and no financial package has been developed.

Taiwan. As of mid-2024, the country had two remaining reactors operating.13 Four others had been closed in the framework of a national nuclear phaseout plan. The last unit is planned to close by May 2025. So far, the buildup of other power-generation options has been slow but picked up speed in 2022 when renewables’ output outpaced nuclear for the first time. In 2023, solar power generation jumped by almost three quarters, while natural gas more than quintupled its 2020 production.

Türkiye. Russia’s Rosatom started building four units at the Akkuyu site between 2018 and 2022. Turkish authorities had hoped to connect Unit 1 to the grid in 2023, to coincide with the 100th anniversary of the foundation of the Republic of Türkiye. That target was missed, and startup of the first unit was delayed to 2024, and then delayed again to 2025. Reportedly, one reason for the latest delay is that equipment from Germany had not been delivered, likely due to current geopolitical circumstances. The project has also been troubled by a series of technical problems, e.g. parts of the foundation had to be redone, and worker health and safety issues, including a deadly meningitis outbreak.

Ukraine. Of 15 operating or operable reactors, six are at the Russian occupied Zaporizhzhia site; shut down for nearly two years, they entered the LTO category as of mid-2024. The remaining operating reactors are a constant cause of concern in a country engaged in a full-blown war. At 51 percent, Ukraine is nevertheless the country with the third highest nuclear share in total electricity generation in the world. Westinghouse is partnering with Ukrainian companies in a project to build two AP-1000 at the Khmelnytskyi site. However, the licensing and financing aspects remain unclear.

United Kingdom. There are only nine reactors with a combined capacity of 5.8 GW left operating in the country. Nuclear power generation dropped again by 14.5 percent to 37.3 TWh representing 12.5 percent of total electricity production (down from 28 percent in 1997). Meanwhile, further delays and cost increases for the two reactors under construction at Hinkley Point C have been announced; grid connection for the first unit is now planned between 2029 and 2031, and the price tag for the two units is estimated at US$52.5–59.2 billion.

United States. Nuclear output increased slightly (+0.9 percent) to 775 TWh. The nuclear share of commercial electricity generation increased accordingly by 0.4 percentage points to 18.6 percent. The U.S. nuclear fleet is still the largest in the world, with 93 units, as well as one of the oldest with a mean age 42.7 years. After 11 years of construction, the second of two new reactors at Plant Vogtle was connected to the grid in March 2024. All-in cost estimates for the two units have reached almost US$36 billion. In November 2023, SMR developer NuScale canceled its flagship Carbon Free Power Project (CFPP), after cost estimates soared and subscriptions hardly exceeded a quarter of the planned power generating capacity.

Fukushima Status Report

Thirteen years have passed since the Fukushima Daiichi nuclear power plant disaster began, triggered by the East Japan Great Earthquake on 11 March 2011 (also referred to as 3/11 throughout the report). The situation is still far from having been stabilized.

Overview of Onsite and Offsite Challenges

Onsite Challenges

Spent Fuel Removal. All spent fuel from the pool of Unit 3 had been removed by February 2021. Preparatory work is still underway on Units 1 and 2, with removal to begin in FY2027–2028 and to be completed by the end of 2031, more than 20 years after the disaster began.

Fuel Debris Removal. Due to technical challenges, operations have been postponed several times. Preparatory work for the trial debris removal at Unit 2 has made some progress. However, more detailed engineering studies on various retrieval options are needed.

Contaminated Water Management. As water injection continues to cool the fuel debris, highly contaminated water continues to run out of the cracked containments into the basements mixing with water from an underground river that has penetrated the basements. Various measures have reduced the influx of water from up to 540 m3/day in 2015 to about 80 m3/day in 2024. Nonetheless, an equivalent amount of water is partially decontaminated and stored in 1,000-m3 tanks daily, with a new tank filling up in less than two weeks.

As of 31 March 2024, about 1.2 million m3 of contaminated water were stored.

The safety authority have allowed operator TEPCO to release contaminated water into the ocean. As of the end of March 2023, about two thirds of the water needed to be treated again, and all of the water had to be diluted by a factor of 100 or more in order to meet licensed standards before being released into the ocean. TEPCO released approximately 31,200 tons of contaminated water in four rounds during the fiscal year through March 2024. The plan remains widely contested, including overseas.

Offsite Challenges

Offsite, the future of tens of thousands of evacuees, the contamination of food, and the management of decontamination wastes, all remain major challenges.

Evacuees. Although down from a peak of nearly 165,000 in May 2012, nearly 26,000 residents of Fukushima Prefecture remained living as evacuees as of 1 May 2024. In 2022, evacuation orders for some parts of the so-called “difficult to return areas” were lifted for the first time, but 2.2 percent of the Fukushima Prefecture surface continues to be designated as “difficult to return areas”. These areas continue to have significant exposure levels.

Food Contamination. According to official statistics, of a total of 43,643 samples that were analyzed in financial year up to end of March 2023, 162 samples from twelve prefectures, of which over half from wild animal meat, exceeded the radionuclide concentration limits. Whether the testing program provides an adequate picture of the situation remains open, considering that e.g. 12.5 percent of the wild animal samples from Fukushima exceeded contamination limits. As of the end of May 2024, six countries and regions—down from a peak of 54—still had import restrictions for Japanese food items in place. In July 2023, the European Commission lifted its remaining import restrictions for the E.U.

Decontamination and Contaminated Soil Management. The effectiveness of the decontamination operations remains uncertain. Decontamination is carried out only for areas within 20 meters of the so-called “living areas”. Around 71 percent of the Fukushima Prefecture is forested, so unsurprisingly only 2 percent of the area designated for decontamination was decontaminated. The contaminated soil is transferred to intermediate storage facilities in eight areas. As of the end of mid-2024, about 90 percent of total storage capacity was filled. The government is legally responsible for the final disposal of the contaminated soil.

Decommissioning Status Report

As an increasing number of nuclear facilities either reach the end of their pre-determined operational lifetime or close due to deteriorating economic conditions, timely decommissioning is becoming a key challenge.14

• The number of closed power reactors reached 213 units by mid-2024—one more than a year earlier and almost one third of the 655 reactors connected to the grid in the past 70 years have been closed. These had a total operating capacity of 106 GW.
• 190 units are awaiting or are in various stages of decommissioning.
• Only 23 units, or 11 percent of the closed reactors, have been fully decommissioned, one more than a year ago: 17 in the U.S., four in Germany, and one each in Japan and Spain (added over the past year). Of these, only nine, or 4 percent of all closed reactors, have been released from regulatory oversight as greenfield sites.
• The average duration of the decommissioning process is about 20 years, with a large range of 6–45 years (both extremes are for reactors with very low power ratings of 22 MW and 63 MW, respectively).
• The analysis of 11 major nuclear countries hosting 85 percent of all closed reactors shows that progress in decommissioning remains slow: of 159 units in various stages of advancement, 77 are in the “warm-up stage”, 31 (+4 compared to one year earlier) are in the “hot-zone stage”, 13 (+1) are in the “ease-off stage”, while 38 (-1) are in “long-term enclosure” (45 globally).
• To date, four of the early nuclear states— Canada, France, Russia, and U.K.—have not fully decommissioned a single reactor.

Potential Newcomer Countries

Africa Focus

For the first time, a dedicated Africa Focus section looks at a selection of countries and the status of nuclear aspirations on the continent. Only South Africa operates two ageing reactors in continental Africa (see South Africa in Annex 1). China and especially Russia have been the most aggressive promoters of nuclear power. While China has cooperation agreements with Kenya and Sudan with no concrete follow-up yet, Russia has inked agreements with about 20 countries and is in the course of building one plant in Egypt, the only nuclear construction site in Africa.

As a rule of thumb, the largest unit in a grid system should not exceed 10 percent of total available capacity in the system. There needs to be sufficient reserve production and transmission capacity to keep the grid stable, even if the largest unit is not available. A typical large modern reactor has 1 GW. The analysis of 18 African countries shows that only four of these—Algeria, Libya, Morocco, and Nigeria—would meet the production capacity criteria with more than 10 GW in the grid. Even there, adequate transmission capacity is uncertain. These constraints have led some countries to consider SMRs instead of large units. Below is a status overview for selected countries:

Egypt. Construction of the first (Russian-designed) nuclear power plant was launched at the El Dabaa site on 20 July 2022, even as the war in Ukraine was ongoing. Building of Units 2, 3, and 4 began in November 2022, May 2023, and January 2024, respectively.

Ghana. The country has set up a Nuclear Regulatory Authority, the Ghana Atomic Energy Commission, and Nuclear Power Ghana to develop the first nuclear power plant project. The U.S. considers Ghana an important ally in the region and a U.S.-Japanese initiative aims at establishing Ghana as an African leader in SMR rollouts. The country’s total installed capacity of around 5 GW would not allow for the integration of a large reactor.

Nigeria. The country signed nuclear cooperation agreements with several countries and considered the option of developing up to 4 GW of nuclear capacity. However, when in early 2023 Nigeria launched its Energy Transition Plan (ETP) with the goal of carbon neutrality by 2060, nuclear power did not feature amongst the options outlined for electricity generation.

Rwanda. The government signed an agreement with Canadian-German Company Dual Fluid in September 2023 to build and operate a demonstration unit by 2026. The capacity has not been specified in the announcement and it says “about 300 MW” on the company website. The innovative, untested design has not been licensed anywhere. The target date for startup seems unrealistic.

Uganda. The country offers a striking illustration of the disconnect between reality and plans for nuclear development: the Ugandan Government envisages the buildup of 24 GW of nuclear capacity, 18 times the country’s total installed capacity.

Other Potential Newcomer Countries

Besides Egypt, two other potential newcomer countries had nuclear reactors under construction as of mid-2024: Bangladesh and Türkiye. Both of these projects are implemented by the Russian nuclear industry. The full impact of sanctions and potentially other geopolitical developments on the future of these projects remains uncertain albeit some effects have already been documented.

Bangladesh. Two reactors of Russian design have been under construction since 2017–2018. They were scheduled to start up in 2023 and 2024. Sanctions have reportedly led to delays in the delivery of some equipment and the commissioning of Unit 1 has been pushed back at least until December 2024. The impact of the recent turmoil in the country remains to be seen.

Jordan. Attention has shifted from large reactors to SMRs. In October 2023, the government had submitted plans for SMR deployment to the IAEA. No precise construction plans have been communicated.

Kazakhstan. Several potential suppliers had been considered for the construction of small or large reactors, but no technology has been chosen, no site selected, and no financing package announced. The government has announced the organization of a national referendum prior to the launch of a nuclear power program.

Saudi Arabia. The government has issued a call for “best and final offers” from China, France, Russia, and South Korea for the construction of two large reactors. But the deadline has been extended twice, to July 2024 the last time. The government has also explicitly invited the U.S. to provide an offer; however, that is at least delayed due to a number of non-proliferation concerns.

Uzbekistan. In May 2022, officials announced that a site for the construction of two Russian-designed VVER-1200 reactors had been chosen. Subsequently, the plan was apparently abandoned in favor of an SMR project. Reportedly, in May 2024 the government signed an agreement with Russia’s Rosatom to build six 55-MW Small Modular Reactors (SMRs) in the eastern Jizzakh region. Should this materialize, it would be the first export agreement for an SMR anywhere in the world.

Russia Nuclear Dependencies

Russia has not only developed into the dominant international vendor of nuclear power plants. Further, the country is also playing a key role in the supply of fuel services, including uranium mining, conversion, and fuel assembly manufacturing for Soviet-designed VVER pressurized water reactors, of which there are 19 in the E.U. and 15 in Ukraine. The U.S. introduced sanctions on some subsidiaries of Russian government-controlled company Rosatom in April 2023 and banned the import of uranium products from Russia in May 2024. Since the invasion of Ukraine in February 2022, the E.U. has passed 14 sanctions packages against Russia as of mid-2024. Despite repeated calls—notably by the European Parliament—the nuclear sector remained exempt from sanctions—a clear indication of dependency on Russia in the field.

Surprisingly, the share of Russian supply of natural uranium, conversion, and enrichment services to the E.U. all increased between pre-war year 2021 and 2023. E.U. imports of fuel assemblies “shot up in 2023” (The Wall Street Journal), in fact at least doubling in total (data for Bulgaria unavailable), with Slovakia more than quadrupling and Hungary more than doubling imports compared to 2021.

Efforts to reduce or eliminate Russia dependencies in natural uranium, conversion, and enrichment services will likely increase costs.

The quasi-monopoly of Rosatom and its subsidiary TVEL constituted a technical dependency. Westinghouse provided an alternative, but only for some clients, some fuel, and some periods of time. Since the Russian invasion of Ukraine, things are starting to change. Westinghouse has greatly expanded its client-base in Europe beyond Ukraine and is increasing manufacturing capacity. Concurrently, VVER-operating utilities accelerated fuel assembly deliveries, apparently due to concerns about potential sanctions on Russian fuel. Competitor Framatome is also entering the market.

Westinghouse has apparently reverse-engineered VVER fuel assemblies. Perhaps to avoid an expensive learning curve, Framatome decided to expand its long-term cooperation with Rosatom for the manufacturing of VVER fuel elements instead. The company chose its Lingen site in Germany to plan for a VVER-dedicated fuel assembly production line, which created political problems with the German authorities that have yet to be resolved.

Interdependence between Russia and its western partners remains significant. With Rosatom implementing all 13 nuclear power reactor construction sites started outside China over the past five years, providers of parts, e.g. France’s Arabelle turbines, do not have any other foreign customer besides Rosatom. Germany’s Instrumentation & Control technology has a similar problem.

The close mutual industrial and market interdependencies between the Russian nuclear industry and its western counterparts at least partially explain European hesitations to impose sanctions on the nuclear sector.

Civil-Military Cross-Financing in the U.K. Nuclear Sector

This chapter follows up directly on work discussed in WNISR2018 that examined interdependencies between civil and military nuclear infrastructures around the world. It summarizes an academic study, carried out in the framework of a wider U.K. Government project, that assesses the overall flows of money and other resources that deeply interlink supposedly separate civilian and military nuclear activities.

The study also provides a rough estimate of the opportunity costs of civil nuclear power use in the U.K., identifies revenues from ‘civil’ taxpayer and consumer budgets to cover costs of military nuclear activities that fall outside existing levels of defense spending, and assesses the costs of an expensive array of nuclear-specific policy, regulatory, research and industrial bodies that are unnecessary for non-nuclear strategies.

Subject to considerable uncertainties, the analysis suggests that the overall excess costs to the U.K. economy of keeping the national nuclear complex in operation, may be estimated conservatively to exceed £5 billion (US$6.3 billion) per year.

Militarization of Civil Nuclear Reactors: Tritium for Nuclear Weapons

In March 2024, the French Government announced that, following the closure of its dedicated tritium production reactors, it was partnering with the utility EDF to produce tritium for its nuclear weapons program at the Civaux dual-reactor nuclear power plant. Though the program has not yet been approved by the regulator, a first test is already planned for 2025. Virtually no information has been released on the project other than a one-page Defense Ministry press statement.

The chapter provides an overview of the purpose of tritium production and the precedent in the U.S. where the two Watts Bar reactors in Tennessee serve the same purpose. The first 18-month production cycle was started at Watts Bar-1 in 2003. It was discovered that the tritium permeation rate into the reactor coolant was nearly ten times higher than predicted, leading it to exceed the regulatory limit for tritium release in wastewater. This led the Nuclear Regulatory Commission (NRC) to impose a limit of the so-called Tritium-Producing Burnable Absorber Rods (TPBARs) per irradiation cycle significantly below the originally envisaged number. As the Department of Energy raised its tritium requirements (for unknown reasons), it applied for permission to increase absorber rods. NRC authorized an increase by a factor of 2.5 to a maximum of 1,792 absorber rods. The maximum amount was loaded in 2023 into Watts Bar-1 and 1,104 in Watts Bar-2. The effects of these changes to the tritium content in wastewater are not known yet.

Small Modular Reactors (SMRs)

The gap between hype about Small Modular Reactors (SMRs) and industrial reality continues to grow. The nuclear industry and multiple governments are doubling down on their investments into SMRs, both in monetary and political terms. So far, reality on the ground does not reflect those efforts. SMR projects continue to be delayed or canceled. Costs for nuclear projects in general and SMRs in particular are surging. The few available cost estimates for SMRs, especially when weighted by their electrical power generation capacities, show how expensive these are.

The country-by-country status:

Argentina. The CAREM-25 project had been under construction since 2014. Reportedly, construction was halted in spring 2024 due to budget cuts (WNISR retains it ‘under construction’ for the time being). The National Atomic Energy Commission (CNEA), builder-owner of the reactor, decided to carry out a “critical design review” prior to construction restart. The estimated date for startup has been pushed back to 2028. Recent estimates suggest the reactor will cost at least US$800 million or US$32,000/kW, much more on a per kilowatt basis than the most expensive large Generation-III reactors.

Canada. Strong federal and provincial government support for the promotion of SMRs continues. The Canadian Nuclear Safety Commission (CNSC) also promotes SMRs. Several designs have gone through a “pre-licensing vendor design review” but none has yet been certified.

China. It took ten years between construction start and first full power in December 2022 for two high-temperature reactor modules, twice as long as anticipated. Since then, the operational record appears disappointing. Nominal capacity has been downrated for unknown reasons by 25 percent from 200 MW to 150 MW for the two units. A second design, the ACP100 or Linglong One, has been under construction since July 2021 with scheduled startup by May 2026.

France. In February 2022, President Macron announced a US$20221.1 billion contribution to finance the development of the Nuward SMR design and other “innovative reactors”. “Basic design” studies were to be completed by 2026 and construction was scheduled to start in 2030. But in mid-2024, EDF confirmed that it had suspended the development and reoriented the project “to a design based on proven technological building blocks”. Consequences on timeline and costs are uncertain yet.

India. An Advanced Heavy Water Reactor (AHWR) design has been under development since the 1990s, but its construction has been continuously delayed. There have been no reports about progress over the past three years, which raises the possibility that the design has been shelved. Meanwhile, the government has announced the start of a new Bharat SMR program and talks continue about potential cooperation on SMRs with various countries including France and Russia.

Russia. Russia has a special focus on barge-mounted SMRs, and two 30-MW “floating reactors”, the Akademik Lomonosov, were started up in December 2019, nine years later than planned. Since then, their performance has been mediocre. Two more barge-mounted projects are underway. Construction on a different, land-based SMR project, a lead-cooled fast reactor design called BREST-300, started in June 2021. The project has been discussed for a decade and was originally to be deployed by 2018.

South Korea. In 2012, the System-Integrated Modular Advanced Reactor (SMART) design received approval by the safety authority, but there have been no orders since. Several other designs are reportedly in early stages of development, in particular the “i-SMR”. The regulator has yet to receive an application for standard design approval, not expected before 2026, with plans to start construction in 2029.

United Kingdom. Since 2014, Rolls Royce has been developing the “UK SMR”, a (now) 470 MW reactor (exceeding the size-limit of 300 MW for the generally adopted SMR definition). The regulator is currently carrying out a Generic Design Assessment (GDA) that is scheduled to be completed by August 2026. Six other SMR designs were submitted for review of which four have been rejected for failing the GDA entry criteria and only Holtec’s SMR-160 and GE-Hitachi’s BWRX-300 were accepted for review. The government aims for a final investment decision by 2029.

United States. The Department of Energy (DOE) continues to offer large amounts of funding for SMR development. In June 2024, DOE announced it would provide US$0.8 billion for “up to two first-mover teams of utility, reactor vendor, constructor, and end-users or power off-takers committed to deploying a first plant”. In other words, there is still not a single reactor under construction.

Only one design, NuScale, had received a (conditional) final safety evaluation report. However, since then, the design capacity has been increased from 50 MW to 77 MW per module, and many issues remain unresolved. By January 2023, cost estimates had ballooned to US$9.3 billion, and in early November 2023, the entire investment project was terminated.

In June 2024, the ground-breaking ceremony was held in Wyoming for TerraPower’s Natrium fast reactor. The nuclear regulator has not yet licensed the design of the 345-MW fast reactor—exceeding the size-limit of the SMR-definition—nor has it issued a construction license.

Nuclear Power vs. Renewable Energy Deployment

In 2023-24, the global energy landscape continued being reshaped by national, continental, and global climate ambitions in the face of persistent economic pressures, including inflation and geopolitical tensions. There is no doubt, however, that the renewable energy sector got another significant boost over the period. The Global Renewables and Energy Efficiency Pledge, launched at COP28 in Dubai in December 2023 and endorsed by about 130 national governments and the E.U., aims to triple global renewable energy capacity to 11,000 GW (11 TW) and double the annual rate of energy efficiency improvements to over four percent by 2030.

Investment. Total investment in non-hydro renewable electricity capacity in 2023 was estimated by Bloomberg New Energy Finance (BNEF) at US$623 billion, up 8 percent compared to the previous year. According to a WNISR estimate, this represents 27 times the reported global investment decisions for the construction of nuclear power plants of about US$23 billion for 6.7 GW. According to BNEF, investment in solar increased by 12 percent to reach US$393 billion. Investments in wind power plants followed at US$217 billion seeing a slight reduction in investments for onshore wind more than offset by a record US$77 billion for offshore wind plants. BNEF estimated investments in stationary storage capacity at around US$36 billion, which, for the first time, exceeded investments into new nuclear.

Installed Capacity. Annual additions of solar and wind power grew by 73 percent and 51 percent, respectively, resulting in nearly 460 GW of combined new capacity, according to the International Renewable Energy Agency (IRENA). The solar PV market saw China alone adding around 217 GW—a 150-percent increase over 2022-additions—and the rest of the world 129 GW for a total of 346 GW or about 1 GW per day. The Global Wind Energy Council (GWEC) reported a record of 117 GW of new wind installations, a 50 percent year-on-year increase, with China accounting for 65 percent of total added onshore capacity and 58 percent of total added offshore capacity. These numbers compare with a net addition of 1 GW nuclear capacity in China and -1 GW globally between new startups and closures.

Electricity Generation. In 2021, the combined output of solar and wind plants surpassed nuclear power generation for the first time. In 2023, wind and solar facilities generated 50 percent more electricity than nuclear plants. Wind power alone generated 2,300 TWh and is getting close to nuclear’s 2,600 TWh. Since 2013, non-hydro renewables added 3,500 TWh to the world’s power generation, 14 times more than nuclear’s roughly 250 TWh, and generated 80 percent more power than nuclear in 2023.

China. Solar PV produced a total of 578 TWh of electricity in 2023, for the second year in a row, overtaking nuclear power that generated 413 TWh by 40 percent. Wind outpaced nuclear in 2012 and has stayed ahead every year since. Wind power plants produced 877 TWh, more than twice the nuclear power generation. Adding other non-hydro renewables like biomass to solar and wind, the net total generation of 1,643 TWh represents four times the nuclear output, or more than three times the total power consumption of Germany, the world’s fourth largest economy (by GDP in 2022).

European Union. In 2023, the E.U. achieved its largest renewable capacity additions ever and the renewable share in total electricity generation reached 44 percent, exceeding 40 percent for the first time. Solar and wind plants together produced 721 TWh—almost a quarter more than nuclear energy with 588 TWh—accounting for 27 percent of the E.U.’s gross electricity production. Notably, in 2023, for the first time ever, non-hydro renewables generated more power than all fossil fuels combined, and wind alone surpassed fossil gas. Fossil fuels generally dropped by a record 19 percent, reaching their lowest level ever and accounting for less than one-third of the E.U.’s electricity generation.

India. Over the period 2000–2023, electricity generation from wind power grew 50-fold. Solar power capacity surged by 85 percent in the short period between 2020 and 2023, while nuclear added nothing in operational capacity. Solar power generation soared by 19 percent in 2023 and India overtook Japan as the third largest solar electricity generator. Solar and wind individually generated 2.4 times and 1.8 times respectively more electricity than nuclear.

United States. According to the Solar Energy Industries Association (SEIA), solar power experienced remarkable growth in 2023 with a record 31 GW of new solar capacity installed—55 percent more than 2022 additions. Wind capacity increased by 8 GW. On-grid solar power output increased from virtually nothing in 2000 to 238 TWh in 2023. Over the same period, installed nuclear capacity has remained almost stable at 96–100 GW and production has fluctuated roughly between 750–810 TWh.

Power Firming and Competitive Pressure on Nuclear

What is firming? Asset level firming pairs variable renewables with another power resource via co-located or hybrid plants to backfill hours when solar and wind are not available. Battery storage is increasingly used for firming, boosting reliability and availability for variable producers while also providing some additional market power to store and later sell electricity when prices are higher.

Power firming is already an important and growing complement to variable renewables. Within the United States, there were 374 hybrid power plants operating at the end of 2022, excluding hydro pumped storage. These comprised more than 40 GW of generating capacity, of which more than half were PV plus storage. Most of these installations have occurred since 2020, which is indicative of the rapid improvements in the viability and market attractiveness of utility scale batteries. In recent months, battery storage in the U.S. state of California has sometimes met more than 20 percent of peak power demand, contributing around 7 GW, the equivalent of seven large nuclear reactors, to the grid.

Multiple sources of value from utility-scale storage support continued rapid growth. Grid services and renewable firming dominate the use cases for wind while peak shaving is an additional area of importance for PV. These additional sources of value help to propel and accelerate storage installations.

Globally, utility-scale storage additions jumped from just over 10 GW added in 2022 to more than 25 GW in 2023 (net nuclear additions were -1 GW).

The OECD’s International Energy Agency (IEA) has concluded in a recent study that, even if taking into account the increased need for reserve margin, spinning reserve, part-load penalties, and cycling costs, solar plus storage is on the winning stretch:

• Costs are expected to fall below those of coal-fired and nuclear power plants by around 2025 in China.
• Solar plus storage is already more competitive than coal in India and remains so going forward.
• Costs are expected to drop below those of new efficient gas-fired power plants before 2025 in the U.S., and “substantially extends its lead by 2030.”
• Carbon pricing within the E.U. means that solar PV plus battery storage already easily outcompetes natural gas-fired power.
• Solar plus storage is already “significantly lower than nuclear power in most markets today,” as well as “highly competitive with other low-emissions sources of electricity that are commercially available today.”

Estimates by investment bank Lazard also conclude that solar hybrids are often cheaper than gas peaking and new nuclear, while wind plus storage turned out even less expensive than coal in many circumstances. The competitive cost and large-scale availability of variable renewable energy sources combined with firming options—especially storage—could well turn out to be the game-changer of energy policy in the years to come.

Introduction

The global geopolitical situation remains tense in 2024. The nuclear power issue is still linked to a full-scale war, with the largest European nuclear power plant by installed capacity, Zaporizhzhia in Ukraine, still under hostile military occupation, assisted by engineers of Russian state-owned company Rosatom. The six reactors of the site have not generated power since 2022. But, as Russia steps up attacks against power generating or transport facilities and is seeking to cause disruption to the power system especially during the coming winter, the other nine operational nuclear reactors also come under increasing threat.

In the summer of 2024, an additional nuclear risk zone was opened by Ukraine’s surprise attack—which turned out to be much more significant than originally interpreted by international observers—in the Russian Kursk region, which houses another large nuclear power plant with two operating reactors, two closed ones, and two units under construction. The risk of a nuclear disaster has increased again.

WNISR2022’s chapter on Nuclear Power and War detailed why a nuclear reactor needs a functioning cooling system at all times, meaning it also needs reliable electricity supply at all times, during operation and after shutdown.

WNISR2024 has a chapter on Russia Nuclear Dependencies analyzing the question of dependencies of many countries on Russia as nuclear service and hardware provider, but also the other way around. Of the 35 reactor construction-starts in the world in the five years between December 2019 and mid-2024, 22 took place in China and the remaining 13 were implemented by the Russian nuclear industry in eight countries (including Russia). Nothing else. Nowhere. As Chinese companies do not need foreign components, who will buy, for example, French Arabelle turbines if not Rosatom? At the same time, as the chapter demonstrates, the share of Russian supplies in natural uranium, enriched uranium, and fuel assembly deliveries to the European Union went up in 2023 if compared with pre-war year 2021.

Two International Atomic Energy Agency (IAEA) General Assemblies have passed since the beginning of the all-out war in Ukraine, yet nothing has been reported on the potential discussions about establishing basic conditions for prospective newcomer countries to receive technical assistance and by whom, now and in the future. Russia continues to implement by far the most newbuild projects around the world—20 outside Russia in seven countries—many of them, if not all, with the assistance of the IAEA. Still, neither political decision-makers nor the international media have addressed the issue.

In addition to the usual overview of potential nuclear newcomer countries, WNISR2024 features a section on developments in Africa where a lot of noise is being made around potential nuclear projects, conferences are being held, and countless memoranda being signed, most of them with little chances of concrete activities on the ground.15 Not only are the costs out of reach for many countries, but the grid systems are too small for a large nuclear reactor of 1 gigawatt (GW) or more. As a rule of thumb, used by the IAEA and others, the largest unit in a grid should not exceed 10 percent of the total installed capacity. Only four out of 18 assessed African countries with nuclear ambitions have grids that exceed 10 GW (Algeria, Libya, Morocco, and Nigeria). However, on 29 August 2024, the U.S. State Department announced the “signing of a commercial agreement between Nuclear Power Ghana (NPG) and Regnum Technology Group, the U.S. developer for a Small Modular Reactor (SMR) project using NuScale Power technology.”16 The goal is the deployment of a single NuScale VOYGR-12 reactor module. The VOYGR-12 design is not yet licensed anywhere, and no information is available on timelines or the financial package.

Many international media outlets continue to provide large-scale coverage of early, often vague developments of SMR designs, politicians take policy decisions and make plans for the near future, investors speculate, despite the lack of major progress to report on the ground (see chapter on SMRs)—“at least not outside China and Russia—with no startups, no construction starts, not even a design certification” (no change from WNISR2023). The once most advanced scheme in the western world, a NuScale project with a conglomerate of Utah municipalities, was terminated in early November 2023 following a significant rise in cost estimates and the subsequent failure to line up enough potential clients.

While effective action on the climate emergency is needed across all sectors and societies, one of the highest profile initiatives is the pledge for a trebling of the current renewables’ capacity and the doubling in energy efficiency by 2030. These targets were embraced by 133 countries at COP 28 in Dubai in December 2023. Beyond the traditional Nuclear Power vs. Renewable Energy Deployment chapter, this report presents a first analysis of Power Firming and Competitive Pressure on Nuclear, looking at the potentially game-changing developments in hybrid systems that aim to provide the same grid service and reliability as dispatchable sources like nuclear and fossil fuels. These systems are growing quickly and becoming increasingly competitive with conventional power supply options, including winning capacity auctions and alleviating demand peaks.

An assessment released by the International Renewable Energy Agency (IRENA) in July 2024 confirms that “renewables are the fastest-growing source of power worldwide, with new global renewable capacity in 2023 representing a record 14% increase from 2022”, but that is not enough. The annual growth rate would need to be at least 16.4 percent to get on track of tripling capacity by 2030.17 In comparison, nuclear power has become irrelevant in the international market for electricity generating capacity, with more nuclear capacity closing than being newly added to the world’s grids.18

A pledge to triple nuclear generating capacity by 2050, was also launched during COP28—considering the lack of industrial capacity, low building rates, long lead-times, and high costs involved in nuclear construction—seems highly unrealistic and has attracted comparatively little support with 25 countries signing up, including major nuclear players like France, Japan, the U.K., and the U.S., but also non-nuclear countries like Jamaica, Moldova, Mongolia, and Morocco.19 Significantly, the pledge does not include the two major nuclear builders China and Russia. The annual global reactor building rate would have to almost double from five in the past two decades to ten simply to replace aging units that can be expected to close by 2050 (see Lifetime Projections). In order to triple the installed capacity an additional 1,000+ reactors would need to be built. This is impossible considering there are only a handful of nuclear builders around the world that can respond to calls for tenders for large units, and all of them have considerable limitations: the French Electricité de France (EDF) and Korea’s Korea Electric Power Corporation (KEPCO) have very large debt loads (US$60 billion and over US$140 billion, respectively) and face technical and manpower challenges with their existing ageing nuclear fleets and ongoing construction projects; the Chinese China General Nuclear Power Group (CGN) and China Natinal Nuclear Corporation (CNNC) have been blacklisted by the U.S. Government; Russian Rosatom is suffering from international sanctions; and Westinghouse has made it clear that it will only supply technology and engineering but not act as a builder anymore.20 Who is supposed to build hundreds of nuclear power reactors around the world over the coming two and a half decades?

In 2023–2024, the gap has widened again between media attention, political announcements, and public perception of the nuclear sector on one side and the industrial reality on the other side. The comprehensive documentation and analysis that WNISR2024—just as earlier editions—provides on the status and trends of the nuclear industry shows a sector that struggles to maintain ageing operating fleets, accumulates significant delays and cost overruns at construction projects, and fails to timely develop competitive new designs.

One question remains: in the absence of a convincing economic, energy- or climate-policy argument, what are the drivers for policy decisions in favor of plant lifetime extension or nuclear newbuild? This is a complex question and there is not one answer that fits all situations. In most cases, it is a combination of various drivers such as the powerful, long-term lock-in effect of a nuclear power project that binds two or more countries together for decades and untransparent package deals involving strategic interests outside the nuclear sector be it fossil fuels, raw materials, defense related issues or items seen as strategic by the protagonists that are never made public. In a concerning number of cases, corruption has proven to be another powerful driver in many countries, including Brazil, China, Russia, and the U.S. (see also Nuclear Power and Criminal Energy in WNISR2021).

The multi-layer connection between nuclear power and the military sector is particularly interesting. Of 59 reactors under construction in the world as of mid-2024, 55 (93 percent) are either built in nuclear weapon states or by a nuclear weapon state-controlled company—e.g. Rosatom—in other countries.

WNISR2018 carried a first analysis of Interdependencies Between Civil and Military Nuclear Infrastructures in various countries. WNISR2024 presents a short update on the matter and deeper analysis of the U.K. case that provides for the first time an estimate of undeclared taxpayer and ratepayer financing flows to the civil and military nuclear sectors (see Civil-Military Cross-Financing in the U.K. Nuclear Sector).

Another example is dual-use of specific facilities. Following the French Government’s decision to militarize the two most recent French power reactors at Civaux and start tritium production for its nuclear weapons program, this edition provides a short overview of the issue on the basis of the U.S. precedent at the Watts Bar plant (see Militarization of Civil Nuclear Reactors: Tritium for Nuclear Weapons).

Understanding the political and other motivations is essential to grounding the debate on the nuclear power option finally on fact-based analysis. The WNISR provides a contribution to that goal.

General Overview Worldwide

Role of Nuclear Power – Nuclear Power Generation

For the past five years, Russia has been the dominating global reactor builder outside China and, even after the full-scale invasion of Ukraine and a hostile takeover of Europe’s largest nuclear power plant, Zaporizhzhia, it continues to work closely with the International Atomic Energy Agency (IAEA), especially in potential newcomer countries. In its introductory statement to the First Session of the Preparatory Committee for the 11th Review Conference of the Parties to the Non-Proliferation Treaty (NPT) in August 2023, the Russian Ministry of Foreign Affairs stressed:

Russia considers the efforts to promote the nuclear energy development central to the IAEA work. We cooperate with the Agency in implementing the initiative launched in 2017 to develop the nuclear energy infrastructure of newcomer countries. Russia is the initiator and leading donor of the IAEA International Project on Innovative Reactors and Fuel Cycles, in which 43 countries and the European Commission participate. (…)

We note that all NPT-compliant countries should have access to peaceful nuclear energy without any additional conditions.21

As of mid-2024, 32 countries operated nuclear power programs. Figure 1 illustrates how the spread of nuclear power throughout the world took place at a significantly slower pace and smaller scope than anticipated in the early 1970s:

• Fourteen countries had operating nuclear power reactors (grid connected) when the Treaty on the Non-Proliferation of Nuclear Weapons (commonly known as the nuclear Non-Proliferation Treaty, or NPT) entered into force in 1970.
• Sixteen additional countries were operating power plants by 1985, the year when reactor startups peaked.
• Four countries (Romania, Iran, United Arab Emirates, and Belarus) have started up power reactors for the first time over the past 30 years, of which two in 2020.
• The number of countries operating power reactors in 1996–1997 reached 32. It took another 23 years to reach a new peak at 33 countries.
• Four countries (Germany, Italy, Kazakhstan and Lithuania) abandoned their nuclear power programs.
• Ten of the 32 nuclear countries have active reactor construction programs.
• Twenty-two nuclear countries are not currently constructing any reactors (or construction is suspended); of these, four have either nuclear phaseout, no-newbuild, or no-program-extension policies in place (Belgium, Spain, Switzerland and Taiwan). Some of these program-limitation policies, such as in the Netherlands and Sweden, have been revised only recently. However, while policy changes in some countries reopen the door for nuclear newbuild, actual work on the ground remains many years away.

1. National Nuclear Power Programs Development, 1954–2024

Sources: compiled by WNISR, with IAEA-PRIS, 2024

In 2023, the world nuclear fleet generated 2,602 net terawatt-hours (TWh or billion kilowatt-hours) of electricity22, (see Figure 2). After a decline in 2020, nuclear production increased by 3.9 percent in 2021, dropped by 4 percent in 2022 and increased again by 2.2 percent in 2023. As in 2021, it stayed below the 2019 level. China, with a 2.8-percent increase (compared to 11 percent in 2021 and 3.2 percent in 2022), produced more nuclear electricity than France for the fourth year in a row, and remains in second place—behind the U.S.—of the top nuclear power generators. Nuclear production outside China increased by 2.1 percent, to reach the equivalent of the global production of 1995.

Nuclear energy’s share of global commercial gross electricity generation in 2023 was almost stable at 9.15 percent—the lowest value in four decades—and over 45 percent below the peak of 17.5 percent in 1996.23

Non-hydro renewables continued their growth, with a 13-percent increase, to reach a share of 7.5 percent in primary energy. While the share of non-hydro renewables is now 1.9 times larger than the nuclear share, both figures illustrate how modest the current contribution of both technologies remains in the global context.

Nuclear’s main competitors, non-hydro renewables (primarily solar and wind) grew their gross output by 12.9 percent and their share in global gross power generation increased by 1.5 percentage points to 15.9 percent.

Non-hydro renewables continued their growth, with a 13-percent increase, to reach a share of 7.5 percent in primary energy. While the share of non-hydro renewables is now 1.9 times larger than the nuclear share, both figures illustrate how modest the current contribution of both technologies remains in the global context.

In 2023, there were ten countries—compared to six in 2022—that increased the nuclear share in their respective electricity mix, including two “newcomer countries”, the United Arab Emirates (UAE) and Belarus, which generated nuclear power for the first time in 2020, while eight decreased, and 15 remained at a constant level (change of less than 1 percentage point). Besides the UAE and Belarus, six countries (China, Finland, India, South Korea, Pakistan, Slovakia) achieved their largest ever nuclear production. Belarus, China, and Slovakia started up new reactors during the year, as well as South Korea, but only in December, so with little effect on overall output which increased by modest 2.5 percent.

The following noteworthy developments for the year 2023 illustrate the volatile operational situation of the individual national reactor fleets (see country-specific sections for details):

• Argentina’s nuclear production increased by nearly 20 percent following a drop of 26.5 percent, primarily due to months-long—planned and unplanned—maintenance and reparation outages at one of its three reactors.
• Belarus has seen a spectacular, close to 150-percent increase in nuclear generation mainly due to the startup of its second unit.
• Belgium, following an exceptional 2021 and a drop of 13 percent output in 2022, nuclear power production declined again by 25 percent partially due to the closure of one unit in February 2023.
• China started up only one unit following three startups in both 2022 and 2021, with nuclear generation increasing a modest 2.8 percent following increases in 2022 and 2021 of respectively 3.2 percent and 11.2 percent.
• Finland saw a significant 35 percent increase in nuclear generation due to the beginning of the commercial operation of the largest nuclear reactor in the country, Olkiluoto-3, 18 years after construction start.
• France’s nuclear generation picked up by close to 15 percent following a record 22.7 percent drop to below 300 TWh for the first time since 1990 but remained below 400 TWh for the eighth year in a row.
• Germany completed its nuclear phaseout in mid-April 2023 and therefore nuclear power output declined by 79 percent compared to 2022.
• Japan has boosted nuclear electricity generation by almost half following the restart of two additional units—12 reactors are now in operation—and improved productivity of the remaining fleet.
• South Africa once again has experienced a highly volatile nuclear generation pattern. Output dropped again by close to 20 percent following a 17-percent decline in 2022.
• The UAE reached a logical all-time high in nuclear power generation after connecting to the grid the third of four nuclear units that were under construction. Output increased by 31 percent.
• In the U.K., after decreasing steadily between 2016 and 2021, nuclear generation increased by 4.3 percent in 2022. However, as two reactors closed in the second half of 2022, output dropped by 14.5 percent in 2023.

1. Nuclear Electricity Generation in the World... and China

Sources: WNISR, with IAEA-PRIS and Energy Institute, 2024

Note: IAEA-PRIS production data for the years 2022 and 2023 does not include Ukraine (data unavailable). Net nuclear production for Ukraine for those years represented 59 TWh and 49 TWh respectively according to the Energy Institute’s “Statistical Review of World Energy” dataset.24 The total number is thus based on IAEA-PRIS plus the production figure for Ukraine from the Energy Institute.

Similar to previous years, in 2023, the “big five” nuclear generating countries—the U.S., China, France, Russia, and South Korea, in that order—generated 72.4 percent of all nuclear electricity in the world (see Figure 3, left side).

In 2002, China was 15th in terms of global production levels; in 2007, it was tenth, and it reached third place in 2016. In 2020—earlier than anticipated due to the mediocre performance of the French fleet—China became the second largest nuclear generator in the world, a position that France held since the early 1980s. That has not changed since.

1. Nuclear Electricity Generation and Share in National Power Generation

Sources: IAEA-PRIS, and Energy Institute data for Ukraine, compiled by WNISR, 2024

Note: For comparison reasons, data used in this graphic are IAEA-PRIS data, except for Ukraine, and may differ from data used in the country sections.

In 2023, the top three countries, the U.S., China, and France, remained at around 58 percent of global nuclear output, underscoring the concentration of nuclear power generation in a very small number of countries.

In many cases, even where nuclear power generation increased, the addition is not keeping pace with overall increases in electricity production, leading to a nuclear share below the respective historic maximum (see Figure 3, right side). Six of the current 32 nuclear countries achieved their historically largest nuclear shares in the 1980s, seven in the 1990s, six in the 2000s, four in the 2010s, nine in the short 2020s with a remarkable eight for the single year of 2023.

Startups/Closures, Operation, Age Distribution

Since the first nuclear power reactor was connected to the Soviet power grid at Obninsk in 1954, there have been two major waves of startups. The first peaked in 1974, with 26 grid connections. The second reached a historic maximum in 1984 and 1985, just before the Chornobyl accident in 1986, reaching 33 grid connections in each year. By the end of the 1980s, the uninterrupted net increase of operating units had ceased, and in 1990, the number of reactor closures25 outweighed the number of startups for the first time.

The 1994–2003 decade globally produced almost a third more startups than closures (44/33), while in the decade 2004–2013, startups compensated for only about 60 percent of the closures (35/59) (see Figure 4).

In the past decade 2014–2023, 67 reactors were started-up, that is 60 percent more than in the previous decade—of which 37 (55 percent) in China—and 45 were closed (none in China).

Over the past two decades 2004–2023, there were 102 startups and 104 closures. Of these, 49 startups were in China which did not close any reactors. As a result, outside China, there has been a drastic net decline of 51 units (see Figure 5). As larger units were started up (totaling 94 GW) than closed (totaling 73.3 GW) the net nuclear capacity added worldwide over the 20-year period was 20.7 GW. However, since China alone added half of the capacity (47 GW), the net capacity outside China declined by almost 26.5 GW.

In 2023, five reactors were connected to the grid, one each in Belarus, China, Slovakia, South Korea, and the U.S., and five were closed, three in Germany and one each in Belgium and Taiwan.

In the first half of 2024, four units were connected to the grid, one each in China, India, the UAE, and the U.S., and one was closed in Russia. (See Figure 5).

1. Nuclear Power Reactor Grid Connections and Closures in the World

Sources: WNISR, with IAEA-PRIS, 2024

Notes: WNISR considers reactors closed as of the date of their last electricity production, and not as of their closure announcement (which can be made years after the reactor ceased production).

As of 1 July 2024, a total of 408 nuclear reactors were operating in 32 countries, one more than reported for mid-2023.26 The current world fleet has a total electric net operating capacity of 367.3 GW. As the annual statistics always reflect the status at year-end, the situation might change again by the end of 2024.

The number of operating reactors remains ten below the fleet size already reached in 1989 and 30 below the 2002-peak (see Figure 6).

Usually, the capacity of new reactors is larger than the ones that are closed. The year 2023 was an exception: while five reactors closed and five reactors started up, the capacity of those closed at 6 GW exceeded the new ones by 1 GW, mainly because of the retirement of three large German units totaling over 4 GW.

For many years, the capacity increased more than the number of reactors as a result of the combined effects of larger units replacing smaller ones and “uprating”. In 1989, the average size of an operational nuclear reactor was about 740 MW, in 2023 it was almost 900 MW. Technical alterations raised capacity at existing plants resulting in larger electricity output, a process known as uprating.27 In the U.S. alone, the Nuclear Regulatory Commission (U.S. NRC) has approved 172 uprates since 1977. The cumulative approved uprates in the U.S. total 8 GW, the equivalent of eight large reactors. These include seven minor uprates (<2 percent of reactor capacity) approved since mid-2020, of which only one since mid-2021.28 So this is a program that is pretty much completed in the U.S.

1. Nuclear Power Reactor Grid Connections and Closures – China Effect Pausing?

Sources: WNISR, with IAEA-PRIS, 2024

A similar trend of uprates and major overhauls in view of lifetime extensions of existing reactors has been seen in Europe. The main incentive for lifetime extensions is economic but this argument is being increasingly challenged as refurbishment costs soar and alternatives become cheaper.

1. World Nuclear Reactor Fleet, 1954–mid-2024

Sources: WNISR, with IAEA-PRIS, 2024

IAEA’s Operating Reactor Data Revisions

Until September 2022, the IAEA’s online Power Reactor Information System (PRIS) database counted 33 reactors as operational/operating in Japan, whereas 20 of these had not produced power since 2010–2012, and an additional three units had been shut down even since the Niigata Earthquake in 2007.

For almost a decade, WNISR has been calling for an appropriate reflection in world nuclear statistics of the unique situation in Japan. The approach taken by the IAEA, the Japanese Government, utilities, industry, and many research bodies as well as other governments and organizations to continue classifying the entire stranded reactor fleet in the country as “in operation” or “operational” was misleading.

Faced with this dilemma, the WNISR team in 2014 decided to create a new category with a simple definition, based on empirical fact, without room for speculation: “Long-Term Outage” or LTO. Its definition:

A nuclear reactor is considered in Long-Term Outage or LTO if it has not generated any electricity in the previous calendar year and in the first half of the current calendar year. It is withdrawn from operational status retroactively from the day it was disconnected from the grid.

When subsequently the decision is taken to close a reactor, the closure status starts with the day of the last electricity generation, and the WNISR statistics are retroactively modified accordingly.

IAEA’s Category “Suspended Operation”

On 16 January 2013, the IAEA moved 47 reactors in Japan, most of them shut down in the aftermath of the Fukushima events in 2011, from the category “In Operation” into “Long-term Shutdown”29 that existed in the IAEA statistical system until October 2022. Only two days later, the move was labelled a “clerical error” and the action was reversed at the request of the Japanese Government.30

It was only in September 2022, that in the IAEA-PRIS database, twelve Japanese reactors31 were gradually withdrawn from the list of “operating” or “operational” reactors, and their status changed to “Long-term Shutdown” (LTS). By mid-October 2022, the category title was changed to “Suspended Operation” on the PRIS website32, and in November 2022, four more Japanese units33 joined the new category as well as one Indian reactor (Rajastan-1) that has not generated any power since 2004 and is considered closed by WNISR.

As of the end of 2022, the PRIS database still counted 17 Japanese reactors as “in Operation”. Whereas ten had effectively restarted since the beginning of the Fukushima disaster (also referred to as 3/11), the remaining seven had not produced any electricity since 2010–2012. Then, in April 2023, those seven units also joined the “Suspended Operation” category, followed by three additional Indian reactors in May 2023, that have not produced power since 2018 (Madras-1) and 2020 (Tarapur-1 & -2).

The definition of the new category is as follows:

A reactor is considered in the suspended operations status, if it has been shut down for an extended period (usually more than one year) and there is the intention to re-start the unit but:

1. restart is not being aggressively pursued (there is no vigorous onsite activity to restart the unit) or

2. no firm restart date or recovery schedule has been established when unit was shutdown [shut down].

Suspended operations may be due to [due to] technical, economical, strategic or political reasons. This status does not apply to long-term maintenance outages, including unit refurbishment, if the outage schedule is consistently followed, or to long-term outages due to regulatory restrictions (licence suspension), if restart (licence recovery) term and conditions have been established. Such units are still considered “operational” (in a long-term outage). If an intention not to restart the shutdown unit has been officially announced by the owner, the unit is considered “permanently shutdown [shut down]”.34

It is important to understand that the application of this new rule modifies retroactively all of the IAEA’s statistics on operating reactors—in most cases as of day of last production—back to 2007. This dramatically modifies the IAEA’s representation of the Japanese nuclear reactor fleet’s evolution. The changes obviously also impact the IAEA’s representation of the long-term evolution of the entire global nuclear power-reactor fleet (see a detailed discussion in WNISR2023).

The differences with WNISR statistics are greatly reduced, and the remaining ones mostly relate to official closure dates, as WNISR statistics consider the end of electricity production as reference for dating closures, and not the “announcement” or “political decision” to permanently withdraw a reactor from the grid.

IAEA vs. WNISR Assessment

WNISR’s assessment of “operating” reactors has shown significant differences with IAEA statistics since the beginning of the Fukushima disaster in 2011. However, after major changes in the PRIS statistics (see above), those differences were reduced to minor disparities during the period September 2022 to May 2023.

The following section provides a detailed explanation and justification of the differences.

Figure 7 presents the evolution of the number and capacity of the world reactor fleet “in operation” as reported by the IAEA vs. WNISR.

As of July 2024, the evolution of the world nuclear fleet in the IAEA-PRIS statistics shows a peak of 440 reactors operating in 2005, whereas the operating capacity reached 374.7 GW, marginally over the previous peak of 374 GW reached in 2018; as of the end of 2023, the operating capacity was 371.5 GW.

In the WNISR statistics, which consider reactors closed from the day they stop producing electricity, and systematically apply the LTO status to reactors not operating for a certain period, a maximum number of 438 operating reactors was reached as soon as 2002, and again in 2005. At the end of 2023, with a balance of minus 1 GW between closed and newly started-up reactors and a balance of three additional reactors in LTO, the operating capacity stayed at 364.7 GW below the previous peak of 367.1 GW in 2006 but in July 2024, with 367.3 GW, just exceeded the previous record.

1. World Nuclear Reactor Fleet – IAEA vs WNISR, 1954–July 2024

Sources: IAEA-PRIS and WNISR, 2024

Notes: The IAEA data used for this graph includes at least three reactors that have been later withdrawn from the PRIS statistics for operating reactors (Niederaichbach, VAK-Kahl and HDR Großwelzheim, in Germany, now only appearing as “Decommissioning Completed”). On the other hand, the Swiss research reactor in Lucens is not included. Reactors classified as in “Suspended Operation” by the IAEA are not represented here.
Although the total number of reactors in operation according to WNISR statistics has always remained, albeit slightly, inferior to IAEA-PRIS data, it contains Chinese reactors not accounted for in PRIS (see below).

Although not the only case, the Japanese fleet still provides the main and most visible differences between the two datasets, especially over the past decade. This applies both to reactors that did not produce electricity for many years before they returned to service (designated as “LTO later restarted” or “Restarted from LTO”), or which were declared permanently closed years after they stopped producing electricity (“Closed at a later date”).

Applying this definition to the world nuclear reactor fleet, as of 1 July 2024, leads to classifying nine units considered “in operation” by the IAEA as in LTO:

• Darlington-1, under refurbishment since February 2022 (see Canada in Annex 1).
• Kori-2 in South Korea, shut down in April 2023, after 40 years of operation, expected to be restarted at an unknown date, and therefore considered in LTO (see South Korea Focus).
• Rajasthan-3 in India, shut down for repairs since October 2022 (see India in Annex 1).35
• The six reactors at Zaporizhzhia in Ukraine that did not produce any electricity in 2023, and are considered in LTO as of the end of 2022.

But on the other hand, WNISR statistics do include additional reactors in China:

• Shidao-Bay-1: The IAEA considers the two 100-MW modules as one reactor as they drive a single 200-MW turbine. WNISR considers that each module is a separate reactor.
• China Experimental Fast Reactor (CEFR): The IAEA has simply deleted the file for the reactor without any indication of reasons. Chinese sources have argued it should have never been in the IAEA’s PRIS database in the first place as it is to be considered an experimental reactor. However, as this is a nuclear power reactor, it is considered as such by WNISR. Its current operational status is uncertain. In the absence of operational data, WNISR considers it in LTO as of May 2023 (but still operating as of December 2022).36

The biggest difference between IAEA-PRIS and WNISR is found as of the end of 2012, with 29 units less operating according to WNISR criteria: the IAEA-PRIS counts 30 reactors (detailed in Table 1) that are not considered operating according to WNISR, but on the other hand has retrieved the Chinese CEFR it previously considered operational at this date.

1. WNISR Rationale for the Classification of 30 Reactors as Non-Operational as of end 2012

   Countries	Officially Closed at a Later Date 21 Reactors		Restarted from LTO 9 Reactors
   	Reactors that last produced electricity in (or prior to) 2012, officially closed after 2012 (either considered closed by WNISR as early as 2012, or after a certain period in LTO). Most of those reactors were considered “in operation” for many years before their official closure date.		Reactors in LTO as of December 2012 Restarted prior to 1 July 2023
   	Reactors considered closed in 2012	Reactors in LTO prior to closure
   Japan	6 Reactors Fukushima Daiichi 5–6 Fukushima Daini 1–4 Officially Closed in 2013 and 2019	11 Reactors Last production in 2010–2012 Officially closed 2015–2019	8 Reactors Restarted 2015–2021
   South Korea			1 Reactor Wolsong-1, Restarted in 2015
   Spain	1 Reactor Santa Maria de Garoña Last production in 2012 Officially Closed in 2017*
   U.S.	3 Reactors San Onofre-2 & -3 Last production in 2012 Officially closed in 2013 Crystal River-3 Last production in 2009 Officially closed in 2013

Sources: IAEA-PRIS and WNISR, 2024

Note: *Garoña was subsequently considered in “Suspended Operation” during 2013–2016 by the IAEA until its official closure.

The differences between the IAEA and WNISR are not limited to the effects of the Fukushima disaster. Even prior to 3/11, WNISR and IAEA-PRIS data had differences, reaching up to 10 units at the end of some years. These differences were mainly due to the definition of the closure date that the IAEA either sets at last production or at closure-decision date while WNISR systematically applies the day of last electricity generation (when available). Another reason for differences lies in the IAEA’s delays to classify reactors in “suspended operation”.

Overview of Current NewBuild

As of 1 July 2024, 59 reactors were considered as under construction—including 27 units in China—one more than the WNISR reported a year ago and 10 fewer than in 2013 (see Figure 9). Of the 69 reactors under construction at the end of 2013, five projects have subsequently been abandoned or suspended.

Eighty-five percent of the reactors are being built in Asia or Eastern Europe (see Building vs. Vendor Countries). In total, 13 countries are building nuclear plants, with the UAE and U.S. having started up their last units under construction, and work was suspended (again) on a reactor in Brazil, that is three countries less building than as of mid-2023.

However, only three countries—China, India, and Russia—have construction ongoing at more than one site, and five countries only have a single reactor under construction (see Table 2 and Annex 5 for details). Between mid-2023 and mid-2024, construction of seven units was launched worldwide, five in China and one each in Egypt and Russia.

The 59 reactors that are listed as under construction by mid-2024 represent a quarter of the 234 units—totaling more than 200 GW—listed in 1979. However, 48 of those projects listed at the time were never finished (see Figure 8). The year 2005, with 26 units listed as under construction, was the lowest since the early nuclear age in the 1950s.

1. Nuclear Reactors “Under Construction” in the World

Sources: WNISR, with IAEA-PRIS, 2024

Notes: This figure includes construction of two CAP1400 reactors at Rongcheng/Shidaowan, although their construction has not been officially announced (see China Focus). This figure considers the Ohma project in Japan as suspended, as it remains unclear whether active construction has resumed.

Compared to the year before, the total capacity of the 59 units under construction in the world in mid-2024 increased by 1.2 GW to 59.8 GW, with an average unit size of 1 GW.

1. Nuclear Reactors “Under Construction” – China and the World

Sources: WNISR, with IAEA-PRIS, 2024

Building vs. Vendor Countries

As of mid-2024, China has by far the most reactors under construction in the world. However, it is currently not building anywhere outside the country and, so far, has only exported to Pakistan. Although the official construction start of a barge which China is building for a Russian client occurred in China, it is considered a Russian domestic project as installation of the two “floating reactors” will be carried out in Russia where they will operate.

Russia is in fact largely dominating the international market as a technology supplier with 26 units under construction in the world, as of mid-2024, of which only six are domestic and 20 in seven different countries, including four each in China, Egypt, India, and Türkiye, two in Bangladesh and one each in Iran and Slovakia (Russian design, completed by Czech-led consortium). It is uncertain to what extent these projects are impacted by the various layers of sanctions imposed on Russia following its invasion of Ukraine.

Besides Russia’s Rosatom, there is only France’s EDF presently building abroad (see Table 2 and Figure 10).

1. Nuclear Reactors “Under Construction” (as of 1 July 2024)37

Sources: Various, Compiled by WNISR, 2024

Notes:

(a) - Of the seven reactor projects under construction, all are delayed or likely to be delayed, with all Kudankulam reactors under construction “likely to be impacted” by the war in Ukraine. Five is the number of reactors “formally” delayed. See India (in Annex 1) and Annex 5.

(b) - Mochovce -4 is a Russian VVER design being completed by a Czech-led consortium.

This table does not contain suspended or abandoned constructions. It does include construction of two CAP1400 reactors at Rongcheng/Shidaowan, although that has not been officially announced (see China Focus) as well as two floating reactors of Russian design to be deployed in Russia—thus counted under Country-Russia, but with a barge built in China.

1. Nuclear Reactors “Under Construction” by Technology-Supplier Country

Sources: WNISR, with IAEA-PRIS, 2024

Construction Times

Construction Times of Reactors Currently Under Construction

A closer look at projects listed as “under construction” as of 1 July 2024 illustrates the level of uncertainty and problems associated with many of these projects, especially given that most builders still claim a five-year construction period in their project proposals:

• For the 59 reactors being built, an average of 5.9 years has passed since construction start—slightly lower than the mid-2023 average of 6 years—and many remain far from completion.
• All reactors under construction in at least nine countries—of which five have only one unit in work—of the 13 builder-countries have experienced often year-long delays. Almost forty percent (23) of the building projects are documented to be delayed. Most of the units which are nominally being built on-time (yet)—23 of the 36 are in China—were begun within the past three years, making it difficult to assess whether they are on schedule. Significant uncertainty remains over construction in China because of lack of access to information.
• It remains also unclear what will happen with Russian designed and/or implemented projects in six other countries, as sanctions have or will likely have an impact on supply chains. Russian projects in five of the seven countries are already documented to be delayed (Bangladesh, India, Iran, Slovakia, Türkiye).
• Of the 23 constructions clearly documented as behind schedule, at least ten—in Argentina, Bangladesh, France, India, Iran, Slovakia, South Korea, and the U.K.—have reported increased delays, and two have reported a delay for the first time over the past year.
• WNISR2022 noted a total of 12 reactors scheduled for startup in 2023. At the beginning of 2023, nine were still planned to be connected to the grid (including three pushed back from 2022 to 2023) but only five of these made it to generate first power, while the other four were delayed at least into 2024.
• The initial construction start of the Mochovce-4 reactor in Slovakia dates back 39 years and its grid connection has been further delayed, currently to 2025. Bushehr-2 in Iran originally started construction in 1976, over 48 years ago, and resumed construction in 2019 after a 40-year-long suspension. Grid connection is currently scheduled for 2028.
• Six additional reactors have been listed as “under construction” for a decade or more: the Prototype Fast Breeder Reactor (PFBR) and Rajasthan-7 & -8 in India, Shimane-3 in Japan, Flamanville-3 (FL3) in France and CAREM in Argentina38. Angra-3 construction, which initially started in 2010, was halted in 2015, apparently resumed in 2022, with an expected startup date of 2028. However, construction activities have been interrupted again in 2023 and WNISR considers the project currently as suspended.

The actual lead time for nuclear plant projects includes not only the construction itself but, in most countries, also lengthy political and legal processes, licensing procedures, complex financing negotiations, site preparation, and other infrastructure development.

Construction Times of Past and Currently Operating Reactors

Since the beginning of the nuclear power age, there has been a clear global trend towards increasing construction times. National building programs were faster in the early years of nuclear power, when units were smaller, and safety and environmental regulations were less stringent. As Figure 11 illustrates, average times between construction start and grid connection of reactors completed in the 1970s and 1980s were quite homogenous, while in the past two decades they have varied widely.

As Figure 12 shows for the period 2021–2023, the longest construction time was for Mochovce-3, even taking into account the suspension construction (38 years in total, of which over 16 years of suspension), followed by the Olkiluoto-3 (OL3) reactor (16.6 years), a Franco-German project, the first European Pressurized Water Reactor (EPR) to start up in Europe, twelve years later than planned. The longest construction times in China were seen for the two HTR modules at Shidao Bay (between 9 and 10 years). The seven units completed in 2021–2023 in China took on average 7.1 years to build.

1. Average Annual Construction Times in the World

Sources: WNISR, with IAEA-PRIS, 2024

The mean time from construction start to grid connection for the five reactors started up in 2023 was 14.9 years, almost six years more on average than construction times of units started up in 2022 (9 years). This includes Mochovce-3 in Slovakia, with construction starting first in 1985.

Four units began power generation in the first half of 2024 in a diverse selection of countries including China, India, UAE, and the U.S., after an average time between construction start to grid connection of 9.9 years.

Over the three years 2021–2023, only one of 18 units connected to the grid in nine countries started up on-time, the Chinese-designed and -built CNP-1000 Tianwan-6.39 The average duration between construction start and first grid connection of these 18 units was 10.1 years (see Figure 12).

The longer-term perspective confirms that short construction times remain the exceptions. Eleven countries completed 67 reactors over the decade 2014–2023—of which 37 in China alone—with an average construction time of 9.9 years (see Table 3), higher than the 9.4 years of mean construction time in the decade 2013–2022. The construction durations from the beginning of concreting of the foundations of the reactor building to first grid connection have been stable around 10 years for over a decade with a broad range between countries and between projects inside individual countries as can be seen in Table 3.

1. Delays for Units Started Up, 2021–2023

Sources: Various, Compiled by WNISR, 2024

Notes: Expected construction time is based on grid connection data provided at construction start when available; alternatively, best estimates are used, based on commercial operation, completion, or commissioning information.

At Shidao Bay, the HTR plant, where construction started in 2012, has two reactor modules on the site and is therefore counted as two units as of WNISR2020. Grid connection of the first unit of the twin reactors officially took place on 20 December 2021. No date was provided for startup of the second reactor, which is considered as operating in WNISR2023 as of end-2022, and total construction time set at 10 years.

1. Duration from Construction Start to Grid Connection, 2014–2023

Construction Times of 67 Units Started Up 2014–2023
Country	Units	Construction Time (in Years)
		Mean Time	Minimum	Maximum
China	37	6.3	4.1	10.0
Russia	9	17.9	8.1	35.1
South Korea	5	8.7	6.4	10.5
Pakistan	4	5.6	5.5	5.8
UAE	3	8.1	8.0	8.3
Belarus	2	8.0	7.0	8.9
India	2	12.2	10.1	14.2
U.S.	2	26.5	10.1	42.8
Argentina	1	33.0	33.0
Finland	1	16.6	16.6
Slovakia	1	38.1	38.1
World	67	9.9	4.1	42.8

Sources: WNISR, with IAEA-PRIS, 2024

Construction Starts and Cancellations

The number of annual construction starts40 in the world peaked in 1976 at 44, of which 11 projects were later abandoned. In 2010, there were 15 construction starts—including 10 in China—the highest level since 1985 (see Figure 13 and Figure 14). That number dropped to five in 2020 (including four in China), while building started on ten units in 2021 (including six in China), as well as in 2022 (including five in China). Six constructions started in 2023, of which five in China and one in Egypt implemented by the Russian nuclear industry.

Four reactors got underway in the world in the first half of 2024, two of them in China, one in Russia, and one built by the Russian industry in Egypt. Chinese and Russian government-owned or -controlled companies launched all 35 reactor constructions in the world over the 54-month period from the beginning of 2020 to mid-2024.

1. Construction Starts in the World

Sources: WNISR, with IAEA-PRIS, 2024

Notes: Construction of Bushehr-2 in Iran started in 1976, was considered abandoned in earlier versions of this figure. As construction was restarted in 2019, it now appears as “Under Construction”. Albeit of uncertain future, construction of Angra-3 in Brazil (2010) was considered restarted in WNISR2023, but construction has been suspended again.

Over the decade 2014–2023, construction began on 61 reactors in the world, of which over half (33) in China. As of mid-2024, 13 of those units had started up, while 48 remain under construction.

Seriously affected by the Fukushima events, China did not start any construction in 2011 and 2014 and began work only on eight units in total in 2012 and 2013. While Chinese utilities started building six more units in 2015, the number shrank to two in 2016, only a demonstration fast reactor in 2017, none in 2018, but four each in 2019 and 2020, six in 2021, five each in 2022 and 2023 and two in the first half of 2024 (see Figure 14). While this increase represents a sign of the restart of commercial reactor building in China, the level continues to remain below expectations. The five-year plan 2016–2020 had fixed a target of 58 GW operating and 30 GW under construction by 2020. As of the end of 2020, China had 49 units with 47.5 GW operating, one reactor in LTO (CEFR), and 17 units (16 GW) under construction, much lower than the original target. At the end of 2023, 56 reactors with a total capacity of 53.1 GW were operating and 26 units (27.7 GW) were under construction (for details, see China Focus).

1. Construction Starts in the World/China

Sources: WNISR, with IAEA-PRIS, 2024

Experience shows that having an order for a reactor, or even having a nuclear plant at an advanced stage of construction, is no guarantee of ultimate grid connection and power production. The two V.C. Summer units in the U.S., abandoned in July 2017 after four years of construction and following multi-billion-dollar investment, are only the latest in a long list of failed significantly advanced nuclear power plant projects.

French Alternative Energies & Atomic Energy Commission (CEA) statistics through 2002 indicate 253 “cancelled orders” in 31 countries, many of them at an advanced construction stage (see also Figure 15). The United States alone accounted for 138 of these order cancellations.41

1. Cancelled or Suspended Reactor Constructions

Sources: Various, compiled by WNISR, 2024

Note: This graph only includes constructions that had officially started with the concreting of the base slab of the reactor building. Many more projects have been cancelled at earlier stages of construction/site preparation.

Of the 807 reactor constructions launched since 1951, at least 93 units in 19 countries had been abandoned or suspended, as of 1 July 2024. This means that 11.5 percent—or one in nine—of nuclear constructions have been abandoned.

Close to three-quarters (66 units) of all cancelled projects were in four countries alone—the U.S. (42), Russia (12), Germany and Ukraine (six each). Some units were 100-percent completed—including Kalkar in Germany and Zwentendorf in Austria—before it was decided not to operate them.

Operating Age

In the absence of significant, successful newbuild over many years, the average age (from grid connection) of operating nuclear power plants has been increasing since 1984, and as of mid-2024 is 32, up from 31.4 years in mid-2023 (see Figure 16).42

A total of 269 reactors—four more than mid-2023—two-thirds of the world’s operating fleet, have operated for 31 or more years, including 127—almost one in three—for at least 41 years.

1. Age Distribution of Operating Reactors in the World

Sources: WNISR, with IAEA-PRIS, 2024

In 1990, the average age of the operating reactors in the world was 11.3 years; in 2000, it was 18.8 years, and it stood at 26.3 years in 2010. The leading nuclear nation also has the oldest reactor fleet of the top-five nuclear generators. The average age of reactors in the U.S. passed 40-years in 2020 and reached 42.6 years as of the end of 2023. France’s fleet exceeded 38.5 years. Russia’s fleet age peaked in 2017 and declined for a few years before increasing again starting in 2020, and its average fleet age of 30.4 years, as of the end of 2023, almost caught up with that of 2017. South Korea’s reactors at 22.7 years remained almost half as old as the U.S. fleet, and China had an average fleet age of just 10 years. (See Figure 17).

1. Reactor-Fleet Age of Top 5 Nuclear Generators

Sources: WNISR, with IAEA-PRIS, 2024

Many nuclear utilities envisage average reactor lifetimes of beyond 40 years up to 60 and even 80 years. In the U.S., reactors are initially licensed to operate for 40 years, but nuclear operators can request a license renewal from the Nuclear Regulatory Commission (NRC) for an additional 20 years. An initiative to allow for 40-year license extensions in one step was terminated in June 2021 after NRC staff recommended that the Commission “discontinue the activity to consider regulatory and other changes to enable license renewal for 40 years.”43

As of mid-2024, 84 of the 94 operating U.S. units had received a 20-year license extension, applications for six further reactors were under NRC review. The Initial License Renewal application for the Diablo Canyon units, scheduled to close when their current licenses expire in 2024–2025, is under review.44

As of July 2024, the NRC had granted Subsequent Renewed Operating Licenses to six reactors, which permit operation from 60 to 80 years. A further sixteen reactors have their applications still under review, and owners have notified of their intentions to submit applications for a further 29 reactors between 2025 and 2034. See Extended Reactor Licenses in United States Focus for details and references.

Only nine of the 41 units that have been closed in the U.S. had reached 40 years on the grid. All nine had obtained licenses to operate up to 60 years but were closed long before mainly for economic reasons. In other words, almost one quarter of the 136 reactors connected to the grid in the U.S. never reached their initial design lifetime of 40 years. Only one of those already closed had just reached 50 years of operation (Palisades, closed after 50.4 years). The mean age at closure of those 41 units was 22.8 years.

On the other hand, of the 94 currently operating plants, 54 units have already operated for 41 years or more, of which 15 have been on the grid for 51 years or more; thus, almost two thirds of the units with license renewals have entered the lifetime extension period, and that share is growing rapidly with the mid-2024 mean age of the U.S. operational fleet exceeding 42.7 years (see Figure 47).

Many countries have no specific time limits on operating licenses. In France, for example, reactors must undergo in-depth inspection and testing every decade against reinforced safety requirements. The French reactors have operated for 39 years on average. The Nuclear Safety Authority (ASN) has evaluated each reactor, and most have been permitted to operate for up to 40 years, which is considered the limit of their initial design. For economic reasons, the French state-controlled utility Électricité de France (EDF) prioritizes lifetime extension to at least 50 years over large-scale new-build. ASN’s fourth decennial assessments are years behind schedule.

EDF’s approach to lifetime extension has been reviewed by ASN and its Technical Support Organization. In February 2021, ASN granted a conditional generic agreement to lifetime extensions of the 32 reactors of the 900-MW series. However, lifetime extensions beyond 40 years require reactor-specific licensing procedures involving public inquiries in France and transborder consultations. For an assessment of the status of fourth decennial inspections see France Focus: Lifetime Extension – Fact Before License in WNISR2023.

Recently commissioned reactors and the ones under construction—including in France, South Korea, and the U.K.—have or will seek a 60-year operating license from the start.

1. Age of World Nuclear Fleets

Sources: WNISR, with IAEA-PRIS, 2024

Note: This figure only takes into account reactors operating as of 1 July 2024, thus excluding reactors in LTO, in particular Tarapur-1 & -2 in India, that have passed 50 years.

Figure 18 shows that the average fleet age in 23 of the 32 countries that operate nuclear reactors as of mid-2024 is over 30 years, and in eight countries over 40. Two in three, that is 21 of the countries have been operating one or more reactors for more than 40 years, but, as of mid-2024, only seven countries operate reactors that are over 50 years.

In assessing the likelihood of reactor fleets being able to operate for 50 or 60 years, it is useful to compare the age distribution of reactors that are currently operating with the 213 units that have already closed (see Figure 16 and Figure 19). In total, 98 of these units operated for 31 years or more, of which 42 reactors operated for 41 years or more. Many units of the first-generation designs only operated for a few years. The mean age of the closed units is about 28 years.

1. Age Distribution of Closed Nuclear Power Reactors

Sources: WNISR, with IAEA-PRIS, 2024

While the operating time prior to closure has clearly increased continuously, the mean age at closure of the 29 units taken off the grids in the five-year period between 2019 and 2023 was 42.8 years (see Figure 20).

As a result of the Fukushima nuclear disaster (elsewhere also referred to as 3/11), many analysts have questioned the wisdom of operating older reactors. The Fukushima Daiichi units (1 to 4) were connected to the grid between 1971 and 1974. The license for Unit 1 had been extended for another 10 years in February 2011, just one month before the catastrophe began. Four days after the initial events in Japan, the German Government ordered the closure of eight reactors that had started up before 1981, two of which were already closed at the time and never restarted. The sole selection criterion was operational age—30 years or more. Other countries did not adopt the same approach, but clearly the 3/11 events in Japan had an impact on previously assumed extended lifetimes in other countries. Some of the main nuclear countries closed their oldest units, at the time, before or long before age 50, including Germany at age 37, South Korea at 40, Sweden at 46. France closed its two oldest units in spring 2020 at age 43. The U.S. closed its oldest unit, Palisades, at age 50 in 2022, but is now considering reopening it.

1. Nuclear Reactor Closure Age

Sources: WNISR, with IAEA-PRIS, 2024

Lifetime Projections

Nuclear operators in many countries continue to implement or prepare for lifetime extensions. As in previous years, WNISR has created two lifetime projections. A first scenario (40-Year Lifetime Projection, see Figure 21), assumes a general lifetime of 40 years for worldwide operating reactors—not including reactors in Long-Term Outage (LTO).

Forty years, explicitly or implicitly, corresponds to the design lifetimes of most operating reactors. Some countries have legislation or policy in place—including Belgium (even if the currently debated lifetime extension for two units was implemented), or Taiwan—that limit operating lifetime, for all or part of the fleet, to 40 or 50 years. Recent designs, mostly reactors under construction, have often a design lifetime of 60 years (e.g. APR-1400, EPR). For the 136 reactors that have passed the 40-year lifetime as of end-2023, we assume they will operate to the end of their licensed, extended operating time.

A second scenario (Plant Life Extension or PLEX Projection, see Figure 22) takes into account all already-authorized lifetime extensions as of mid-2024 and assumes that the respective reactors will operate until the expiration of their license—a very conservative assumption considering empirical evidence from the past.

The lifetime projections allow for an evaluation of the number of reactors and respective power generating capacity that would have to come online over the next decades to offset closures and simply maintain the same number of operating reactors and level of capacity, if all units were closed after a lifetime of 40 years (60 years for the very few units that hold such initial licenses) or after their licensed lifetime extension.

Considering all units under construction scheduled to have started up, 26 additional reactors would have to be commissioned or restarted prior to the end of 2024 to maintain the status quo of operating units (compared to the end of 2023 status). Without additional startups, installed nuclear capacity would decrease by 19 GW by the end of 2024.

1. The 40-Year Lifetime Projection

Sources: Various sources, compiled by WNISR, 2024

Notes pertaining to Figure 21, Figure 22 and Figure 23:

Those figures include two Chinese 1400 MW-units at Shidao Bay and two Russian 55 MW RITM reactors, for which the startup dates were arbitrarily set to 2024 and 2027, as there are no official dates.

Restarts or closures amongst the 34 reactors in LTO as of 1 July 2024 are not represented in Figure 21 and Figure 22; however, at least some are expected to be restarted (and later closed, after 2050 in some cases)

In the case of reactors that have reached 40 years of operation prior to 2024, the 40-year projection also uses the end of their licensed lifetime. (including 80 years for 6 reactors in the U.S, where the Subsequent License Renewal Applications have been approved for a further 20 years of operation, despite the fact that their new expiration dates will be incorporated when NRC adopts the new Generic Environmental Impact Statement (GEIS) for license renewal.) See United States Focus.

In the case of French reactors that have reached 40 years of operation prior to 2024 (startup before 1984), we use the deadline for their 4th periodic safety review (visite décennale) as closing date in the 40-year projection. In case this deadline is or will be passed by the end of 2024, we use a 10-year extension, although no licensing procedure has yet been completed for this extension besides Tricastin-1. For all those that have already passed their 3rd periodic safety review, the scheduled date of their 4th periodic safety review is used in the PLEX projection, regardless of their startup date.

In total, over the period 2024–2030, in addition to the units currently under construction, 124 new reactors (104.5 GW)—over 18 units or 15 GW per year—would have to be connected to the grid to maintain the status quo, almost three times the rate achieved over the past decade (67 startups between 2014 and 2023, that is 6.7 units or 6.7 GW per year).

The relative stabilization of the situation by the end of 2024 is only possible because most reactors will not actually close, regardless of their age. The number of reactors in operation will probably more or less continue to stagnate in spite of lifetime extensions becoming the rule worldwide. Such generalized lifetime extensions—far beyond 40 years—are clearly the objective of the international nuclear power industry, and, especially in the U.S., there are numerous, increasingly successful attempts to obtain subsidies for uneconomic nuclear plants in order to keep them on the grid (see Subsidies and Financing for Nuclear Power in United States Focus).

Developments in Asia, including in China, do not fundamentally change the global picture. Reported ambitions for China’s targets for installed nuclear capacity have fluctuated in the past. While construction starts have picked up speed again since 2021, Chinese medium-term ambitions appear significantly lower than anticipated in the pre-3/11 era.45

1. The PLEX Projection (not including LTOs)

Sources: Various sources, compiled by WNISR, 2024

Notes: see Figure 21.

Every year, WNISR also models a scenario in which all currently licensed lifetime extensions and license renewals are maintained, and all construction sites are completed. For all other units, a 40-year lifetime projection is maintained, unless a firm later closure date has been authorized. By the end of 2024, the net number of operating reactors would remain almost stable but the operating capacity would increase (-1 unit /+4.8 GW).

In the remaining years to 2030, the net balance would turn negative in 2025, slightly positive for the year 2026, stable in 2027, and would decrease sharply during 2028–2030; overall, over the period 2024–2030, an additional 65 new reactors (43 GW) would have to start up or restart to replace closures. Taking into account the already licensed lifetime extensions, the PLEX-Projection still reveals for the remaining years to 2030 a need to almost triple the annual startup rate of the past decade from 6.7 to 18 units (see Figure 21, Figure 22 and the cumulated effect in Figure 23) only to maintain the status quo. However, probably at least a third of the 126 reactors projected to close between 2024 and 2030 are likely to secure a lifetime extension beyond 2030.

However, as documented in detail above, construction starts have not been picking up over the past decade. Between 2020 and mid-2024, a total of 35 constructions were launched around the world, of which 22 in China and 13 implemented by the Russian industry, thus an average of 7.8 units per year were launched. Based on empirical evidence, it is unlikely that any substantial number of reactors will come online by 2030 that are not yet under construction. In other words, newbuild will not be sufficient, only further lifetime extensions will allow for the world nuclear fleet not to decline by 2030 and after.

1. Forty-Year Lifetime Projection versus PLEX Projection

Sources: Various, compiled by WNISR, 2024

Note: This figure illustrates the trends, and the projected composition of the current world nuclear fleet, taking into account existing reactors (operating and in LTO) and their closure dates (40-years Lifetime vs authorized Lifetime Extension) as well as the 59 reactors under construction as of 1 July 2024. The graph does not represent a forecasting of the world nuclear fleet over the next three decades as it does not speculate about future constructions.

This figure takes into account the restarts of Rajasthan-3 during the second half-year of 2024, as well as Darlington-1 expected in 2025.

Focus Countries

Belgium Focus

After a decade of ups and downs due to multiple technical issues and a record of 48 TWh in 2021, nuclear production dropped by 13 percent in 2022 to 41.7 TWh and another 25 percent in 2023 to 31.3 TWh partly due to the closure of two units in late 2022 and early (see Figure 24). The installed capacity, with negligeable changes in 30+ years, after a ramp-up period, delivered high levels of production for a period of 15 years, before generating erratic numbers of kilowatt-hours.

1. Nuclear Power Generation in Belgium vs. Installed Nuclear Capacity

Sources: Energy Institute and IAEA-PRIS, 2024

Nuclear plants contributed 41.2 percent to Belgium’s electricity generation in 2023, 5.2 percentage-points less than in 2022 which already saw a 4.4 percentage-point drop over 2021 (see Figure 25). The historic maximum nuclear share was 67.2 percent in 1986.

1. Nuclear Power Generation in Belgium vs. Nuclear Share

Source: Energy Institute, 2024

Until 2022, Belgium operated seven commercial pressurized water reactors (PWRs) at the Doel (4) and Tihange (3) sites. In the framework of the Belgian nuclear phaseout legislation, the nuclear operator closed Doel-3 on 23 September 2022 and Tihange-2 on 31 January 2023. The average age of the remaining Belgian five-reactor fleet is 45.2 years, the third oldest nuclear fleet in the world behind the Netherlands (1 reactor) and Switzerland (4 reactors). See Figure 18.

Belgium remains highly dependent on fossil fuels as contributions to final energy consumption in 2023 represented 48.1 percent for oil, 24.6 percent of natural gas (together 72.7 percent) with nuclear at 6.9 percent and renewables at 12.8 percent. There has been a major surge in installations of solar capacity in 2023 with a jump of 25 percent, so that solar and wind together cumulate 14.2 GW of capacity, representing over half of the total installed capacity in the country. Two thirds of the solar capacity is decentralized with system sizes below 30 kW.46

The gas-price increase in the fall of 2021 and the war in Ukraine have reopened the debate about the possibility of lifetime extension of the two most recent units, Tihange-3 and Doel-4. The government has introduced a corresponding preliminary legislative proposal on 1 April 2022. There is no debate about potential lifetime extensions of the remaining three of the seven Belgian reactors beyond the closure schedule specified by current law. Those three units are to be closed in 2025.

On 18 April 2024, the Belgian Parliament voted in favor of legislation that modifies the nuclear phaseout law from 31 January 2003, which originally required the closure of all of Belgium’s nuclear plants after 40 years of operation. Based on their startup dates, plants would have been closed progressively between 2015 and 2025 (see Table 4). Practically, however, after a first amendment to the law in 2015, lifetime extension to 50 years was granted for three reactors, five of the seven units would have gone offline in the single year of 2025.

The new law was promulgated on 26 April 2024 and published on 5 June 2024.47 It allows for the operation of Doel-4 and Tihange-3 “for a 10-year period from the restart date” it being understood that the reactors will be definitively closed at the end of this period or “at the latest on 31 December 2037.” The text is formulated this way as it is unclear at this time when the units will be able to restart after the end of their current licensing period which expires in 2025.

1. Belgian Nuclear Fleet (as of 1 July 2024)

Reactor	Net Capacity (MW)	Grid Connection	Operating Age (as of 1 July 2024)	End of License (Planned or Actual Closure Date)
Doel-1	433	28/08/1974	48.8	10-year lifetime extension to 15 February 2025
Doel-2	433	21/08/1975	47.9	10-year lifetime extension to 1 December 2025
Doel-3	1 006	23/06/1982		1 October 2022 (Closed on 23 September 2022)
Doel-4	1 038	08/04/1985	38.2	10-year lifetime extension? (Closure date 2035–2037)
Tihange-1	962	07/03/1975	48.3	10-year lifetime extension to 1 October 2025
Tihange-2	1 008	13/10/1982		1 February 2023 (Closed on 31 January 2023
Tihange-3	1 038	15/06/1985	38.0	10-year lifetime extension? (Closure date 2035–2037)

Sources: Various, compiled by WNISR, with Belgian Laws of 28 June 201548 and 26 April 202449.

Lifetime Extension of Doel-4 and Tihange-3?

Operator Electrabel, a subsidiary of French energy group Engie, had previously signaled that it was interested in extending the lifetime of two or three units beyond 2025 but warned that it would need legislation to be adapted by the end of the year 2020.50 This did not happen and Engie decided “to stop preparation works that would allow for the 20-year extension of two nuclear units beyond 2025.”51

In July 2022, the Belgian Government inquired whether Tihange-2, slated for closure on 1 February 2023, could be kept operating until the end of March 2023. Engie stated that a lifetime extension of Tihange-2 “had never been on the table” and that on such short notice, without any preparatory work having been done, “it is not possible due to both technical and nuclear safety constraints.”52 In another reported statement Engie explained that any lifetime extension of Tihange-2 was “not an option” and pointed out that “taking into account the concrete situation, considering such a scenario in haste, without the necessary preliminary studies having been carried out, is not possible with regard to the imperatives of nuclear safety (...)”53 Accordingly, Tihange-2 was closed on 31 January 2023.

In January 2022, the Federal Agency for Nuclear Control (FANC) issued a report commissioned by the government concluding a lifetime extension “would be possible from a nuclear safety point of view but only if the facilities were updated.”54

On 9 January 2023, the government—represented by the Prime Minister and the Energy Minister (Green Party)—jointly announced the signature of a Heads of Terms and Commencement of LTO [Long-Term Operation] Studies Agreement with Engie, stating that

This agreement in principle constitutes an important step, and paves the way for the conclusion of full agreements in the upcoming months. It also provides for the immediate start of environmental and technical studies prior to obtaining the authorizations related to this extension. (…)

With this agreement, both parties confirm their objective to make reasonable endeavours to restart the Doel 4 and Tihange 3 nuclear units in November 2026.55

Green-Party Co-President Rajae Maouane commented: “I’m part of this new generation of environmentalists for whom nuclear power is no longer a taboo.”56

Between 20 March and 20 June 2023, the Belgian Government held a transboundary public consultation on the basis of the “Environmental Impact Assessment in the context of postponing the deactivation of the Doel 4 and Tihange 3 nuclear power plants.”57

According to Engie, the intermediate agreement signed with the Belgian Government on 29 June 2023, only nine days after the end of the public consultation, contained the following key points:58

• “The commitment from both parties to use their best efforts to restart the nuclear units of Doel 4 and Tihange 3 as early as November 2026, or, subject to the effective implementation of an announced relaxation of regulations, as early as November 2025, with the aim to strengthen the security of supply in Belgium.”
• The Doel-4 and Tihange-3 reactors will be co-owned in a 50-50 percent partnership.
• The remuneration will be based on a Contract for Difference model.
• Engie will pay a lump sum of €15 billion (US$202316 billion)59 for “the future costs of nuclear waste management” of all seven of Engie’s nuclear reactors in Belgium. The amount is to be paid in two instalments, one at closing in the first semester 2024 for intermediate- and high-level nuclear waste, and a second payment in 2026 for low-level waste.
• Electrabel has already ordered fuel and the nuclear regulator has determined the scope of inspections and work to be carried out for the operation of ten additional years.

Another “intermediate agreement” was signed on 21 July 202360 and was to be followed by the final, legally binding agreement by the end of October 2023. Provided the European Commission approved the contract, closure of the deal was expected in the first half of 2024.61

On 13 December 2023, just two months later than scheduled, Engie and the Belgian Government signed the final, legally binding agreement that, according to Engie, “endorses the key principles of the framework agreement signed on 21 July 2023.”62

Independent experts and the environmental movement have sharply criticized the agreement. Independent energy consultant Alex Polfliet lists as the “main critics”:

• deficiencies in the democratic process (with lack of consultation, including with the energy regulator);
• the abandoning of the ‘Polluter Pays Principle’ (with the €15 billion [US$16 billion] capping of decommissioning and waste management coverage);
• high costs (as taxpayer would cover almost half of lifetime-extension costs and guaranteed price that might be well over market prices);
• state aid cuts out other options (as Doel-4/Tihange-3 reactors would “run even during negative price hours” and that “while renewables will be stopped.”63

On 18 April 2024, the Belgian Parliament nevertheless voted not only to amend the 2003-nuclear phaseout legislation (see above) but also approved the following pieces of legislation:

• A law on the creation, organization and operation of a public institution whose purpose is to take over the financial responsibility for certain nuclear liabilities (called Hedera Law). Hedera is the public institution to be responsible for those capped liabilities linked to nuclear waste and spent fuel and manage the funds.64
• A law to guarantee security of supply in the energy sector and reforming the nuclear energy sector (called Phoenix Law).65
• A law on the creation, organization and operation of the administrative service with autonomous accounting (called BE-WATT Law). BE-WATT is to become the government’s shareholder in BE-NUC.66

BE-NUC, a company with equal shares for Engie’s subsidiary Electrabel, that remains the sole operator, and the Belgian state that would co-own the remaining two reactors and share the inherent commercial risks. So far, Electrabel held 89.807 percent of the plant ownership that will be shared now with the Belgian state with the remaining 10.193 percent remaining with Luminus, a 68.6 percent subsidiary of EDF-Belgium.

European Commission Opens Formal Procedure for Potential Violation of State Aid Regulations

On 21 June 2024, the Belgian Government officially notified the European Commission of the agreement with Engie concerning the support package of the lifetime extension plan for Doel-4 and Tihange-3. By letter dated 22 July 2024,67 the Commission informed the Belgian Government that it was launching a procedure according to Article 108, paragraph 2 of the Treaty on the Functioning of the European Union (TFEU).68 In a press statement, the Commission expressed its “doubts as to its compatibility with EU State aid rules” and has therefore decided to open an in-depth investigation. In particular, the Commission says it intends to further investigate:

• The necessity of the additional financial support mechanisms on top of the CfD [Contract for Difference], in particular the creation of the joint-venture and its financing, as well as of the operating cashflow guarantee and the €580 million [US$627 million] loan;
• The appropriateness of the CfD design and the combination of financial and structural arrangements as they may unduly relieve the beneficiaries from too big a share of the market and operational risks;
• The proportionality of the combination of financial and structural arrangements and of the €15 billion [US$16 billion] lumpsum;
• Compliance with relevant EU sectoral legislation, in particular concerning the design of the CfD mechanism; and
• The impact of the measure on the market in light of the CfD design and the selection and independence of the agent selling the nuclear electricity.69

The Commission considers that the CfD design, that provides a guaranteed remuneration for the two nuclear reactors, “might have an adverse effect on the functioning of the E.U. [electricity] market, contrary to the principles set out” in the E.U. regulations.70 An initial strike price shall be set in 2025 that takes into account the cost of upgrading required by the nuclear safety authority. In 2028, the strike price shall be updated and fixed for the rest of the operational period.

The term “risk” comes up on 55 of the 78-page letter, often several times on a given page. The Commission has listed technical and management risks, risks related to waste management and decommissioning, market and investment risks as well as regulatory and political risks. Engie’s strategy since 2020 was to withdraw from nuclear activities in Belgium and “de-risk its exposure as nuclear operator to market price volatility.”71 All studies into potential lifetime extension at Doel and Tihange were halted. Therefore, when the Belgian Government pushed the company to reopen the option:

Engie made it clear from the start that without a risk sharing mechanism and a solution for the costs of nuclear waste stemming from the operation of the seven nuclear power plants, it would not consider the lifetime extension of the two nuclear reactors, which forces Engie to substantially modify its company strategy and risk exposure.

The European Commission highlights in particular the “considerable” uncertainties regarding the final investment costs, as “the scope of the necessary investments will only become clear in a later stage,” once inspections and studies have been carried out and the upgrading work program has been approved by the safety authorities. The scope of work will determine how long the units will have to remain off-grid without generating income.

The letter states that:

the Commission does not have sufficient elements to conclude whether the conditions for the compatibility of any possible aid with the internal market (…) are met, in particular, whether the aid is necessary, appropriate and proportionate, does not violate Union law and does not affect competition in a way contrary to the common interest.

The Commission “wishes to remind Belgium that Article 108(3) TFEU has suspensory effect” and “that all unlawful aid may be recovered from the recipient.” The Commission “warns Belgium” that it will inform interested parties by publishing this letter in the Official Journal of the European Union. The Commission “requests Belgium to submit its comments and to provide all [...] information [...] to assess the measure” by 8 September 2024.

Nuclear Safety Authority Needs Yet to Approve Upgrading Program

On 20 July 2023, the Federal Agency for Nuclear Control (FANC) communicated its expectations to Engie Electrabel to allow for lifetime extensions beyond 2025. The regulator proposes to stagger upgrading work to 2028 to allow for the two reactors to be available during the winters 2025–2026 and 2026–2027. Engie Electrabel now has to come up with concrete proposals on how and by when to implement the requested upgrading work.72

As of mid-2024, FANC stated on its website, updated on 23 February 2024, that “AFCN expects Engie Electrabel’s complete file by the beginning of 2025, and will analyze and comment on it in depth within the following six months.”73

Many technical and legal challenges remain to be solved prior to the operation of Doel-4 and Tihange-3 beyond 2025. In February 2023, Engie has ruled out the lifetime extension of the three other remaining operating reactors Doel-1 and -2, and Tihange-1 calling the option “unthinkable”.74 In March 2023, FANC ruled out the prolongation option for the three units on safety grounds.75

Previous Lifetime Extensions

In summer 2012, the operator identified an unprecedented number of hydrogen-induced crack indications in the pressure vessels of Doel-3 and Tihange-2, with respectively over 8,000 and 2,000 previously undetected defects, which later increased to over 13,000 and over 3,000. In spite of widespread concerns, and although no failsafe explanation about the negative initial test results was given, on 17 November 2015, FANC authorized the restart of Doel-3 and Tihange-2 (see previous WNISR editions for details).

The Belgian Government did not wait for the outcome of the Doel-3/Tihange-2 issue and decided in March 2015 to draft legislation to extend the lifetime of Doel-1 and Doel-2 by ten years to 2025. The law went into effect on 6 July 2015. On 22 December 2015, FANC authorized the lifetime extension and restart of Doel-1 and -2.76

On 6 January 2016, two Belgian NGOs filed a complaint against the 28 June 2015 law with the Belgian Constitutional Court, arguing in particular that the lifetime extension had been authorized without a legally required public enquiry. Following a 22 June 2017 pre-ruling decision, the Court addressed a series of questions to the European Court of Justice (ECJ), in particular concerning the interpretation of the Espoo and Aarhus Conventions, as well as the European legislation.77

On 29 July 2019, the ECJ stated that the lifetime extension of a reactor

must be regarded as being of a comparable scale, in terms of risks of environmental impact, to the initial commissioning of those power stations. Consequently, it is mandatory for such a project to be the subject of an environmental impact assessment provided for by the EIA directive.78

In addition, as the Doel-1 and -2 reactors are particularly close to the Belgian-Dutch border, “such a project must also be subject to the transboundary assessment procedure.” The judgement permitted to delay the implementation of the order, if a national court considers it is

justified by overriding considerations relating to the need to exclude a genuine and serious threat of interruption to the electricity supply in the Member State concerned, which cannot be addressed by other means or alternatives, inter alia in the context of the internal market. That maintenance may only last for the amount of time strictly necessary in order to remedy that illegality.79

On 5 March 2020, the Belgian Constitutional Court nullified the lifetime extension legislation in its entirety but gave the government until the end of 2022 “at the latest” to carry out an appropriate Environmental Impact Assessment (EIA) and a transboundary consultation.80

The Belgian Government argued that the lifetime extension “plays a vital role in securing its supply of electricity until 2025” and sent a notification for consultation to a number of European governments inviting them to comment on the “project” (that is the well engaged lifetime extension of Doel-1 and -2).81

The Belgian precedent has significant consequences on lifetime extension projects in European Union Member States that now all have to carry out full-scale EIAs and organize transboundary consultations prior to granting permission for lifetime extensions.

China Focus

As of mid-2024, China had 57 reactors in operation with a total capacity of around 54 GW. The count of 57 is higher than the IAEA’s count of 56 in its PRIS database because WNISR records the Shidao Bay project with twin High-Temperature Reactor Pebble-bed Modules (HTR-PM) as two 100-MW reactors. For unknown reasons, the China Experimental Fast Reactor (CEFR) is no longer mentioned in the PRIS database since May 2023, and has been placed in Long-Term Outage (LTO) as of this date in WNISR statistics.

Nuclear plants produced a record 406.5 TWh in 2023, an increase of 2.8 percent over the 395.4 TWh generated in 2022. The nuclear share was 4.9 percent of total electricity produced in 2023, marginally lower than the 5 percent recorded in 2022. In comparison, the 2024 edition of the Statistical Review of World Energy records nuclear power’s share of total electricity produced (gross) as 4.6 percent, again marginally lower than the 2022 figure of 4.7 percent.82 In late September 2023, the China Nuclear Energy Association has announced plans to expand nuclear power’s contribution to 10 percent of total electricity production by 2035 and about 18 percent by 2060.83 These targets, while still very ambitious, are down from those announced in 2020 in a joint policy advisory report by the China Nuclear Development Institute (CNDC) and China Electric Power Research Institute (Cepri), respectively part of the National Energy Administration and China State Grid Corp. According to their 2020-projections, nuclear capacity would grow to 131 GW in 2030 contributing 10 percent to the national power generation and to 169 GW by 2035 with 13.5 percent of the total generation mix.84

In the year to mid-2024, only one nuclear reactor has started operating: Fangchenggang-4, a 1000-MW Hualong One, became critical on 3 April 2024.85 The reactor was subsequently connected to the grid on 9 April 2024, and declared to be operating commercially on 25 May 2024. The reactor’s first pour of concrete was on 23 December 2016, which represents a construction period of a bit over 87 months.

It is interesting to assess the construction durations of the 58 units connected to the Chinese grid between 1991 and July 2024. The 42 reactors of Chinese or Sinicized design had an average construction time of 5.7 years with a range from 4.1 to 10 years with the smallest, the SMR-type High Temperature reactors, showing the longest construction times. It took on average respectively only 4.5 years for two Canadian CANDUs, but 6.6 years for six French units (4.8–9.2 years), 6.9 years for four Russian reactors (5–11.2 years), 8.6 years for two U.S. AP-1000s, and 9 years for two AP-1000 built by a U.S.-Japanese consortium (see Figure 26). It is remarkable that, just as other nuclear countries, China does not seem to reduce construction times but rather experiences an increasing trend. The reasons are unclear.

China has a further 27 reactors under construction, with a combined capacity of around 29 GW (see also Annex 5 – Nuclear Reactors in the World “Under Construction”):

• The two CAP1400 reactors, Shidao Bay 2-1 and Shidao Bay 2-2, (since 2019) which are not listed in the IAEA’s PRIS database.
• The five units that have started being constructed since WNISR2023 are: Lufeng-6, a Hualong One reactor (26 August 2023); Lianjiang-1 and -2, two 1224 MW CAP1000 reactors (27 September 2023 and 26 April 2024); Zhangzhou-3, a Hualong One reactor (22 February 2024); and Xudabu-1 (also called Xudapu or Xudabao), a CAP1000 reactor (3 November 2023).86
• Other (large) light water reactors being built, with details in earlier WNISR editions, are
  • since 2019: Taipingling-1 and Zhangzhou-1;
  • since 2020: Taipingling-2, Sanaocun-1, and Zhangzhou-2;
  • since 2021: Changjiang-3 and -4, Sanaocun-2, Tianwan-7, and Xudabu-3;
  • since 2022: Tianwan-8, Xudabu-4, Sanmen-3, Haiyang-3, and Lufeng-5;
  • since 2023: Haiyang-4, and Sanmen-4.
• The Xiapu two fast reactor units started being built on 29 December 2017 and 27 December 2021 respectively.87
• The SMR Changjiang (or Linglong-1) is under construction since 2021.88

1. Construction Times of Reactors Built in China

Sources: WNISR with IAEA-PRIS, 2024

In December 2023, the State Council approved building two 1200 MW Hualong One units that would constitute the first phase of the Jinqimen nuclear power plant in Ningbo, Zhejiang Province; the China National Nuclear Corporation (CNNC) broke ground at the site in February 2024.89 Earlier, in July 2023, the State Council approved Unit 5 and 6 of the Ningde plant in Fujian Province, Unit 1 and 2 of the Shidaowan plant in Shandong Province, and Unit 1 (now under construction) and 2 of the Xudabao plant in Liaoning Province.90

The Chinese reactor fleet is very young. Almost three quarters of all units have not reached 10 years of age (see Figure 27). Only one unit, the 300-MW Qinshan-1, is over 31 years old, and it is the only Chinese unit, at 32.5 years, slightly exceeding the average age of the world nuclear fleet of 32.1 years.

1. Age Distribution of the Chinese Nuclear Fleet

Sources: WNISR with IAEA-PRIS, 2024

Pakistan (see Pakistan in Annex 1) continues to be the only country to which China has been exporting nuclear reactors. Its plans to export a reactor to Argentina had earlier resulted in a February 2022 agreement signed by CNNC and Nucleoeléctrica Argentina SA (NA-SA) to build Atucha-3.91 But the project had reportedly “hit a stumbling block over finances” last year.92 (See Argentina in Annex 1.) Those problems have deepened with President Javier Milei coming to power in Argentina, and there is no clarity whether the project will eventually move forward.93 The fact that CNNC remains on the U.S. Government’s blacklist is not helping either.94

China continues to expand renewable energy very rapidly. Installed capacities of wind and solar energy in 2023 were 441.9 GW and 609.9 GW, up from 96.8 GW and 28.4 GW in 2014.95 The wind capacity includes 37.3 GW of offshore wind power, up from 0.4 GW in 2014. In the first five months of 2024, China has added around 79 GW of solar energy and 20 GW of wind power.96

According to the Energy Institute’s Statistical Review of World Energy, renewable sources (not including large hydropower) produced 17.6 percent of the total electricity in 2023 (up from 15.5 percent in 2022), nearly four times the contribution from nuclear power plants. Electricity produced by non-hydro renewable sources increased by 21.5 percent in 2023, compared to a 19.5 percent increase in 2022 (see also Case Study on China in Nuclear Power vs. Renewable Energy Deployment). Thanks to the massive installations of solar and wind energy, the share of coal-fired generation in May 2024 fell to 53 percent, the lowest share on record; shares of solar energy and wind energy for May 2024 were 12 percent and 11 percent respectively.97

Czech Republic Focus

The Czech Republic has six Russian-designed reactors in operation at two sites. Dukovany houses four VVER-440/v213 reactors, and Temelín operates two VVER-1000/v320 units. In 2023, nuclear power production represented a 40 percent share in electricity generation at 28.7 TWh, a slight decrease from 29.3 TWh in 2022.

In May 2022, ČEZ, the 70-percent-state-owned utility,98 announced that it had received an indefinite operating license for Temelín-2, on the grid since 2002, with a caveat that it continually meets conditions for safe operation.99 Temelín-1, commissioned in 2000, had received a ten-year license renewal in September 2020.100 ČEZ is planning to extend operating cycles at both units from 12 to 18 months, for which it expects the “final phase of approval” to begin this year.101 In 2023, the company announced that it would invest CZK3.6 billion (US$2023162 million) for the modernization of the reactors in view of extended lifetime operations to at least 60 years. Reportedly, as of February 2023, a total of over CZK28 billion (US$20231.26 billion) had been invested for upgrading the plant since startup.102

The Dukovany units were started up between 1985 and 1987 and have already undergone a lifetime-extension upgrading program under the expectation that they would operate until 2025. In March 2016, SÚJB extended the operating license of Dukovany-1 indefinitely,103 soon followed by indefinite lifetime extensions for the other three units.104 ČEZ expects that the plant will operate until 2037105 with the possibility of an extension until 2047.106 To allow for the operation of the plant “for at least 60 years”, ČEZ announced in early 2023 that it would be spending around CZK2.3 billion (US$2023104 million) during the year—28 percent more than in the previous year.107 The output of the four Dukovany units is planned to be gradually increased by 2.3 percent during 2024.108

Efforts to Decrease Dependence on Russia

In June 2022, in response to ongoing sanctions against Russian assets, CEZ Group purchased Škoda JS—an originally Czech nuclear service company—from OMZ, a Russian engineering group controlled by Gazprombank.109 Škoda JS had been acquired by OMZ together with two other former Škoda Holding subsidiaries in 2004.110 With its acquisition by ČEZ having been finalized in November 2022,111 Škoda JS has now been removed from U.S. sanction lists where it had been included due to its former ownership.112 Further, by acquiring Škoda JS, ČEZ increased its share in the ÚJV Řež research facility from 17.39 percent to 69.85 percent.113 With this acquisition, Czech companies are now actively involved in several local nuclear power plant component suppliers such as Sigma Group, a supplier of pumps used in nuclear power plants. However, fittings manufacturer Arako is still owned by Rosatom, and Chinese-owned machinery company Žďas generated 20 percent of its turnover from sales to Russia as of March 2023.114

Refueling-cycle extensions go hand in hand with Czech efforts to diversify fuel supply and “gradually replace” the current Russian provider, TVEL. Ultimately, all four VVER-440 reactors at Dukovany are to operate with fuel manufactured by Westinghouse.115 Preparations to receive Westinghouse fuel by the end of the year are ongoing, as are efforts to expand fuel storage capacity at both Dukovany and Temelín to secure increased onsite fuel reserves.116 Meanwhile, ČEZ continues to use and increase its stockpile of TVEL fuel. The latest refueling, that began in October 2023 at Dukovany-4, was carried out with new-generation TVEL fuel117 and ČEZ clarified that “the increase of nuclear fuel stocks will continue, at least until the operation of the plants with fuel from new suppliers is verified.”118

Russian fuel is also to be replaced at Temelín. Framatome and Westinghouse were contracted in 2022 to deliver fuel for “more than 10 years” from 2024 onwards.119 Westinghouse had already supplied fuel to Temelín in the first decade of operations,120 but in 2010, the operators switched back to TVEL, supposedly for economic reasons.121 However, there had also been technical difficulties with Westinghouse’s VVER-1000 fuel that might have led to the decision to switch suppliers.122 In 2019, six test assemblies manufactured by Westinghouse were loaded into Temelín-1,123 likely easing the return to Western suppliers. See also Russia Nuclear Dependencies. Furthermore, in March 2024, ČEZ signed an agreement with French Orano for uranium enrichment services that would be used to supply fuel for both Czech plants.124

These developments are part of the broader ongoing Czech efforts to shift energy reliance away from Russia. Before Russia invaded Ukraine, the Czech Republic received about 50 percent of its oil supply and most of its natural gas from Russian sources. Despite diversification efforts, Czech crude oil imports from Russia—currently exempt from E.U. crude oil import bans—rose to 56 percent of its total oil imports in 2022 and 65 percent in the first half of 2023.125 However, the state-owned oil pipeline operator indicated that Russian imports would be fully replaced “as early as mid-2025” following capacity upgrades on the alternative pipeline route.126 Natural gas supplies are also being diversified via other pipelines and Liquefied Natural Gas (LNG) import capacities are being secured via Dutch terminals.127 Further, the country is investing in shares of the German LNG terminal at Stade, scheduled to become operational in 2027.128

Newbuild Projects

Over the past two decades, the government and industry have repeatedly announced and withdrawn initiatives to build additional reactors.129 On 13 November 2019, the Czech parliamentary committee for the construction of new nuclear resources approved the construction of the Dukovany II nuclear plant.130 Subsequently, then-Prime Minister Andrej Babiš said that construction would start in 2029, and power production in 2036. This would have required holding a tender in 2021 and selecting a vendor by the end of 2022, two years ahead of the previous tentative schedule.131

In March 2020, ČEZ applied to SÚJB, the regulator, for the construction license of two 1,200-MW units at the Dukovany site. In June 2020, the government announced that it had agreed on a financing model whereby the state would provide a loan covering 70 percent of the project’s approximated US$6 billion price tag, while ČEZ would have to front the remaining 30 percent on its balance sheet. It was planned to launch a tender in late 2020.132

The government was expected to prepare, by the end of June 2020, draft contracts with ČEZ and its project company subsidiary that would establish a long-term (30–40 years) offtake agreement from the prospective newbuild to give the project greater financial security. It was also suggested that the government was prepared to insulate the project from legislative and regulatory risks, so that if a subsequent government were to phase out nuclear power, it would have to buy the project and reimburse the investors.133 It is not clear how the contracts between the state and ČEZ will be drawn up to provide such guarantees to ČEZ and minority shareholders. Current plans might lead to ČEZ restructuring, leading to full state responsibility for nuclear projects.134

By 2021, the government’s intention was to conduct safety assessments of potential applicants over the course of 2021 to launch a tender in December 2021 that would conclude in 2023. At the time, ČEZ hoped to finalize a supply contract by 2024 and to start building in 2029.135

The choice of vendor for the project is controversial. Initially, five designs were said to be in the running, including Korea Electric Power Corporation’s (KEPCO) APR-1000+, a revised, downsized version of EDF’s EPR called EPR1200—a design that has not been completed on paper and is not certified anywhere—both of which are yet to be built anywhere, and an AP-1000 from Westinghouse. Other designs in the running were reactors from China General Nuclear Power Corporation (CGN) and Rosatom of Russia. However, in early 2021, CGN was ejected from the process—officially due to security concerns as CGN is blacklisted by the U.S. Government—and the Czech Parliament delayed a final decision as the opposition demanded the Rosatom design to also be removed.136 Subsequently, the Cabinet unanimously approved the resolution and then-Deputy Prime Minister Karel Havlícek confirmed that security clearances would only be given to suppliers from France, South Korea, and the U.S.137

In March 2022, ČEZ subsidiary Elektrarna Dukovany II launched a newbuild tender for up to 1.2 GW. The three pre-qualified vendors—EDF, KEPCO subsidiary Korea Hydro & Nuclear Power (KHNP), and Westinghouse—submitted initial bids in November 2022 with the expectation that testing of the new units would begin in 2036. Estimations made in 2020 placed project costs at around CZK160 billion (US$20206.9 billion).138 Given that only Westinghouse’s AP-1000 would have fit the capacity constraints, some speculations around bid design to strengthen U.S.-Czech relations (recently reinforced by the purchase of F-35 fighter jets) arose. However, KEPCO was offering the lowest price and was willing to cooperate with Plzeň-based Škoda JS for turbine manufacturing.139 In October 2023, all three vendors submitted their final bids for Dukovany-5 and non-binding offers for three additional reactors.140 In parallel, ČEZ received the zoning permission for new nuclear facilities for the project.141

In January 2024, rather surprisingly, Westinghouse was removed from the competition; the government announced that the bid “did not meet the necessary conditions, and, above all, its offer is not binding and therefore cannot be evaluated in a comparable way.”142 EDF and KHNP were then asked to submit updated bids by the end of April 2024. These new binding bids were to include the construction of up to four reactors—instead of one—to reduce per-unit costs. According to Prime Minister Petr Fiala, “the course of the tender so far shows that the supply of several reactors at the same time could provide us with a lower price of up to one quarter for one reactor. Therefore, we have decided to ask bidders to submit binding offers for the supply of up to four new nuclear reactors. Based on them, we will then select a supplier and decide whether we will have more reactors built or not.”143 Both companies submitted their renewed bids on time.144 In mid-July 2024, KHNP was selected to build a minimum of two reactors.145, 146 Contract finalization is expected by March 2025, and the first reactor is scheduled for grid connection by 2036, the second following two years later. Each reactor is said to cost CZK200 billion (US$8.7 billion), and the Czech Government announced the beginning of negotiations for two additional reactors to be built at Temelín, hoping to reduce per-unit costs by 20 percent147 instead of the previously envisioned 25 percent.148

Westinghouse being ousted from the race is all the more remarkable given the ongoing technology licensing dispute between Westinghouse and KHNP. In October 2022, Westinghouse filed a lawsuit accusing KHNP of unauthorized transfer of technology and technical information (including through participation in the Czech bidding process) for its APR-1400 from an earlier design owned by Westinghouse (see Poland Focus and KEPCO/KHNP v. Westinghouse in South Korea Focus), which could impact KHNP’s ability to provide reactor technology for the Dukovany project, amongst others.149 In September 2023, the District Court for the District of Columbia ruled that export control enforcement lied solely with the U.S. Government, thereby dismissing Westinghouse’s claim that this could be privately acted upon.150 Westinghouse appealed the decision in October 2023.151 However, with or without the appeal, Westinghouse’s main claim regarding technology licensing is still under review by an arbitration panel, and a final ruling is not expected before the end of 2025.152

In parallel to finding a potential reactor vendor, the financing scheme for the Dukovany II project is also being designed. In July 2022, the European Commission launched a state aid review of the project, which was to look at the three government support mechanisms, namely:

(i) a low-interest repayable State loan expected to cover 100% of the construction costs (approximately €7.5 billion [US$20238.1 billion];

(ii) a power purchase agreement between EDU II and a State-owned company for the lifetime of the project (60 years)—according to the Czech authorities, this would lower the power purchase price and allow for price adaptations every 5 years; and

(iii) a mechanism to protect the ČEZ Group and the State in case certain unforeseen events occur (e.g. if the Czech law changes and makes the realization of the project impossible).153

The Commission reviewed “the appropriateness and proportionality” of the subsidies and their impact on the electricity market to ensure these were “fully in line with EU State aid rules”.154 Based on an earlier preliminary assessment, the Commission had “found the project necessary and considers that the aid facilitates the development of an economic activity”,155 and in April 2024, the Commission approved of the aid scheme with the Czech Government’s amendments. This included, amongst others, the reduction of the price support scheme from 60 to 40 years, and the implementation of a “contract-for-difference” design. The plant will also receive the actual market price for every megawatt-hour of electricity produced; the Commission hopes that the exposure of the plant to market signals “[will limit] market distortions and [prevent] the displacement of renewables, to the benefits of the electricity system and facilitating its decarboni[z]ation.”156 The subsidized state loan is to go through as planned and include “a protection against unforeseen events or policy changes that may make the realization of the project impossible.”157

SMRs for the Czech Republic?

In addition to a new reactor at Dukovany, ČEZ has long been interested in building additional units at Temelín, where two more units were under construction between 1985 and 1990, and in March 2022 announced that it had set aside land for the construction of SMRs.158 Seven bidders are currently competing for the construction of an SMR at the Temelín site, with first operation scheduled for 2032 to 2035, which appears unrealistic (see chapter on SMRs). According to media reports, GE Hitachi, NuScale, and Rolls-Royce are considered to have the most prospects of winning the contract.159

In February 2023, ČEZ announced further potential sites for SMR construction post-2035 at the current sites of coal power plants Dětmarovice and Tušimice.160 In total, ČEZ plans to build SMR-capacities adding up to 3 GW after 2050 with a pilot project envisioned to be online by 2032.161 In the Czech SMR Roadmap, published by the Ministry of Industry and Trade, SMRs are discussed as potential electricity generation sources alongside high-capacity reactors and renewables. Cost estimations and scenarios are based on very optimistic assumptions (see chapters on SMRs and Nuclear Economics and Finance in WNISR2023).162 In November 2023, the government approved the roadmap, and drawing from it decided that SMRs would be “included in the State Energy Policy and recognized in the Spatial Development Policy of the Czech Republic.”163

Energy Policy Context

According to Ember, in 2023, the Czech Republic generated a total 76.18 TWh of electricity, of which over 40 percent were attributed to coal, followed by nuclear power attaining just under 40 percent. Bioenergy contributed 7 percent of electricity generation while solar and hydro accounted for only 4 percent and 3 percent, respectively. Natural gas stood at around 3 percent, and just shy of 2 percent were generated by “other fossil fuels”. Wind power contributed less than 1 percent.164

In October 2023, an update of the National Energy and Climate Plan (NECP) was completed.165 The document builds on 2040-targets stipulated by the 2015 the Czech State Energy Concept166 (in Czech: Státní energetické koncepce, SEK) which envisioned a reduction of the share of coal generation to 11–21 percent, the increase of nuclear to 46–58 percent, and a share of renewable electricity generation of a maximum of 25 percent. Given these rather low shares, and the newly elected government having hinted at an amendment of these targets in 2022,167 an update of this SEK was expected to be published by end-2023.168

With a brief delay, a draft was published in February 2024 that aimed at a coal phaseout by 2033. The new 2040 electricity generation share targets envision a 47–65 percent share for nuclear. For renewables, the new target ranges from 33 to 47 percent.169 While scenarios in the NECP projected a future mix with 13 GW of solar PV, 2.5 GW of wind, 2.2 GW of hydro and pumped storage, and less than 600 MW of “other renewables”, with around 3.8 GW of natural gas capacity and approximately 5.2 GW of nuclear power as well as 2.6 GW of battery capacity.170 ČEZ envisions bringing a total of 6 GW of “new renewables” to the grid by 2030, albeit not clarifying the breakdown by technology.171 As of the time of writing, a consultation process on the new draft had just ended and was under review for finalization.172

France Focus

Overview

EDF’s Executive Director of Generation and Engineering of the Existing Nuclear and Thermal Fleet called the year 2022 “annus horribilis”.173 Nuclear output dropped below the level of 1990 when the installed nuclear capacity was some 5 GW lower. Nuclear generation actually peaked in 2005 at over 430 TWh and in nine of the following ten years, output exceeded 400 TWh, which was considered the norm until 2015. In 2022, French reactors produced 279 TWh, a drop of over 120 TWh from the 2005–2015 period. In 2023, nuclear power generation picked up by just under 15 percent to reach 320 TWh, still far from the 400 TWh level of earlier years.

The discovery in December 2021 of cracks in the emergency core cooling systems first led to the shutdown of the four largest (1500 MW) and latest French reactors. After the identification of the same phenomenon in other reactors, EDF decided to implement an unprecedented, comprehensive inspection and repair program that eventually should cover the entire fleet and last into 2025.

In June 2023, the National Assembly passed legislation for the “acceleration of procedures for the construction of new nuclear facilities near existing nuclear sites and for the operation of existing facilities”174 (see France Focus in WNISR2023). While these measures can cut some red tape, they are unlikely to significantly ease the phenomenal industrial challenges.

In February 2022, the French President announced a plan to build six units of a new design, called EPR2, with a target date of the first startup by 2035. In addition, the option of building eight additional units until 2050 should be studied.175

Currently, the EPR2 does not exist on the drawing board; no detailed design is available yet. The administration estimated in an October 2021 internal note that 19 million engineering hours still had to be deployed to get from “basic design” to the “detailed design” stage and that, if everything goes well, the first EPR2 could start up by 2039–2040. In case unexpected industrial difficulties occur—as they did in the past and do currently—it could take until 2043 to commission the first EPR2, the project review states.176

In August 2023, EDF applied for a building permit for the first pair of the “sixpack” to be built at the Penly site. The other pre-selected sites for a pair of EPR2 units are Bugey and Gravelines, and EDF is in the course of filing all administrative applications to implement these projects.

As of mid-2024, EDF announced that the total EPR2 development budget would reach €3 billion (US$3.2 billion) by the end of 2024. Also, EDF launched the manufacturing of EPR2 primary components (like heavy forgings). All of this is happening while no Final Investment Decision (FID) has been taken.177

Meanwhile, the Nuclear Safety Authority (ASN) stated in its Annual Report 2023:

The EPR 2 program is starting at the rate of one pair of reactors every three years. This situation is creating considerable pressure on the industrial stakeholders, with the risk being that, faced with unrealistic objectives, deadlines compliances takes precedence over quality.178

French Economy and Finance Minister Bruno Le Maire was quoted as saying in early June 2024:

The first EPR2 reactor should be completed by 2035, that is in nine years. In the next five years, we should be able to see how the program is advancing. If things are going well, rapidly and on cost, that will be the moment when we can consider building the extra EPR2 reactors.179

Performance Still Far From Normal

Until the closure of the two oldest French units at Fessenheim in the spring of 2020, the French nuclear fleet had remained stable for 20 years, except for the closure of the 250-MW fast breeder Phénix in 2009, two units in Long-Term Outage (LTO) within the period 2015–2017, and another one within the period 2021–2023 (see Figure 28). Penly-1, subject to the stress-corrosion cracking issue, was offline between 2 October 2021 and 13 July 2023.180 Four units at Civaux and Chooz-B did not generate power throughout 2022 but did not meet the LTO criteria as they were restarted prior to mid-2023. Golfech-1 was shut down for almost two years, between 26 February 2022 and 14 January 2024, but did not meet the LTO criteria (down for a full calendar year plus six months of the following year).

1. Operating Fleet and Capacity in France

Sources: WNISR with IAEA-PRIS, 2024

No new reactor has started up since Civaux-2 was connected to the French grid 25 years ago, in December 1999. The first and only Pressurized Water Reactor (PWR) closed prior to Fessenheim was the 300-MW Chooz-A reactor, which was retired in 1991. The other closures were that of eight first-generation natural-uranium gas-graphite reactors, two fast breeder reactors, and a small prototype heavy water reactor (see Figure 29).

In 2023, the 56-reactor fleet181—one of which did not generate any power—produced 320 TWh, an increase of 41.5 TWh (+14.8 percent) over the previous year which saw the lowest output since 1988; the production remained at the level of 1992, when the six most recent units had not started operating. It also stayed below its level of 2020 and the eighth year in a row below 400 TWh. The national grid operator RTE summed up: “Nuclear power generation started to recover but is still far from its historic levels.”182 The difficulties are not over.

In 2005, nuclear generation peaked at 431.2 TWh. After the construction program was completed in 1999, it took the fleet five years to build up to that maximum generation, and with a quasi-stable installed nuclear capacity between late 1999 and early 2020, performance plunged after 2015 (see Figure 30).

1. Startups and Closures in France

Sources: WNISR, with IAEA-PRIS, 2024

Notes: PWR: Pressurized Water Reactor; GCR: Gas-Cooled Reactor; HGWGCR: Heavy Water Gas Cooled Reactor; FBR: Fast Breeder Reactor.

1. Nuclear Electricity Production vs. Installed Capacity in France

Sources: RTE, 2000–2024, EDF 2024

Note: In Figure 30, reactors in LTO are counted in the “installed capacity”.

In 2023, nuclear plants provided 65 percent (+2.3 percentage points) of the country’s electricity, but still less than in COVID-year 2020. The nuclear share peaked in 2005 at 78.3 percent. As of mid-year, EDF estimated the production for 2024 to be in the upper end of the 315–345 TWh range and in the 335–365 TWh range for 2025 and 2026183 (see Figure 30 and Figure 31).

The year 2023 saw record additions of solar (+ 3 GW) and offshore wind power (+360 MW) capacities as well as record solar and total onshore and offshore wind generation—solar increasing by 16 percent and wind by one third compared to 2022—reaching close to 22 TWh and 51 TWh, respectively, together accounting for almost 15 percent of the electricity supply in the country. Offshore wind remains relatively marginal yet with a cumulated installed capacity of only 840 MW compared to 21.8 GW of onshore wind capacity as of the end of 2023.184

1. Nuclear Electricity Production vs. Nuclear Share in France

Sources: RTE, 2000–2024, EDF, 2024

Monthly production has continued to deteriorate in early 2023 with a lower output in every month of the first quarter of the year than in any year over the past decade, and while output improved starting in the second quarter, it remained below the 2021 level until December (see Figure 32). In the first half of 2024, the production level stayed again slightly below the 2021-performance.

Electricity represented 25 percent of final energy in France in 2023. As nuclear plants provided 65 percent of electricity, they covered 16.3 percent of final energy. The largest share being covered by fossil fuels at 60 percent, with oil at 42.5 percent, and natural gas at 17.2 percent (coal <1 percent).185

1. Monthly Nuclear Electricity Generation, 2012–mid-2024

Sources: RTE and EDF, 2021–2024186

Nuclear Unavailability Review 2023

In 2023, there were 7,103 reactor-days— around 1,400 fewer reactor-days than in 2022 but still the second highest number in the past five years—an average of 127 days, or over four months, with zero-production per reactor. This does not include load following or other operational situations with reduced, but above-zero output. The number is 32 percent higher than the average 96 days per reactor in pre-COVID year 2019 and 10 percent higher than in 2020. Fifty-five reactors were subject to outages lasting from five to 365 days (see Figure 34). One reactor was offline during the whole year (Golfech-1) and one produced all year round (Saint Alban-2).

The declared “forced” outages have increased by 43 percent from 278 to 399 days exceeding any of the four previous years.

Table 5 illustrates that, while the declared “planned” outage-days dropped significantly in 2023, the declared “forced” outages have increased by 43 percent from 278 to 399 days exceeding any of the four previous years.

1. Total Unavailability of French Nuclear Reactors, 2019–2023 (in Reactor-Days)

	Declared Type of Unavailability
	“Planned”	Forced	Total	Average per Reactor
2019	5,273	316	5,588	96
2020	6,179	286	6,465	115
2021	5,639	172	5,811	14
2022	8,287	278	8,515	152
2023	6,704	399	7,103	127

Sources: RTE and EDF REMIT Data, 2019–2024

1. Reactor Outages in France in 2023

Sources: compiled by WNISR, with RTE and EDF REMIT Data, 2024

Note: For each day in the year, this graph shows the total number of reactors offline, not necessarily simultaneously as all unavailabilities do not overlap, but on the same day.

The unavailability analysis for the year 2023 on Figure 33 further shows:

• During the whole year at least 11 units and up to 28 were down during the same day.
• On 252 days (69 percent of the year), 19 or more units were shut down for at least part of the day.
• At least eleven reactors were down (zero capacity) simultaneously at any day of the year but for 7 hours with only ten reactors offline.
• At least 20 reactors were offline simultaneously during the equivalent of 192 days.

According to EDF’s classification of “planned” and “forced” unavailabilities, in 2023:

• 16 reactors did not experience any “forced” outage (of which 13 were in “planned” outage for more than 100 days during the year)
• at six units “forced” outages lasted less than one day,
• at 24 cumulated “forced” outage duration represented between one and 10 days,
• and at 10 reactors “forced” outage cumulated between 10 and 65 days over the year (see Figure 34).

1. Forced and “Planned” Unavailability of Nuclear Reactors in France in 2023

Sources: compiled by WNISR, with RTE and EDF REMIT Data, 2024

Notes: This graph only compiles outages at zero power, thus excluding all other operational periods with reduced capacity >0 MW. Impact of unavailabilities on power production is therefore significantly larger.

“Planned” and “Forced” unavailabilities as declared by EDF.

However, EDF’s declaration of “planned” vs. “forced” outages is highly misleading. EDF considers an outage as “planned” whatever the number and length of extensions (or, in rare cases, reductions) of its total duration if the outage was first declared as “planned”.

Detailed WNISR analysis for earlier years shows a different picture.

1. Unavailability of a Selection of French Nuclear Reactors, 2019–2023

Sources: compiled by WNISR, with RTE and EDF REMIT Data, 2019–2024

Note: The categorization follows EDF’s classification. However, it is not reflecting reality as a “planned” outage remains in that category even if it lasts much longer than “planned”.

The cumulated outage analysis over the five years 2019–2023 reveals the following (see Figure 35):

• Three reactors were down half of the time or more (Flamanville-1 and -2, Chooz-1);
• 26 reactors were generating zero power for 30 percent of the time, that is 109 days and more per year on average;
• 46 reactors were off-grid for at least one quarter of the time, in other words, they did not generate any power for the equivalent of one in four years.

Stress Corrosion Cracking and Thermal Fatigue

Severe stress corrosion cracking had been first identified in late 2021 at the safety injection systems of the four largest and most recent French reactors at Chooz and Civaux.187 Later additional reactors were identified and a program of pre-emptive replacement of particularly sensitive piping sections was decided for the “P’4” reactor series. While apparently so far rare, the phenomenon has also been identified on other 1300-MW and some 900-MW reactors. EDF decided to inspect its entire reactor fleet by the end of 2025 and claims that, as of mid-2024, already 50 of its 56 units had been “controlled and treated”.188

In February 2023, an additional issue was identified during destructive examination at Penly-1. Close to a weld of a line of the safety injection system that had been repaired during construction of the plant, a 15.5 cm long—about one quarter of the circumference—and up to 2.3 cm deep crack—for a 2.7 cm thick tube—was identified. The origin has been determined as thermal fatigue rather than stress corrosion cracking. This discovery meant that an extensive inspection program of all repaired welds had to be added to the stress corrosion cracking investigations. According to planning, 90 percent of the repaired welds in the safety injection and shutdown cooling systems of the entire reactor fleet are to be inspected by the end of 2024 with the remaining ones in 2025.189

Lifetime Extensions – Regulator Flexibility

By mid-2024, the average age of the 56 nuclear power reactors exceeded 39 years (see Figure 36). Lifetime extension beyond 40 years—52 operating units are now over 31 years old, of which 23 are over 41 years—requires significant additional upgrading. Also, relicensing is subject to public inquiries reactor by reactor.

EDF will likely seek lifetime extensions beyond the 4th Decennial Safety Review (VD4) for most, if not all, of its remaining reactors. President Macron in his February 2022 programmatic speech made it clear that the government had no intention of closing reactors anymore. He stated, “While the first extensions beyond 40 years have been implemented successfully since 2017, I’m asking EDF to examine the conditions of the [lifetime] extensions beyond 50 years, in conjunction with the nuclear safety authority.”190

The first reactor to undergo the VD4 was Tricastin-1 in 2019. Bugey-2 and -4 were scheduled for the same in 2020, and Tricastin-2, Dampierre-1, Bugey-5, and Gravelines-1 started in 2021… until the COVID-19 pandemic further disrupted the safety review schedule.191 Until 1 July 2024, 16 units had undergone their VD4 and a further 4 were underway (see Table 6).

The Chief Technical Officer of EDF Group and EDF Director of R&D, Bernard Salha, told French Parliament in February 2023 that the work volume of a VD4 was five times larger than that of a VD3.

While ASN judged the VD4-premiere on Tricastin-1 “satisfactory”, it questioned whether EDF’s engineering resources were sufficient to carry out similar extensive reviews simultaneously at several sites.192 Beyond the human resource issue, the experience raises the question of affordability. EDF had scheduled an outage for Tricastin-1 of 180 days in 2019, which was first extended by 25 days to 205 days. Including further, unrelated unavailabilities, the reactor was finally in full outage for two thirds of that year (232 days).

The following VD4 exercises also saw significant delays between expected and real durations (see Table 6).

EDF expects these VD4 outages to last six months, much longer than the average of three to four months experienced through VD2 and VD3 outages. The Chief Technical Officer of EDF Group and EDF Director of Research & Development (R&D), Bernard Salha, told the French Parliament in February 2023 that the work volume of a VD4 was five times larger than that of a VD3. He also said investments into the operating fleet have doubled over the past decade.193

As illustrated, many factors could lead to significantly longer outages. EDF has already started negotiating with ASN for the workload to be split in two packages, with the supposedly smaller second one to be postponed four years after the VD4.194

1. Fourth Decennial Visits of French 900-MW Reactors, 2019–2024

Reactor	Capacity	Grid Connection	VD4 Outage	Expected Duration	Total Duration
Tricastin-1	915	31 May 1980	01/06/19–23/12/19	180	205
Bugey-2	910	10 May 1978	18/01/20–15/02/21	181	395
Bugey-4	880	8 March 1979	22/11/20–24/06/21	226	214
Dampierre-1	890	23 March 1980	19/06/21–05/02/22	170	231
Tricastin-2	915	7 August 1980	06/02/21–26/07/21	180	170
Bugey-5	880	31 July 1979	31/07/21–21/04/22	189	265
Gravelines-1	910	13 March 1980	14/08/21–11/04/22	188	240
Tricastin-3	915	10 February 1981	12/03/22–21/11/22	171	254
Gravelines-3	910	12 December 1980	23/03/22–22/12/22	191	275
Dampierre-2	890	10 December 1980	27/04/22–31/12/22	171	248
Blayais-1	910	12 June 1981	31/07/22–19/06/23	185	323
Saint-Laurent-2	915	1 June 1981	20/01/23–20/11/23	223	304
Chinon B-1	905	30 November 1982	07/02/23–19/05/24	265	467
Gravelines-2	910	26 August 1980	10/06/23–07/03/24	197	272
Blayais-2	910	17 July 1982	24/06/23–31/03/24	182***	281
Dampierre-3	890	30 January 1981	23/09/23–2/03/24	170	161
Bugey-3	910	21 September 1978	11/11/23–28/08/24**	177	291
Tricastin-4	915	12 June 1981	19/01/24–16/07/24	194	179
Gravelines-4	910	14 June 1981	20/01/24–23/08/24**	195	215**
Blayais-3	910	17 August 1983	08/06/24–16/12/24*	191
Cruas-3	915	14 May 1984	04/08/24–24/03/25*	232
Dampierre-4	890	30 January 1981	12/07/24–16/01/25*	188

Sources: compiled by WNISR, based on EDF REMIT-Data195

Notes: The expected duration is based on outage dates in use as of outage start, or within the few days after the reactor was disconnected from the grid.

For ongoing decennial visits, end of outage date is the date in use as of 17 August 2024, and can vary from the original date:

* Expected duration as of Outage start;

** Revised date/duration, as provided as of 17 August 2024;

*** Original duration.196

On 23 February 2021, ASN issued detailed generic requirements for plant life extension.197 The key aspects of ASN’s decision were not the five short administrative articles but the two annexes setting the technical conditions and the timetable for work to be carried out. The challenge for operator EDF will be high, as ASN outlines:

Over the coming five years, the nuclear sector will have to cope with a significant increase in the volume of work that is absolutely essential to ensuring the safety of the facilities in operation.

Starting in 2021, four to five of EDF’s 900 Megawatts electric (MWe) reactors will undergo major work as a result of their fourth ten-yearly outages. (…)

All of this work will significantly increase the industrial workload of the sector, with particular attention required in certain segments that are under strain, such as mechanical and engineering, at both the licensees and the contractors.198

This was prior to the corrosion issues that struck EDF’s fleet at the end of 2021. ASN has shown remarkable tolerance for extended timescales of refurbishments and upgrades in the past; many of the post-Fukushima measures have not yet been implemented eleven years after the events, for example. As of the end of 2020, none of the 56 French reactors were backfitted entirely according to ASN requests issued in 2012. According to some estimates, the completion of the work program could take until 2039.199

Additionally, the implementation of work to be carried out as part of the lifetime extension beyond 40 years stretches over 15 years until 2036, when the last 900-MW reactor is supposed to be upgraded: Chinon B-4, connected to the grid in 1987, gets the 15-year delay to implement 15 of a total of 37 measures. By then, the unit will have operated for 49 years. This is just one example, and it is the newest of the operating 900-MW reactors. ASN has accepted similar timescales for all 32 of the 900-MW units. The French Nuclear Safety Authorities have proven flexible, and—considering the dire state of the reactor fleet—pressure for even more flexibility might increase in the future.

On 13 October 2023, EDF applied for permission to delay many of the required upgrades of the 32-unit fleet of 900-MW units by years, “given the difficulties of meeting them.” EDF justified the application by

• the occurrence of technical contingencies during the implementation of certain requirements;
• changes in the scheduling of refueling outages, linked in particular to the discovery of stress corrosion on auxiliary lines, to fortuitous long-term shutdowns, and to stresses affecting the power grid;
• the concomitance of other periodic reviews, putting a strain on engineering capacity.200

Following a public consultation for three weeks between 13 November and 1 December 2023, ASN, on 19 December 2023, modified its February 2021 publication of generic requirements, and delayed target dates for 31 of the 32 units for at least one but up to 14 upgrading work-packages (of a total of 36 per reactor) for periods of one to five years. This regulatory decision is another demonstration of the remarkable flexibility of the French nuclear safety authority.

1. Age Distribution of French Nuclear Fleet (by Decade)

Sources: WNISR, with IAEA-PRIS, 2024

Financial Issues

Operating and maintenance costs of the ageing fleet of reactors have significantly increased over the past decade (see also previous WNISR editions), but whatever the uncertainties over various cost estimates might be, there is little doubt that the additional costs for refurbishment and upgrades in view of lifetime extensions remain below any cost estimate for newbuild.

Outages that systematically exceed planned timeframes are particularly costly. EDF’s net financial debt increased by about €10 billion (US$202111.8 billion) over the period 2019–2021 to a total of €43 billion (US$202151 billion) as of the end of 2021.201 In 2022 alone, net debt jumped by €21.5 billion (US$202222.6 billion) to €64.5 billion (US$202267.9 billion) at the end of the year.202 Luc Rémont, EDF’s incoming CEO, stated during a hearing at the Finance Commission of the National Assembly:

We are on the eve of an industrial challenge which, in reality, is out of all proportion with the Group’s history for several reasons. The first is that we are beginning this steep path towards greater investment in electrification with the somewhat heavy rucksack of a 65 billion euro [US$202370 billion] debt which is—I’m sure, even for the Finance Commission, 65 billion euros is a significant amount—I can assure you for a company, it is the heaviest amount a company can experience in Europe and so, naturally, it is part of the elements that define our capacities and the ways in which we can envisage this new investment cycle.203

Rémont added that the Group never before had to invest on the order of €25 billion per year (US2023$27 billion/year) of which 80 percent in France while “debt can hardly increase more”.204

In 2023, profiting from increased nuclear and hydro power output as well as a good year for renewables, EDF managed to go from a record loss to a €10 billion (US$202310.8 billion) profit and was able to reduce its debt load by an equivalent amount to €54.4 billion (US$202358.8 billion).205 EDF’s 2024 Half-Year Results show a stabilization of the debt load at €54.2 billion (US$58.6 billion).206

However, the struggle with rapidly changing market situations leading to lower average prices and, increasingly often, to negative prices on the spot market, have significant impact on the management of France’s nuclear fleet. EDF states in its 2024 half-year financial report that “the decline in sale prices had an estimated impact of -€8.1 billion [US$8.8 billion]” in the first six months of the year. And further: “For example, on 12 May 2024, the French nuclear power fleet adjusted its capacity from 36.4 GW to 22.6 GW and the lowest hourly spot price in the whole half-year, -€87.3/MWh [US$94.4/MWh], was recorded at 2 pm the same day.”207

The Flamanville-3 EPR Saga Continued

The 2005 construction decision of Flamanville-3 (FL3) was mainly motivated by the industry’s attempt to confront the serious problem of maintaining nuclear competence. Fifteen years later, ASN still drew attention to the “need to reinforce skills, professional rigorousness and quality within the nuclear sector.”208

In December 2007, EDF started construction on Flamanville-3 (FL3) with a scheduled startup date of 2012. The project has been plagued with design issues and quality-control problems, including basic concrete and welding difficulties similar to those at the Olkiluoto (OL3) project in Finland, which started construction two-and-a-half years earlier and was connected to the grid only in March 2022 (see earlier WNISR editions.) These problems never stopped.

In March 2020, EDF had stated that fuel loading would be delayed to “late 2022” and re-evaluated construction costs at €12.42015 billion (US$201513.8 billion), an increase of €1.52015 billion (US$20151.7 billion) over the previous estimate.209 In addition to the overnight construction costs, as of December 2019, EDF indicated more than €4.2 billion (US$20194.7 billion) was needed for various cost items, including €3 billion (US$20193.4 billion) of financial costs.

In January 2022, EDF estimated the overnight costs at €201512.7 billion (US$201514.1 billion).210 In December 2022, the figure was updated to €201513.2 billion (US$201514.6 billion).211 In 2020, the French Court of Accounts estimated the total cost, including financing and other associated costs, at €201519.1 billion (US$201521 billion).212 The Court estimated that the cost of electricity from FL-3 would be €2015110–120/MWh (US$2015122–133/MWh). This estimate has not been publicly updated.

The fuel issue that struck the Taishan EPRs and kept Unit 1 off-grid for over one year had consequences for FL3. EDF decided to refabricate 64 of the 241 fuel assemblies that had already been produced. These were approved by ASN and delivered to the site. Fuel loading was finally completed in May 2024. Since then, EDF representatives repeatedly stated that the reactor startup was “imminent” with grid connection happening “a few weeks later”. As of mid-year 2024, this did not happen.213

Conclusion

The French nuclear industry remains under a high level of stress. The full re-nationalization of EDF, analysts agree, will not solve its structural problems: an ageing nuclear fleet with lowest performance in decades, manpower and competence challenges, unprecedented investment needs at times of unprecedented net debt, and never-ending problems at the only active construction site at Flamanville.

Not covered here, but to this list should be added serious fuel chain issues, climate impact, social movements, and some unexpected opposition. Especially the plutonium-economy part of the industry is experiencing its own crisis with historically low throughput at the spent fuel reprocessing plant at La Hague and at the uranium-plutonium mixed-oxide (MOX) fuel fabrication facility MELOX at Marcoule. Consequently, spent fuel pools are filling up and the stocks of unirradiated plutonium have increased to unprecedented levels.

Confronted with this avalanche of problems, the French Government has chosen to insist on the launch of a nuclear newbuild program—supported by a majority in the National Assembly. And EDF follows suit:

On 29 June 2023, EDF announced that it was making the applications for approval to launch construction of the first pair of EPR 2 reactors at Penly, and starting other administrative procedures required for their completion and connection to the electricity transmission network. EDF’s objective is to begin preparatory work in mid-2024.214

The EPR2 does not even exist on paper. It increasingly looks as if the current administration and nuclear establishment have not learned the lessons of the Flamanville EPR1 disaster, as spelled out in the chapter headlines of a 2019-assessment commissioned by EDF’s President: “An unrealistic initial [cost] estimate; (…) An inappropriate project governance; Struggling project teams; (…) Insufficiently advanced studies at launch; (…) Generalized loss of competence.”215

Largely unreported, the science community in France is far from offering unanimous support of the newbuild initiative. As of the end of October 2023, close to 1,200 scientists had signed the “Call by scientists against a new nuclear program”.216

Hungary Focus

Hungary has one operating nuclear power plant at Paks where four VVER-440/v213 reactors provided 15.1 TWh or 48.8 percent of the country’s electricity in 2023. The nuclear share in the national power mix peaked at 53.6 percent in 2014. The reactors began operating between 1982 and 1987 and have undergone engineering work to enable their operation for up to 50 years (compared to their initial 30-year license). The first unit received permission to operate for another 20 years in 2012, the second in 2014, the third in 2016, and the fourth in December 2017, enabling the plant’s operation until the mid-2030s.

In Hungary, renewable capacities have been increasing over the past decade, driven by the expansion of solar from just 89 MW in 2014 to over 5.8 GW in 2023, representing about 86 percent of the country’s renewable sources.217 In an updated version of Hungary’s National Energy and Climate Plan, submitted in September 2023, 12 GW of PV capacity is expected to be reached in 2030, while wind power capacity shall more than triple over the same period from currently around 330 MW to still modest 1 GW. This would bring the total renewable electricity generation share to 31 percent. The plan assumes continued operation of all four operational reactors at Paks, plus the Paks II reactors currently under construction, amounting to 4.4 GW of nuclear capacity by 2030. It also envisions the potential deployment of Small Modular Reactors (SMRs). This would account for around 50 percent of annual electricity production from nuclear.218 At the International Atomic Energy Agency’s (IAEA’s) Nuclear Energy Summit held in March 2024 in Brussels, Prime Minister Viktor Orbán announced, without providing any details, that his government was planning to expand this share to 70 percent by adding a further 2.4 GW by the “beginning of the next decade”.219

According to Ember, natural gas contributed 21.1 percent and solar 18.4 percent to the Hungarian electricity production in 2023.220 The remainder consisted of a mix of bioenergy (4.9 percent), wind (1.8 percent), hydro (0.6 percent), and “other” fossil fuels (1 percent).221

In July 2022, the government announced it would put forward economic and technical plans to further extend the operating lives of the existing nuclear reactors at Paks by up to 20 years.222 This decision was approved with an overwhelming majority in parliament (170 votes in favor, eight against, one abstention) in December 2022,223 and in December 2023, these plans, that would extend the operational lifetimes of the four reactors to 70 years, were officially announced to the E.U. Commission. A detailed implementation plan shall be provided by 2028. Costs for “revamping [of] the electric and control systems” are estimated at around €1.5 billion (US$20231.7 billion).224

Cooperation With Russia and Belarus

Hungary’s energy supply heavily depends on Russia.225 With its continued blocking of E.U. sanctions against Russia, especially in the nuclear sector, Hungary is being rewarded by a continued supply of Russian gas mostly via the Turkstream pipeline.226 After a meeting between Hungarian Prime Minister Viktor Orbán and Russian President Vladimir Putin in October 2023 in Beijing, increased gas supplies from Russian state-owned company Gazprom were announced.227 Paks operator MVM Paksi Atomerőmű Zrt reportedly said that from 2024 it would be storing three years’ instead of previously two years’ worth of nuclear fuel onsite. The increase would be intended «to reduce the uncertainties resulting from the conflict in Ukraine.”228

Furthermore, after being the first E.U. minister to visit Belarus since the imposition of substantial sanctions in May 2024, Hungarian Foreign Minister Péter Szijjártó announced that Belarusian and Hungarian officials had signed an agreement to cooperate on nuclear energy, reportedly envisaging personnel training and nuclear waste handling. He stated that he “[hoped] that Belarusian companies will soon join American, German and French companies that are already working as partners of Rosatom on the construction of the Paks [II] nuclear power plant.”229 The former project manager of Rosatom’s Belarusian new build project (see Belarus in Annex 1), Vitaly Polyanin, became project leader of the Paks II newbuild project in November 2023, discussed below.230

“I would like to stress there will be no European sanctions against the nuclear industry in the future, all the more so as it would be against our national interests. So, of course, we will keep at bay any such attempts,” Szijjártó was quoted as saying in September 2023.231 Hungary’s stance on blocking sanctions against Russia or granting financial aid to Ukraine continued in 2024.232 In March 2024, Hungary’s Prime Minister Orbán stated during the above-mentioned Nuclear Summit in Brussels:

We are happy to note that regardless of the geopolitical difficulties, a wide range of international professional and scientific cooperation still exists on the field of nuclear energy. While Russia became the number one uranium supplier of the United States last year, a number of American, German, French, Swedish, Swiss, and even Austrian subcontractors are working together with the Russian constructors on our nuclear expansion project. It is the interest of all of us to prevent nuclear energy to become a hostage of geopolitical conflicts, hypocrisy, and ideological debates. Therefore let me finally thank all of you for intervening in the European Court case regarding our nuclear investment and to ensure the safe delivery of nuclear fuel to our existing plant.233

Hungary’s dependence on Russian nuclear fuel became remarkably evident in April 2022, when fresh nuclear fuel was flown from Russia following the award of a special permit to bypass the E.U. airspace closure to Russian aircraft.234 Hungarian nuclear fuel for the operating plant is provided solely by Russian TVEL, and the Paks II plant will also be provided with fuel by TVEL.235 Since 2022, Russian fuel has been coming to Hungary via the Black Sea, where ships escorted by Russian Navy warships unload the fuel in Varna, Bulgaria, from where it is transported to Hungary via rail. Before 2022, fuel had been delivered via train through Ukraine.236 After a stockpile of three years’ worth of fuel had been secured,237 the Hungarian Parliament in November 2023 passed an amendment to the official nuclear policy that would allow alternative sources for nuclear fuel to be used.238 This followed contradicting reports that Hungary would not change supplier,239 the signing of an MoU for “long-term cooperation” with French fuel supplier Framatome,240 and its participation in the consortium, led by U.S. supplier Westinghouse, which was selected for the E.U. Accelerated Program for Implementation of Secure VVER Fuel Supply (or APIS project) intended to “secure [VVER] fuel supply in Europe and Ukraine.”241

The PAKS II Saga

For a decade and a half, plans have been discussed and developed to build additional nuclear power plants. In March 2009, Parliament approved a government decision-in-principle to build additional reactors242 and a tender was prepared according to E.U. rules. In 2014, the Paks II project, consisting of two 1200-MW reactors, was suddenly awarded to Rosatom without reference to any public tender, with Russia financing 80 percent of the project through loans.243 The original Russian-Hungarian bilateral financing agreement from 2014 consisted of a €10 billion (US$201413 billion) loan to the Hungarian state, to be repaid from 2026 onwards irrespective of whether the plant had come online by that time. Hungary would have to invest 20 percent or up to €2.5 billion (US$20143.3 billion) into the project. Then in April 2021, the loan terms were revised to allow Hungary to start repaying the loan in 2031, five years later than originally agreed.244 Rosatom had been awarded the project at a fixed price contract that “might no longer be favorable”, while in Hungary cheaper solar deployment is rapidly highlighting the high costs of potential electricity to be produced by Paks II, which would be borne by the taxpayers.245

Legal Challenges to State Aid for Paks II

In November 2016, after a one-year procedure, the European Commission cleared the award of the contract to Rosatom of any infringement of its procurement rules,246 and in March 2017, it also approved the financial package for Paks II.247 However, in February 2018 the Austrian Government challenged the validity of the decision.248 In November 2022, the European General Court ruled that because Hungary’s state aid for the Paks II project “concerns solely the costs of investment in two new reactors intended to replace the four old reactors […] and with no operating aid being foreseen, the effect on the energy market will only be limited.” The legal challenge had been supported by the Government of Luxembourg, while the Czech Republic, France, Hungary, Poland, Slovakia, and the United Kingdom stood with the European Commission.249 In April 2023, the Hungarian Government and Rosatom updated the delivery contract reportedly saying that “even without the war and sanctions ‘life and the technological situation have changed so much’” since the initial signature. Details on the contract remain confidential.250 According to the government, the amendments were approved by the European Commission in May 2023,251 allowing to speed up the process.252 An Engineering, Procurement and Construction (EPC) contract amendment was also signed by all parties in August 2023, thus concluding “the preparatory phase” of the project and allowing it to “move to the second phase, the actual physical construction phase”, according to Minister Szijjártó, with “the so-called first concrete moment to be realized by the end of [2024].”253

Opposition Against the Construction License for Paks II

In March 2017, the Hungarian Atomic Energy Authority (HAEA) issued the site license for the new construction.254 However, since then, there have been increasing concerns regarding the availability of cooling water given the warmer summer months and higher water temperatures of the Danube River, especially if both Paks I and II are in operation. During the Environmental Impact Assessment (EIA) process, the “proposed solution” to this problem was reportedly the temporary shutdown of the plant in such instances, which could affect the economics of the project and the grid balance.255

In addition, a 2021-report published by the Austrian Federal Environmental Agency found that the Dunaszentgyörgy-Harta seismic fault passes through the Paks II site. According to the report, the fault is both active and capable. The assessment concludes that “[t]he Paks II site should therefore be deemed unsuitable.”256 The Hungarian authorities, responding to the publication of the Austrian report, stated that the licensing process had not found any issues that indicated that the site was unsuitable.257 The licensing documents for the project remain confidential, prompting Hungarian independent news agency Átlátszó to sue for their release after having been denied access.258 Furthermore, the site is apparently located on soil that has an increased risk of liquefaction, necessitating preparatory counter measures on site.259

Process Continues Despite Concerns

On 30 June 2020, Paks II Ltd. submitted the construction license application to the HAEA. The regulator started its assessment procedure the next day and had 12 months to make its views known.260 That period was extended by an additional three months in May 2021.261 If all went according to plan, site preparation would have taken an additional 18 months, and formal construction would have started in mid-2022, some six years after the Hungarian and Russian Governments signed the corresponding intergovernmental agreements. That did not happen, and in October 2021, following IAEA feedback, HAEA announced that it needed more time “to fully verify all requirements,” without communicating an updated timeline.262

Despite the economy-wide sanctions against Russian companies, Paks II is proceeding, as nuclear energy is not subject to E.U. sanctions as of mid-2024. In June 2024, Hungary obtained the exclusion of Paks II from future E.U. sanctions, by making it the main condition for its government to approve the union’s 14th sanctions package against Russia, which targets the Russian LNG sector for the first time.263 In May 2022, following Rosatom reassurances, Hungarian authorities seemed confident that “in terms of technology they are able to complete the project.”264 In July 2022, the government announced that further site preparation licenses had been awarded by HAEA,265 and in August 2022, construction licenses for two new VVER-1200 reactors were granted.266

On 5 July 2023, Rosatom announced that work on building a groundwater cut-off had begun and onsite preparatory work was ongoing.267 In December 2023, project management reportedly indicated that the construction start of the first unit had been scheduled for March 2025, but could in fact start “ahead of schedule” by December 2024, a timeline that has since been officially maintained.268 However, there had already been even earlier announcements that construction was to begin in 2024.269 In April 2024, it was announced that the reactor pressure vessel of Unit 5 was being forged in St. Petersburg, Russia.270

There is conflicting information regarding the current planned completion date. Per a statement issued in April 2024, the to-be-operating company Paks II Ltd. plans to “connect the new units to the grid by the beginning of 2030,”271 while earlier reports suggested this for 2032272 or more vaguely at “the start of the next decade.”273 The announcement of an agreement regarding a non-published accelerated construction schedule also envisioned completion for “the early 2030s.”274 In 2014, the first unit had been scheduled to start up in 2023,275 a target that has been gradually pushed back over the years.

Despite the European Commission’s green light and the successful Hungarian obstruction of sanctions in the nuclear sector, the Paks-II project is facing some difficulties. For example, German company Siemens was supposed to deliver parts of control-command systems for Paks II jointly with French Framatome, but export grants, necessary due to dual-use legislation, were reportedly being withheld by the German Government in early 2023.276 As retaliation, the Hungarian Government threatened Siemens with the cancellation of other orders, e.g. for locomotives, and was seeking to focus on Framatome as major European supplier for nuclear plant components.277

Despite the ongoing war in Ukraine, the French Government actively supports the involvement of French suppliers in the Paks II project, arguing that “French nuclear industry players support our European partners, and in particular Hungary, in all their efforts and in all the projects on their soil as long as they strictly respect the European framework of international sanctions. To date, European sanctions [against Russia] do not target the nuclear industry.”278 French involvement is set to further increase as EDF, in late 2022, announced that an agreement had been reached to acquire GE Steam Power’s nuclear activities,279 whose subsidiary GE Hungary had won the tender to supply the turbines for Paks II in 2018.280 The acquisition was completed in May 2024.281

In March 2023, Szijjártó had suggested bringing Russian suppliers into the mix if Framatome failed to “take over leadership of the [Franco-German] consortium.”282 Reportedly, the Hungarian Government had been working on sidelining Siemens to cooperate solely with Framatome.283 However, when attending the opening of a new gas-turbine component manufacturing facility of Siemens Energy in late May 2024 in Budapest, Minister Szijjártó said, in a surprise announcement, that the company would indeed be delivering command-and-control equipment to the Paks II plant.284 Siemens neither confirmed nor denied this. After the announcement of the project’s exemption from future E.U. sanctions, Paks II CEO Gergely Jákli was quoted as saying in June 2024 that he was “certain that Siemens Energy will […] fulfill its contractual obligations,” albeit noting that Germany’s Federal Office for Economic Affairs and Export Control might still block the export.285 In late 2023, Siemens Energy Supervisory Board Chairman Joe Kaeser had warned of damages having to be paid to Rosatom if delivery contracts were to be broken.286 Other issues regarding the transportation of components, originally planned via Ukraine, the hiring of skilled labor, and the cooperation of German, French, and Russian workers put additional pressure on the Paks II project.287

Japan Focus

Overview

During Financial Year (FY) 2023, which runs from April 2023–March 2024, Japan operated 12 reactors with a capacity of 11.6 GW (gross).288 The average load factor for the entire Japanese nuclear fleet (including reactors not currently operating) has improved from 18.7 percent in 2022 to 28 percent in 2023 (calendar years).289 The total nuclear power generation increased by 49 percent, from 51.9 TWh in 2022 to 77.5 TWh in 2023, mainly due to the restart of two reactors. However, the share of nuclear power in the total power generation fell slightly from 6.1 percent in 2022 to 5.6 percent in 2023 (see Figure 37).290

1. Rise and Fall, and Slow Restart of the Japanese Nuclear Program

Sources: WNISR with IAEA-PRIS, 2024

The current reactor fleet consists of 33 units (33.1 GW gross) of which 25 units (24.8 GW gross) have applied for operating licenses under the new post-Fukushima regulations.291 So far, new licenses have been granted for 17 units while eight applications remain under review. The Nuclear Regulation Authority (NRA) did not issue any new operating licenses during the past year.

As of 1 July 2024, twelve reactors were in operation (Ikata-3, Genkai-3 & -4, Mihama-3, Ohi-3 & -4, Sendai-1 & -2, Takahama 1–4), of which one was shut down from 27 March to 3 June 2024 for periodic inspections (Genkai-4),292 and 21 reactors were in Long-Term Outage (LTO).293 In 2022, the IAEA adopted a new category called “Suspended Operation” to which it reclassified 21 reactors that WNISR considers to be in LTO. In other words, Japan and the IAEA have adopted an approach similar to the LTO concept that WNISR introduced in 2014. (See Figure 38).

Thirteen years after the Fukushima accidents were triggered, the reactors in operation are all Pressurized Water Reactors (PWRs) although five Boiling Water Reactors (BWRs), i.e., Kashiwazaki-Kariwa-6 & -7, Tokai-2, Onagawa-2, and Shimane-2, have passed NRA’s new regulatory requirements set in 2013.

1. Status of the Japanese Reactor Fleet

Sources: Various, compiled by WNISR, 2024

1. Age Distribution of the Japanese Nuclear Fleet

Sources: WNISR with IAEA-PRIS, 2024

As of mid-2024, the Japanese nuclear fleet consisting of 33 units including 21 in LTO had reached a mean age of 33.5 years, with 22 units over 31 years (see Figure 39).

Nuclear Power Plant Restarts and Earthquakes in Japan

The Noto Peninsula earthquake, which occurred on 1 January 2024, recorded magnitude 7.6 (maximum intensity seven based on the Japanese Meteorological Agency’s scale),294 and caused enormous damages in the area. The Hokuriku Electric Power Company-run Shika Nuclear power station, which has been shut down since 2011, was also affected. The plant’s transformers were damaged, and it lost external power supply, although the supplemental power lines remained operational; however, no serious damage immediately identifiable occurred at the plant.295 The actual cause of the damages to the transformers has not been identified yet.

The Shika Nuclear power station has two Boiling Water Reactors (BWRs). Shika-1 is relatively small with 505 MW (net) capacity, and Shika-2 has a reference unit capacity of 1108 MW.296 In the vicinity of the site, seven out of the eleven roads designated as evacuation routes in the event of a serious accident involving significant radioactivity releases were closed following the earthquake due to collapses and cracks.297 The effectiveness of the evacuation plan came into question (see Nuclear Energy in Japan in View of the Noto Peninsula Earthquake below).

On 27 December 2017, Tokyo Electric Power Co.’s (TEPCO) Kashiwazaki-Kariwa-6 and -7 became the first BWRs to pass the conformity test with the new regulatory requirements from NRA. The NRA decided at a meeting on 27 December 2023 to lift an administrative order that prohibited TEPCO from moving nuclear fuel or loading it into reactors after the company had committed nuclear security violations in 2021.298 TEPCO started fuel loading at the idled Unit 7 on 15 April 2024. All 872 nuclear fuel assemblies were transferred to the reactor by 26 April. It now needs the local governor’s approval to resume operation while residents are concerned about the effectiveness of the evacuation plan at the Kashiwazaki-Kariwa nuclear power plant in the aftermath of the Noto Peninsula earthquake.299

Tohoku Electric Power Co.’s Onagawa-2 will likely be the first BWR to resume operation since the Fukushima accidents started unfolding. It received the NRA’s official approval of conformity to new regulatory requirements on 26 February 2020, and work on outstanding safety measures was completed in May 2024.300 Operation is planned to restart in September 2024.301 Chugoku Electric Power Co.’s Shimane-2 received approval from NRA to restart operation on 15 September 2021 and from the local governor in June 2022.302 But in April 2024, because of delay in safety related work, Chugoku Electric Power announced that it will postpone the restart of operation until December 2024.303

Japan Atomic Power Co.’s (JAPC) Tokai-2 was the first BWR to get an extension (from 40 to 60 years) approval from NRA in November 2018, but currently the construction of a Specialized Safety Facility (SSF) against terrorist attacks is underway. Mamoru Muramatsu, president of JAPC said at a press conference in March 2024 that it would be difficult to complete the safety measures by September 2024 as planned.304

Kansai Electric Power Co. (KEPCO) owns the largest number of reactors (seven PWRs), all of which are currently operating (as of mid-2024). This is the first time in 15 years since February 2009 that all of KEPCO’s operational reactors are put into operation.305 Takahama-1 and Takahama-2 were restarted on 4 August and 20 September 2023, respectively, after NRA approved both reactors’ operating license extension from 40 to 60 years on 20 June 2016.306 On 25 April 2023, KEPCO applied for license extension beyond 40 years for Takahama-3 and -4. On 29 May 2024, they were granted a license extension of 20 years (from 40 to 60 years).307

On 22 January 2024, Takahama-1’s electric output was reduced to 40 percent due to a steam leak from a pump in the turbine building.308 Takahama-1 was shut down for regular inspection on 31 May 2024.309

Takahama-2 applied for a 10-year safety management plan, required under its operating license extension beyond 40 years, on 19 July 2024.310 Takahama-3 was shut down on 18 September 2023 for a periodic inspection. It resumed commercial operation on 23 January 2024.311 Takahama-4 was shut down on 16 December 2023 for a periodic inspection, during which steam generator tube damage was confirmed on 22 January 2024.312 It resumed power generation on 26 April 2024 and commercial operation on 21 May 2024.313

On 26 July 2024, the NRA in effect rejected JAPC’s request to restart Tsuruga-2, noting that it does not meet new safety rules established after the Fukushima nuclear accident. The main issue was whether the utility can prove there is no geological fault underneath the plant, and the NRA concluded that the utility’s explanation lacked concrete evidence to prove the absence of a fault.314

This is the first time the NRA effectively declined to approve a license application because it did not satisfy the new regulatory standards. JAPC’s Mamoru Muramatsu said that his company will conduct additional research and had not given up on restarting the unit.315

Kyushu Electric Power Co. applied for a 20-year license extension beyond 40 years for Sendai-1 and -2 on 12 October 2022. Their respective licenses would have expired on 3 July 2024 and 27 November 2025. The NRA approved the 20-year lifetime extension of both reactors on 1 November 2023.316

As no additional reactor has been declared for permanent closure during the past year, the total number of closed reactors remains unchanged at 27, including 21 units closed as a consequence of the Fukushima accidents (see Table 7 for details).

Legal Cases Against the Restart of Reactors

Various legal cases against the operation of existing reactors continue. The following are two key decisions made during the past year, both of which rejected local residents’ appeals for injunction to halt aging reactors.

On 15 March 2024, Osaka High Court rejected a petition to close Unit 3 of Kansai Electric Power Co.’s Mihama nuclear plant in Fukui Prefecture, reportedly saying that there would be “no concrete danger” that these reactors could trigger a serious accident. The petition was filed by seven residents of Fukui as well as nearby Shiga and Kyoto who claimed that “safety measures for the reactor, which has passed 40 years since becoming operational, are inadequate.” But the judge rejected such appeal, saying “no proper documents have been identified indicating that the faults could cause quakes involving major changes in the land surface.”317

On 29 March 2024, Fukui District Court rejected petitions to suspend operation of aging nuclear reactors at KEPCO’s Mihama and Takahama plants in Fukui Prefecture. Local residents claimed in the petitions that safety measures for Mihama-3 and Takahama-1 to -4 were inadequate. The plaintiffs claimed that the earthquake ground motions taken into account in the design basis for the Mihama and Takahama plants would be too low, considering past earthquakes observed in Japan. According to The Japan Times, “Presiding Judge Yasushi Kato pointed out that it is necessary to fully consider regional differences when evaluating earthquake ground motions, and found no problems with KEPCO’s survey or the Nuclear Regulation Authority’s (NRA) screening.”318

Reactor Closures, Spent Fuel Management, and HLW Disposal Plan

No additional reactors operating or in outage at the time of the Fukushima events were formally declared for decommissioning in the year to 1 July 2024. The eleven commercial Japanese reactors now confirmed to be decommissioned (not including the Monju Fast Breeder Reactor and the ten Fukushima reactors) had a total generating capacity of 6.4 GW, representing about 15 percent of Japan’s official operating nuclear capacity as of March 2011. Together with the ten Fukushima units, the 21 units totaled 15.2 GW or just under 35 percent of nuclear capacity prior to 3/11 (see Figure 38 and Table 7). In total, including units closed prior to 3/11, as of mid-2024, Japan has 27 closed reactors (27.1 GW) (see Japan in Decommissioning Status Report).

Regarding spent fuel management, on 24 April 2024, Chugoku Electric Power Co. began a drilling survey to investigate the geology of the planned construction site of an interim spent-fuel storage facility in Kaminoseki town, Yamaguchi Prefecture. Chugoku Electric Power Co. and KEPCO plan to apply for a construction permit from the municipal government if the site is found to be suitable and jointly build and operate the facility.319 The preselected site was originally chosen for the construction of a nuclear power plant, but Chugoku Electric suspended work on that in 2011 due to nuclear safety concerns following the Fukushima Daiichi disaster.320 In August 2023, the Kaminoseki municipal government permitted Chugoku Electric to conduct a survey for the construction of a joint storage facility.321

KEPCO was looking for a place to store spent nuclear fuel, but it was difficult to find one. As a condition for the operation of Mihama-3 and Takahama-1 and -2, which have been in operation for more than 40 years, the company promised the governor of Fukui Prefecture that it would finalize a candidate site for storage outside Fukui Prefecture by the end of 2023. The joint development with KEPCO was proposed by Chugoku Electric in place of constructing a nuclear power plant.322

At KEPCO’s three nuclear plants in Fukui Prefecture (Mihama, Takahama, and Ohi), storage pools for spent nuclear fuel are expected to be saturated over the next few years. According to a projection made by the Federation of Electric Power Companies in January 2024, the Takahama site will reach 100 percent of its operational capacity in only four years, while the Mihama and Ohi plants are expected to reach 90 percent and 98 percent of their respective spent-fuel storage capacities in five years.323

KEPCO had promised the prefecture to find a candidate site for a temporary dry storage facility by the end of 2023 and that should it fail to do so, it would halt operation of three aging reactors in Fukui Prefecture: Mihama-3, Takahama-1 and -2.324

On 12 June 2023, KEPCO told the Fukui Governor that the company plans to ship 200 tons of spent nuclear fuel from its Takahama plant to France in the late 2020s for demonstration purposes of reprocessing of spent MOX fuel by the early 2030s.325 However, while representing a large amount for a test, the 200 tons account for only about 5 percent of all spent nuclear fuel at Kansai Electric’s Takahama, Mihama, and Ohi nuclear power plants.326

In October 2023, KEPCO submitted the Roadmap for Spent-fuel Measures to Fukui Prefecture and its plan to build dry cask storage facilities at the three nuclear power plants. On 8 February 2024, KEPCO submitted to Fukui Prefecture and the municipalities of Mihama, Takahama, and Ohi the request to build storage facilities at all three sites. According to the plan, KEPCO is aiming at a total of about 2,000 tons of spent-fuel storage capacity by 2030.327 For KEPCO, securing an interim storage facility for spent fuel is a pre-condition for the operation of its reactors. On 15 March 2024, Fukui Prefecture approved Kansai Electric Power’s application to the central government for the installation of dry cask storage facilities.328

On 29 July 2024, Aomori Governor, Soichiro Miyshita, former Mayor of Mutsu City and son of late Mayor Junichiro Miyashita who decided to host an interim spent-fuel storage facility, agreed to sign the “Safety Agreement” with the Recyclable-Fuel-Storage Co. This opened the opportunity for Mutsu City to start accepting spent fuel from JAPC and TEPCO. In March 2025, TEPCO will start sending spent fuel from its Kashiwazaki-Kariwa plant to the Mutsu facility. This deal will bring the city more than ¥300 million (US$1.9 million) by March 2029 through a spent-fuel storage tax of ¥620/kg (US$4/kg).329

On 23 September 2023, the Mayor of Tshuhima City in Nagasaki, Naoki Hitakatsu, made it clear that the city will not accept a literature survey to determine whether it is suitable to host a final disposal site for high-level radioactive waste from nuclear power plants. He expressed concern that it may divide the citizens between “for” and “against” the plan.330 In addition, he was also concerned that the project may harm their tourism, agricultural, and fishing industries.

On the other hand, according to The Japan Times, on 10 May 2024, Mayor Shintaro Wakiyama of Genkai Town, Saga Prefecture said that the town would accept a literature survey, after the town assembly approved a petition by a local business group.331 On 10 June 2024, NUMO (Nuclear Waste Management Organization) started the survey in Genkai Town.332 After the town of Suttsu and the village of Kamoenai, both in Hokkaido Prefecture, Genkai has become the third municipality in the country to accept such a survey, the first step in the process of selecting a final disposal site. Genkai Town is also host to Kyushu Electric Power’s Genkai nuclear power plant, and it is the first municipality to accept a literature survey for HLW disposal. In order to facilitate literature surveys, the central government provides up to ¥2 billion (US$12.8 million) over two years to municipalities accepting a survey.333

1. Official Reactor Closures Post-3/11 in Japan (as of 1 July 2024)

Sources: JAIF and JANSI, compiled by WNISR, 2024

Notes: This table only lists the 22 reactors closed after the Fukushima accidents, thus not including the Fugen Advanced Thermal Reactor (ATR), Japan Power Demonstration Reactor (JPDR), as well as Hamaoka-1 & -2 (Chubu Electric Power) and Tokai-1 (JAPC).

BWR: Boiling Water Reactor; PWR: Pressurized Water Reactor; FBR: Fast Breeder Reactor; LTS: Long-Term Shutdown (former IAEA category).

JAPC: Japan Atomic Power Company; JAEA: Japan Atomic Energy Commission.

(a) – Unless otherwise specified, all announcement dates from JANSI, “Licensing status for the Japanese nuclear facilities”, Japan Nuclear Safety Institute, as of 15 September 2023, see http://www.genanshin.jp/english/facility/map/, accessed 13 July 2024.

(b) – Unless otherwise specified, all closure dates from individual reactors’ page via JAIF, “NPPs in Japan”, Japan Atomic Industrial Forum, as of 13 July 2024, see http://www.jaif.or.jp/en/npps-in-japan, accessed 13 July 2024.

(c) – Note that WNISR considers the age from first grid connection to last production day.

(d) – The Mainichi, “Japan decides to scrap trouble-plagued Monju prototype reactor”, 21 December 2016.

(e) – The Monju reactor was officially in Long-Term Shutdown or LTS (former IAEA-Category) since December 1995. Officially closed in 2017.

Nuclear Energy in Japan in View of the Noto Peninsula Earthquake

The Noto Peninsula earthquake, which occurred on 1 January 2024, recorded magnitude 7.6 and caused enormous damage to the local community. Hokuriku Electric Power Company’s Shika nuclear power station, which had been shut down since 2011, was also affected. Impacts included damaged transformers and external electricity supply interruption. The earthquake-induced events in this power plant once again highlight the particular problems of nuclear energy use in Japan.

The main issue is that the shaking exceeded anticipated levels, including in the vicinity of the Shika nuclear power plant. The recorded earthquake exceeded the “current reference seismic motion” of 600 gal for an instant (0.47 second) but remained below the reference seismic motion of 1,000 gal that the plant was to be protected against based on the new regulatory standards of 2014.334

Due to the earthquake’s impact, two external power supply transformers for Units 1 and 2 at the Shika plant were damaged. Specifically, one transformer for Unit 2 was reported to have leaked approximately 19,800 liters of oil, although it was originally reported to be 3,500 liters, rendering that portion of the external power supply system inoperable.335 Initially, the NRA said there was no safety problem as other power supply lines remained operable,336 but an NRA committee member stated that the magnitude of the earthquake was extremely large and that the results of further expert research on the quake must be used in future assessments.337

Another serious problem is the approach to evacuation of residents when serious accidents occur. In the vicinity of this nuclear power plant, eleven national highways and prefectural roads have been designated as evacuation routes in the event that serious accidents such as leakages of radioactive substances occur. Of those, seven routes were closed following the Noto Peninsula earthquake due to collapses and cracks. The events placed doubts on the effectiveness of the evacuation plan. Reportedly, NRA is considering a “review of the guidelines”.338

In the wake of the Noto Peninsula earthquake, ongoing discussions to restart TEPCO’s Kashiwazaki-Kariwa nuclear power plant were met with concerns in the Niigata Prefecture, where local governments questioned the effectiveness of the evacuation plan in the event of a complex disaster such as a major earthquake. 339

The administration of evacuation plans in case of a nuclear accident in Japan is characterized by a dual system. The NRA establishes guidelines for evacuation plans but has no legal authority to approve specific plans as they are not covered by the licensing process. The local governments (town, villages, and prefecture) which host nuclear facilities prepare their own evacuation plans, which the Cabinet Office eventually approves but does not take responsibility for. Therefore, even if questions arise about the effectiveness of a given plan, as is the case in the aftermath of the Noto Peninsula earthquake, it is unclear who is responsible for leading a review of the disaster prevention plan.340

New Energy Policy and the Role of Nuclear Power

For Japan, 2024 is the year in which the Seventh Strategic Energy Plan will be formulated, and the role of nuclear power generation will be redefined. The current Sixth Strategic Energy Plan was approved by the Cabinet in October 2021, and the Energy Policy Basic Law mandates a review of the plan every three years or sometime within a year or so.

The central purpose of the Seventh Strategic Energy Plan will be to demonstrate a course of action toward the realization of carbon neutrality by 2050 and the reduction of greenhouse-gas emissions (GHGs) by 46 percent compared to 2013-levels by 2030. According to the 2030-target described in the Sixth Strategic Energy Plan, the respective shares of total generated electricity by power source are as follows: 36–38 percent renewable energies, 20–22 percent nuclear power, 20 percent LNG, 19 percent coal, about 10 percent hydrogen and ammonia, and 2 percent oil.341

On 31 May 2023, Japan’s parliament passed the so-called “GX Decarbonization Power Supply Bill”—GX stands for Green Transformation—which includes amendments of the Nuclear Reactor Regulation Law, the Electricity Utility Industry Law, and the Atomic Energy Basic Law. Those three laws define the main feature of the new policy: Extension of the “licensing period” (until then generally 40 years and 60 years for exceptional cases) allowing operators to apply for an extension that takes into account “certain shutdown period due to ‘non-technical’ or ‘unplanned’ reasons”, typically a part of the post 3/11 shutdown periods. This has become one of the most controversial aspects of the GX Basic Policy, because the licensed operational lifetime limitation was introduced after the Fukushima accidents.342

In addition, the development of innovative light-water reactors, Small Modular Reactors (SMRs), fast reactors, and even nuclear fusion reactors, is also included in the GX implementation plan. The plan envisages the replacement and/or construction of new reactors for the first time since the Fukushima nuclear accidents. This is a major change from the current policy under the Strategic Energy Plan which says, “Japan will reduce the dependence on nuclear energy as much as possible.” The new policy also emphasizes the unstable energy situation caused by the war in Ukraine. Securing a stable energy supply is thus mentioned as a major driver to promote nuclear energy.343

The Strategic Policy Committee, under the Ministry of Economy, Trade and Industry’s (METI’s) Advisory Committee for Natural Resources and Energy is expected to lead discussions around the Seventh Strategic Energy Plan, as the METI Minister is in charge of the Plan.344 To further promote the shift to decarbonized energy sources and to guarantee energy security, the transition to renewables-based electricity will be accelerated and nuclear energy is expected to be re-emphasized.

On 28 March 2024, following the Diet’s approval of the FY2024 budget, the prime minister Fumio Kishida stated that “We must change the present situation, wherein Japan imports energy and tens of trillions of yen flow out overseas. In order to shift to an energy system that contributes both to decarbonization while increasing the capability of domestic firms to earn profits, the implementation of a national strategy is absolutely necessary.” Kishida announced his intention to start discussions toward revising the Strategic Energy Plan to be complemented by the GX National Policy.345

On 3 May 2024, Mr. Kingo Hayashi, President of Chubu Electric Power and Chairman of the Federation of Electric Power Companies (FEPCO), requested for the new Strategic Energy Plan “to create an environment that allows for the construction, replacement (rebuilding), and expansion of nuclear power plants.”346

On 13 May 2024, the Japanese Government’s GX Implementation Council, which was held for the first time in five months, presented its plan to “integrate activities for decarbonization and fundamental economic reform” and to issue a national strategy labelled the “GX 2040 Vision.” By setting out a long-term outlook of the energy policy, the government aims to make it easier for companies to make investment plans. In preparation for investment projects that consume large amounts of electricity, such as data centers, it will compile measures to expand “decarbonized power sources.”. The GX 2040 Vision will be reflected in the Strategic Energy Plan.347

On 15 May 2024, at the sub-committee on basic policy of its Advisory Council on Energy and Resources, METI published its policy to allow for the replacement of existing reactors on a given site.348 This is the first time that METI defines its policy change to move towards newbuild since the Fukushima nuclear accidents.

Prospects for Nuclear Power

The new nuclear energy policies introduced under the GX Transformation laws represent a major shift as they allow for the construction of new reactors. They also amend the nuclear regulation laws to allow for lifetime extensions beyond 60 years. These new policies, which aim to maximize the use of nuclear power, are in fact inconsistent with the policy to “reduce the dependence on nuclear power as much as possible” as stated in the current Strategic Energy Plan.

A recent public-opinion survey suggests that support and opposition of restarting nuclear power plants are evenly divided,349 in some polls, support outweighs opposition, and vice versa. Last year, support for the restart of existing reactors exceeded opposition to restarts for the first time since 3/11. However, some surveys suggest that the Noto Peninsula earthquake in January this year may have affected residents’ perception of the safety of nuclear power generation. 350 It remains unclear how these new policies would change the conditions for utilities to restart reactors, and it is even less certain what the impact on the potential construction of new reactors could be. In addition, many issues associated with the decommissioning of the Fukushima Daiichi reactors remain unresolved (see Fukushima Status Report). Also, legal cases against reactor restarts and in favor of compensation for the impact of the Fukushima disaster continue. In short, the future of nuclear power in Japan is still far from certain.

Regarding activities around nuclear construction sites, on 13 May 2024, Chugoku Electric Power Co. announced that it aims to start operation of Unit 3 of the Shimane Nuclear Power Plant by FY2031. The company now aims to complete the implementation of safety measures by “approximately FY2029”, when the previously announced target was the first half of FY2026.351 Reportedly, in April 2024, Chugoku Electric Power had indicated that the target for commissioning was FY2030, marking the first time that the company had publicly specified when it intends to start operating Shimane-3.352

The Ohma Nuclear Power Plant (Aomori Prefecture) was designed to be the world’s first commercial reactor to run with a full MOX core (uranium-plutonium mixed oxide fuel), with one of the largest power capacities in Japan at 1383 MW. The owner, J-POWER, aims to start operations in 2030, but the NRA, which was created only in December 2014, has been reviewing the plant for a long time. The issuance of the updated construction license, prerequisite for the start of activities, has been postponed five times.353 The latest deferral being when J-POWER announced in 2022 that they rescheduled the construction resumption to the latter part of 2024, due to delays in the licensing process.354

The Netherlands Focus

The Netherlands operates a single, over 50-year-old 482-MW PWR at Borssele—the oldest in the E.U.—that provided 3.8 TWh of electricity in 2023, just below the previous historic maximum of 4.0 TWh in 2009. This corresponded to 3.4 percent of the country’s electricity, compared to the historic maximum of 6.2 percent in 1986, when the country also operated a 60-MW BWR at Dodewaard.

The Dodewaard unit operated from 1968 to 1997. Since April 2003, all the spent fuel has been removed, and the site entered its 40-year safe enclosure period in June 2005, after which the plant is to be dismantled355 (see Decommissioning Status Report).

While Borssele’s operating license is valid for an indefinite period, its initial safety report covered a 40-year operational lifetime, equating to the closure of the plant in 2013, but in late 2006, the owner, its shareholders, and the Dutch Government reached an agreement, formalized as the “Borssele Covenant”, to allow the operation of the reactor to continue until 31 December 2033 provided certain conditions are met.356 Amongst these conditions were enforced actions that Borssele “remain […] amongst the 25% safest water-cooled and water-moderated power reactors in the E.U., the US, and Canada” and that then-shareholding utilities Delta and Essent invest over €100 million (US$2006125.6 million) each into “sustainable energy management policies” and “additional innovative projects.”357 Today, Borssele is owned and operated by the Dutch nuclear utility Elektriciteits Produktiemaatschappij Zuid-Nederland (EPZ), which is co-owned by PZEM (70 percent) and German utility RWE (30 percent) via Energy Resources Holding (ERH).358

In July 2023, the conservative coalition government of Prime Minister Mark Rutte collapsed over disagreements on migration policy, and a snap election was called for November. Rutte withdrew from Dutch politics after the incoming administration took over and was appointed Secretary General of NATO in June 2024.359 The election was won by far-right party Partij voor de Vreijheid (PVV) on an anti-immigration agenda, that, spear-headed by its leader Geert Wilders, announced on 16 May 2024 that it had reached an agreement to form a new coalition with Rutte’s center-right party Volkspartij voor Vrijheid en Democratie (VVD), centrist party Nieuw Sociaal Contract (NSC), and so-called right-wing “Farmers’ Party” BoerBurgerBeweging (BBB).360 The agreement explicitly excludes Wilders from becoming Prime Minister, resulting in Dirk Schoof, a senior official of the Ministry of Justice and former head of the Dutch intelligence service, being presented as a compromise outside of party politics at the end of May 2024.361 The new government under Prime Minister Schoof was sworn into office on 2 July 2024. Government plans on how to implement “a clampdown on immigration and exceptions on EU asylum and environmental rules” are to be presented in September.362

Regarding energy policy, the new government will increase its focus on offshore gas extraction and nuclear power, possibly exceeding the previous government’s ambitions to increase the share of nuclear power in the coming decades.363 There are ongoing evaluations regarding several newbuild options, including both large reactors as well as Small Modular Reactors (SMRs).

For the only operational reactor at Borssele, the possibility of further lifetime extensions had already been discussed by EPZ in November 2020. The idea was to extend the operational lifetime from 2033 by another 10 or 20 years.364 As current legislation prohibits the regulator to even consider an application for further prolonged operation at Borssele,365 in 2020 the Dutch Parliament decided to inquire into the legislative changes required to allow a lifetime extension366 Further operation of Borssele would require the amendment of the Nuclear Energy Act and the Covenant, as well as a license renewal to update underlying safety report forms.367

In December 2022, operator EPZ applied for a grant to conduct technical feasibility studies on the operation of Borssele beyond 2033.368 The up to €11.3 million (US$12.2 million) state aid to EPZ was approved by the European Commission in October 2023,369 prompting the acting Dutch Energy and Climate Minister Rob Jetten to approve the feasibility study of Borssele’s lifetime extension in December 2023. 370 An initial advance of €2 million [US$20232.2 million] was paid, while the remainder will be spread annually until 2033, when the current operational license of Borssele is due to end.371 Additionally, in its draft agreement, the new coalition states that Borssele “will remain open,”372 and in June 2024, while acknowledging that legislative amendments and further feasibility studies were necessary, acting Energy Minister Jetten called for the extended operation of Borssele beyond 2033 in a letter to Parliament. Additionally, he openly considered government purchase of a stake of EPZ to support the financing of this proposed lifetime extension.373

Until recently, nuclear newbuild was not considered a realistic option to decarbonize the Dutch energy system after Delta—then majority shareholder of EPZ— had put plans on ice “for at least two years” in 2012 (see previous WNISR editions).374 While the 2016 Energy Report assessed that “under the current market conditions, there is no demand for a new nuclear power plant, however the cabinet does not rule out new nuclear technologies being deployed in the future, as long as they are safe,”375 the 2019 Integrated National Energy and Climate Plan 2021-2030 mentions that “a number of studies reveal that for 2050, nuclear power could be a cost-effective option and that a positive business case could be one of the long-term options. Given the lead times, additional nuclear power for 2030 does not seem likely in the Netherlands.”376 The plan targeted a 100-percent renewable electricity generation by 2050 with offshore wind delivering the lion’s share.

In recent years however, the Dutch Government has been drawing closer attention to the possibility of continuing nuclear production beyond 2033. A few weeks after the publication of an Enco report on 1 September 2020, the then Minister of Economic Affairs and Climate Policy, Eric Wiebes—whose party, VVD, “want[ed] up to 10 new nuclear plants to be built” at the time—informed Parliament of the findings and the launch of procedures to allow a market consultation on nuclear newbuild.377 The study concluded that nuclear “could play an important role in the future energy mix of the Netherlands” and argued that both large units and SMRs would be “cheaper” than renewable technologies.378

Another study commissioned by Minister Wiebes from Berenschot and Kalavasta concluded, on the contrary, that “nuclear energy is more expensive, except when nuclear power always takes precedence over the electricity grid and the government assumes a large part of the financial risks” as summarized by Nuclear Engineering International (NEI).379

In addition to its lifetime extension propositions made in 2020, EPZ also suggested newbuild as an option. According to the proposal, the government would have to invest in the construction of new nuclear reactors, the favored option being two Generation-III+ reactors of around 1.5 GW capacity each, increasing the currently installed capacity sixfold. This capacity would correspond to the European Pressurized Water Reactors (EPR) or the South Korean Advanced Pressurized Water Reactors (APR), “safe and reliable” technologies according to EPZ.380 For this project, EPZ envisioned costs of €8–10 billion (US$20209.1–11.4 billion) and a construction duration of eight years per reactor, “if the project is properly implemented.”.381

In a 2021 market consultation, commissioned by the House of Representatives prior to the last Rutte administration taking office, consulting firm KPMG stated that “private financing without extensive government guarantees would be difficult or impossible to achieve [as] a large nuclear power plant is too big an investment for many private investors, and has too long a horizon.” 382 The report further states that “proven” technologies of Generation III+ designs, such as the EPR or APR would limit first-of-a-kind (FOAK) cost risks in comparison to implementing a completely new reactor design. Russian and Chinese technologies were placed “out of scope” at the request of the Ministry of Economic Affairs, thus pointing to EDF, Westinghouse, and KEPCO as “obvious options”. Nonetheless, without consensus on the “best” design, and given that “a choice can only be made once a sufficient number of projects have actually been completed”, it was expected that a choice would only be possible by 2023.

In late 2021, the Dutch Government followed EPZ’s original proposal in their coalition agreement. An undefined lifetime extension for Borssele and the construction of two new reactors were included in the official governmental plans. A total of €5 billion (US$20215.9 billion) was planned to be spent by the state until 2030 to facilitate the construction of the new plants.383

Dutch newbuild plans took a new turn in December 2022, when it was announced that two reactors would be built near the Borssele plant with the government as co-investor. The plan is to begin construction in 2028 and complete both units by 2035 thanks to an “accelerated approach”.384 A second consultation issued by KPMG in February 2023, tasked with identifying financing options for newbuild confirmed that state involvement is considered indispensable and concluded that, in the Dutch context, existing financing schemes would have limited applicability. The KPMG study also stated that “market parties” expected a role for the government to limit licensing and political risks, and advance agreements on setting up a decommissioning fund. Construction duration was estimated at 11 to 15 years, calling the Dutch Government’s envisioned “accelerated approach” into doubt.385

Meanwhile, Dutch company NRG Pallas, active in nuclear medicine and operator of the High Flux research Reactor (HFR) at Petten, and Belgian nuclear engineering company Tractebel, a subsidiary of the utility Engie, signed a Memorandum of Understanding in March 2023 to “cooperate to support the new-build of nuclear power plants in the Netherlands.”386

On 12 April 2023, then Minister for Climate and Energy Rob Jetten renewed his pledge to stick with the coalition agreement of 2021 despite disagreement from the “Expert Team Energy System 2050”, which he had appointed to outline recommendations for the country’s Energy System Plan 2050. 387 In its report, submitted on the same day as the Minister’s remarks, the team sees “no or a limited role” for nuclear power in the Dutch energy system and emphasized that new nuclear capacity would only be necessary if the Netherlands doubled or even tripled its current electricity demand and neighboring European countries started importing electricity from the Netherlands. They further questioned the possibility of having a new reactor online before 2040 and the potential choice of Borssele as a possible location for new capacity—as this could lead to system overload from the large amount of wind farms located nearby—all while noting that they had drawn their conclusion on nuclear power from other studies.388 Minister Jetten indicated that the “final decision” on new nuclear capacity would be made towards the end of 2024.389

However, at the end of April 2023, the former administration stated its intent to reach a carbon-neutral electricity system by 2035 with nuclear mentioned as a potential contributor of up to 10 percent of the mix if two new reactors were built. Emphasis on SMR technologies in the statement contradicts the assumption of just two plants providing such a large portion of electricity.390 Given the long lead time of nuclear newbuild in planning and construction experienced in other countries, it seems unlikely that the plans can be implemented in the targeted timeframe.

Dutch new nuclear policy gained further momentum when, also in April 2023, approx. €320 million (US$2023346 million) were allocated to nuclear-associated funds in the draft document for the 2024 climate budget.391 These expenditures exceed the planned budget of the 2021 coalition agreement by €199 million (US$2023215.2 million). Included are €10 million (US$202310.8 million) for studies spanning from 2023 to 2025 on lifetime extension at Borssele and an additional €62 million (US$202367 million) for the local municipality and the province of Zeeland for efforts regarding newbuild projects and continued operation at Borssele. Further €117 million (US$2023126.5 million) are allocated to newbuild feasibility studies and €65 million (US$202370.3 million) are to be spent on the development of knowledge and training of nuclear industry staff for the future operation of Dutch nuclear power plants.392

In December 2023, the Dutch Government announced that Korea Hydro & Nuclear Power (KHNP) had been contracted to carry out a technical feasibility study on the construction of two reactors at Borssele—expected to span at least six months starting in January 2024—with similar contracts with Westinghouse and EDF to follow “soon”. On that occasion, the Dutch and South Korean Governments signed an MoU to “cooperate on nuclear energy”.393 In February 2024, Westinghouse followed with the announcement that it was also to conduct such a study for two AP-1000s, without divulging an estimated timeline.394 However, according to The Wall Street Journal “Westinghouse said it learned from its U.S. experience during the 2010s and no longer takes on reactor construction.”395 That suggests that Westinghouse would provide the technology but not act as the main builder-contractor, who then remains to be identified.

As of June 2024, no contract with EDF had been made public. The government envisions a final site selection in 2025 as a second location, in addition to Borssele, might still come under consideration.396

In March 2024, the “Tweede Kamer”, the lower house of the Dutch Parliament, adopted a resolution to extend newbuild plans from two to four new reactors.397 The incoming government, in addition to the lifetime extension of the operational Borssele plant, indeed envisions the construction of four new nuclear power plants.398 According to the coalition agreement, funding is to be increased from the current €4.5 billion to €14 billion (US$4.9 to US$15 billion), most of which is to be spent in the 2030s, by which time another policy shift might have happened.399

In the outgoing government’s multi-annual climate fund budget, published in October 2023, an additional €65 million (US$202370 million) were earmarked for 2025 for the development of SMRs in the Netherlands.400 In August 2022, Amsterdam-based ULC-Energy and British Rolls-Royce signed an exclusive agreement to cooperate on Dutch SMR development. ULC-Energy hopes to apply for a license for its reactor in 2025, envisioning construction to begin in 2027.401 In November 2023, Rolls-Royce signed an MoU with Dutch construction company BAM “to explore the opportunities for collaboration to support deployment of Rolls-Royce SMRs in the Netherlands.”402 The previously mentioned July 2021 KPMG report had considered SMRs as an “interesting option” to market parties but suggested waiting until “any FOAK issues have been resolved” to identify successful projects, deeming the start of such a process impossible before 2027–2033.403 Moreover, in March 2024 acting Energy Minister Jetten in a letter to the “Tweede Kamer” acknowledged that there was, as of today, no SMR concept ready for deployment, while describing steps taken to prepare the potential deployment of SMRs in the future.404

Today’s electricity mix in the Netherlands is dominated by natural gas, which supplied 37.7 percent of total electricity, 122.15 TWh (gross), in 2023. Wind energy (23.7 percent) and solar (17.3 percent) are next, followed by coal (6.9 percent) and bioenergy (6.8 percent). The contribution of “other fossil fuels” at 4.2 percent exceeds the nuclear share at 3.3 percent of total electricity generation.405

Renewables had strong growth rates in 2023 with wind turbines generating 35 percent and solar panels 24 percent more power than in the previous year. The Dutch National Energy and Climate Plan from June 2023 expects the share of renewable energies in gross electricity consumption to increase from 33.4 percent in 2021 to 86.2 percent in 2030 and 95.5 percent in 2040 (raising questions about the envisioned nuclear plans). This development is to be driven by the expansion of wind and solar power. The plan envisions capacity expansions of 28.3 GW for wind power by 2040, of which 21.2 GW are planned as offshore capacity.406 2023 marked the milestone of exceeding 10 GW of installed wind power, of which nearly 2 GW had been installed in the year including 1.4 GW offshore.407 Solar is expected to grow from 23.9 GW at the end of 2023 to 42.6 GW by 2040.408 The target seems realistic as in 2023 alone, solar capacities increased by 4.3 GW. In the E.U., the Netherlands lead the charts on installed solar capacity per capita at 1.3 kW, followed by Germany (0.9 kW) and Belgium (0.7 kW).409

Poland Focus

For many decades, Poland has been planning the development of nuclear power plants. In the 1980s, construction of two VVER1000/320 reactors began in Żarnowiec on the Baltic coast, but both construction and further plans were halted following the Chornobyl accident in 1986.410 Since then, there has been a long, expensive, and time-consuming series of attempts to restart the program. Refer to previous WNISR editions for a more detailed account of these various attempts, of which only the most recent ones are discussed below.

For example, in 2008, Poland announced that it was going to re-enter the nuclear arena.411 In the “Polish Energy Policy until 2030”, published in 2009, it was assumed that by 2030 three nuclear units (4.8 GW) would generate “over 10 percent” of the country’s electricity, with the first unit put into operation “no[t] sooner than in 2020”.412 Five years later, the Polish Government adopted the Polish Nuclear Power Programme. The plan included proposals to build 6 GW of nuclear power capacity at an estimated cost of PLN40–60 billion (US$201413–19 billion), with the first reactor starting up by 2024 and two units operating by 2035. A contract was to be concluded and a first site named by 2016.413 That did not happen.

Instead, by January 2016, state-owned utility Polska Grupa Energetyczna’s (PGE’s) subsidiary PGE EJ1, which had been set up for the construction and operation of a nuclear power plant,414 applied to the General Directorate for Environmental Protection (GDEP or GDOŚ) to launch Environmental Assessment procedures at Lubiatowo-Kopalino and Żarnowiec, both close to the Baltic coast in the northern province of Pomerania.415 In March 2017, environmental and site selection surveys started at both sites.416

Following this, in November 2018, the government published a draft strategic energy development program, which called for the construction of up to four reactors (providing 4–6 GW of capacity) by 2040, with the first in operation by 2033, and another two reactors by 2043, bringing total nuclear capacity to 6–9 GW.417 In May 2019, the Ministry of Energy envisaged the site selection for the first plant in 2020 and technology selection the following year.418

In October 2020, the Council of Ministers adopted a revised long-term Polish Nuclear Power Programme.419 It maintained the objective to build and commission nuclear power plants in Poland with a total installed capacity of approximately 6–9 GW based on Generation III (+) pressurized water reactors, with the start of operation during the 2030s, while the share of nuclear power in the electricity mix was predicted to reach about 20 percent by 2045.420

In the same month, the U.S. and Polish Governments signed an agreement on the “cooperation towards the development of a civil nuclear power program and the civil nuclear power sector in […] Poland.” The agreement includes cooperation plans on the development of financing regulations and schemes, technological knowledge transfer, and the “development, construction, and financing of the first [nuclear power plant] project, intended to be operational during 2033.” The agreement came into force in February 2021.421 In June 2021, a first grant was issued by the U.S. Trade and Development Agency to fund a front-end engineering and design study for Polskie Elektrownie Jądrowe (PEJ).422

PEJ is the direct descendant of PGE EJ1. In March 2021, the four owners PGE (70 percent of shares), Enea, Tauron, and KGHM (10 percent each) sold ownership to the Polish State Treasury “‘in preparation for realisation’ of the Polish nuclear power programme.” Negotiations had begun in October 2020, and the transaction cost the Treasury around PLN531 million (US$2021137.5 million).423 In June 2021, “PGE EJ1” was renamed “Polskie Elektrownie Jądrowe”, or “PEJ”.424

The Pomeranian Project

In late December 2021, PEJ announced it had chosen the village of Choczewo in Pomerania for the first reactor.425 Bids for the construction of the first Polish nuclear power plant were submitted between October 2021 and September 2022. They consisted of Korea Hydro & Nuclear Power’s (KHNP’s) proposal to build six APR-1400s (8.4 GW) for US$26.7 billion, Westinghouse’s proposal to build six AP-1000 (6.7 GW) for US$31.3 billion, and EDF’s preliminary offer of four to six EPRs (6.6–9.9 GW) for US$33–48.5 billion.426

Despite its bid costing more for less capacity, Westinghouse was formally appointed in November 2022 to deliver three reactors to the Pomeranian project at a price of around US$20 billion.427 Four East German states (Brandenburg, Saxony, Mecklenburg-Vorpommern, and Berlin) opposed the project during the consultation period of the Environmental Impact Assessment (EIA) process.428 Nonetheless, cooperation agreements were signed between Westinghouse and PEJ in December 2022.429 These were further advanced when in February 2023, a contract covering front-end engineering, early procurement work, and program development was signed between Westinghouse and PEJ.430 On 13 April 2023, PEJ applied to the Ministry of Climate for a “decision-in-principle” on the project,431 which was granted in July 2023, allowing for further administrative applications to proceed.432 In September 2023, Westinghouse, PEJ, and Bechtel signed an 18-month Engineering Services Contract (ESC) that shall provide, by the end of the period, the design documentation for the first nuclear plant in Poland.433 At this stage, construction work was planned to begin in 2026, with electricity generation to commence in 2033.434

In the meantime, general elections have resulted in a Polish leadership change with the nationalist party “Law and Justice” (Prawo i Sprawiedliwość, PiS) losing their mandate and being replaced by a pro-European, center-right government under Donald Tusk, who had already been Polish Prime Minister from 2007 to 2014. The new cabinet was sworn into office in December 2023.435 While clearly in favor of nuclear power, before the election, Tusk reportedly agreed that the Polish nuclear power construction plan was “not based on a robust economic analysis and lacks a business plan.”436 The new administration announced that it was considering the implementation of a “Contracts for Difference” scheme together with the European Commission to “efficiently develop a business and financing model”,437 and also prompted an investigation into whether the target of first nuclear operations by 2033 was still achievable. New Climate and Environment Minister Paulina Hennig-Kloska said in February 2024 that the government doubted the ambitious target was achievable given the substantial delays that had already occurred during the previous government’s legislative period.438 Industry Minister Marzena Czarnecka stated in a radio interview in May 2024 that the earliest completion date of the Pomerania project would be in 2039 or 2040.439 She also pointed out that the preceding government had been overly optimistic “without having much on the table”.440 After concerns were raised that the delay could lead to “an energy disaster”, Czarnecka reiterated her statements saying that the target date of 2039 or 2040 referred to the whole plant’s completion and that the first reactor was to come online by 2035 with construction to begin in 2028.441

The Polish Government seems to remain committed to the plant being built, with Deputy Climate and Environment Minister Meciej Bando affirming there was “a clear decision” to pursue, and that there was “no way today for us [the Polish Government] to stop the nuclear project.”442 In April 2024, PEJ’s authorized representative Jan Chadam said that the final cost of the project was still not confirmed, but that current estimates now ranged at around PLN150 billion (US$ 37.9 billion),443 a 90-percent increase over the figure indicated in November 2022.444 In a meeting with Westinghouse CEO Patrick Fragman in April 2024, Minister Hennig-Kloska emphasized “the importance of timely project implementation” while reiterating nuclear’s essential role in her country’s future energy mix.445

The distribution of roles in the project—especially that of Westinghouse—remains unclear. In early June 2024, the Wall Street Journal reported: “Westinghouse said it learned from its U.S. experience during the 2010s and no longer takes on reactor construction. (…) In Ukraine, Westinghouse said Energoatom will be responsible for construction of the new reactors [...]”446 In Bulgaria, South Korean company Hyundai is the main contractor, and Westinghouse is providing the technology and engineering. In Poland, Westinghouse has partnered up with U.S. construction giant Bechtel and the Polish state-owned PEJ, but who will actually sign up as the project management entity remains unclear, just as the financing package is yet to be established.

The Łódź Project

In parallel to the developments in Pomerania, in April 2022, KHNP submitted a bid for six APR-1400 reactors with a total of 8.4 GW and a first grid connection scheduled for 2033 in Pątnów, in the Łódź region of central Poland, at the site of a lignite power plant.447 Polish utility Zespół Elektrowni Pątnów-Adamów-Konin (ZE PAK), PGE, and KHNP signed a letter of intent in October 2022 to develop plans for the project. On the same day, Poland’s then-Minister of Assets, the former Deputy Prime Minister, and South Korea’s Minister of Trade, Industry and Energy also signed an MoU “to support the nuclear energy project in [Pątnów] and tighten cooperation in the scope of necessary information exchange.”448

This nuclear plant would constitute the second phase of the 6–9 GW nuclear capacity deployment envisioned in Poland’s 2021 Nuclear Power Program. The project might come under E.U. investigation due to possible noncompliance with competition regulation that requires multiple equally treated bidders to be allowed to compete for such large infrastructure projects.449 Regardless, ZE PAK and PGE announced in March 2023 that they would establish a joint venture to “represent the Polish side at all stages of the [Pątnów] project”, then planned with at least two APR-1400 reactors to be delivered by KHNP and scheduled to be on the grid by 2035.450 In April 2023, the 50-50 joint venture, named PGE PAK Energia Jądrowa, was established. In August 2023, it applied to the Polish Ministry of Climate for a “decision-in-principle” for two APR-1400 reactors,451 which was granted in November 2023 by the acting Ministry of Climate and Environment, as it considered the project to be “in line with the public interest and the policies pursued by the state.” This approval marks a first step in the Polish licensing process for nuclear facilities.452

Investment decision “very far away”

In January 2024, KHNP president Jooho Wang visited Warsaw for the grand opening of a three-person office. He announced that an agreement for a feasibility study for the project was to be signed by the end of March 2024 and that the financing scheme and EIA would conclude by 2025, allowing for an “ambitious but achievable” beginning of commercial operation of the first reactor by 2035.453

In late May 2024 however, ZE PAK president Dariusz Marzec said that the company was “very far away” from making an investment decision, given that the currently ongoing pre-feasibility studies would require several years to conclude. To begin with, the above-mentioned commissioning of a full-scale feasibility study had not happened.454

In an apparent attempt to force a legal declaration that KHNP’s bid is based on Westinghouse technology, Westinghouse filed a lawsuit against KHNP and its owner Korea Electric Power Corporation (KEPCO) before the U.S. District Court for the District of Columbia455 in October 2022.456 The claim covered two major issues.

First, Westinghouse argued that KHNP was in contempt of U.S. nuclear technology export control requirements because, second, KHNP in its current design of nuclear reactors still uses technology it originally licensed from Westinghouse.457 This regards ownership of “System 80 reactor technology” that was originally held by Combustion Engineering, a company that was taken over by Westinghouse in 2000.458 Arguably, KHNP would require permission to export this technology, to which KHNP states that all necessary regulations had been followed.459

In January 2023, an attempt to reach an out of court settlement on technology licensing revolved around KHNP and KEPCO splitting their potential profits from a nuclear project with Westinghouse. 460 The parties had until 17 March 2023 to come to an agreement, but that did not happen.461 In August 2023, the Korean Commercial Arbitration Board began assessing damages claimed by both sides, possibly amounting to several hundred millions of U.S. dollars.462

Regarding U.S. technology export regulations, in September 2023, the U.S. District Court of the District of Columbia ruled that export control enforcement lied solely with the U.S. Government, thus dismissing the case. Westinghouse filed a notice of appeal the following month and subsequently submitted a series of further documents to back their argumentation.463

The second issue, that of technology licensing, was not affected by this ruling. For this, the arbitration panel said a final ruling could be expected towards the end of 2025.464 With the Czech Republic booting Westinghouse from their Dukovany II project (see Czech Republic Focus), rumors have emerged that the lawsuit might be dropped if Westinghouse were to be compensated accordingly.465

Perspectives for Small Modular Reactor (SMR) Deployment

Plans for a third high-capacity power plant were being discussed until at least August 2023,466 but are currently supposedly on hold.467 However, in addition to negotiations regarding potential orders of large reactors, Poland is eyeing the possibility of investing into the deployment of Small Modular Reactors (SMRs). In a 2023 study by the Polish Economic Institute, 47 “experts” were interviewed regarding the potential future role of SMRs in Poland. A majority said that SMRs might be relevant for heat production, and 42 percent believe that more than 5 GW of SMR capacity will have been installed in Poland by 2045, all while acknowledging that this “is too little [to be considered] a […] significant contribution to the energy trawnsition.”468

Meanwhile, various cooperation agreements have been signed. In September 2021, SMR developer NuScale signed an MoU with Polish mining company KGHM and engineering firm Piela Business Engineering (PBE).469 In July 2023, the project was granted first approval by the responsible Climate and Environment Ministry, theoretically allowing the project to move to the next administrative steps, including siting decisions and building permits.470 Although the administrative procedures are ongoing471 and KGHM stated that cooperation with NuScale continues as planned,472 the termination of NuScale’s Utah project in November 2023 increases uncertainty about the project’s viability (see United States in chapter on SMRs).

In June 2022, Polish state-owned company Enea S.A. and U.S. SMR developer Last Energy agreed to cooperate on the deployment of SMRs.473 In March 2023, after contracting power purchase agreements with industrial partners of Poland’s Katowice Special Economic Zone and in the U.K., totaling over US$4.3 billion in electricity sales and US$1 billion in infrastructure investments, Last Energy felt optimistic enough to announce the deployment of ten 20 MWe “Micro Modular Nuclear Power Plants” with the (extremely unlikely) target of commissioning a first plant by 2026 to provide customers with electricity and heat.474 The reactor design is not licensed anywhere yet.

In April 2023, the U.S. Export-Import Bank and the U.S. International Development Finance Corporation both signed letters of interest to provide loans, up to US$3 billion and US$1 billion, respectively, to the ORLEN Synthos Green Energy (OSGE) project that as of April 2023 envisioned the construction of up to 20 GE Hitachi (GEH) BWRX-300 reactors in Poland, with the startup of the first one ambitiously scheduled for 2029.475 The BWRX-300 design is not licensed anywhere in the world and is currently in the pre-licensing phase in Poland.476

In September 2023, OSGE was also selected to receive funds from the U.S. Department of State for “Coal-to-SMR” feasibility studies under “Project Phoenix”.477 On 7 December 2023, six projects at Włocławek, Stawy Monowskie, Stalowa Wola, Ostrołęka, Nowa Huta, and Dąbrowa Górnicza, envisioning up to 24 individual reactors on the grid by 2030, received approval-in-principle from the Climate and Environment Ministry, only a few days before the new government came into power.478

Then in May 2024, the Ministry of Climate and Environment granted a “decision-in-principle” for Polish state-owned Industria’s plans to use a Rolls-Royce SMR at their “Central Hydrogen Cluster”, a cooperation that had been announced in February 2023.479 In March 2024, a letter of intent had also been signed between Industria and U.K. company Chiltern Vital Group to collaborate on the project.480

This decision brings the total number of SMR-based initiatives with principal government approval to three, none of them licensed anywhere in the world:

• July 2023: Mining company KGHM Polska Miedź SA plans to construct a six-module NuScale VOYGR as of 2029 (~ 460 MW);
• December 2023: OSGE project envisions the construction of 24 GEH BWRX-300 reactors at six sites by 2030 (~ 7.2 GW);
• May 2024: Industria plans to deploy up to three 470 MW Rolls-Royce SMR in the 2030s.

Polish SMR proponents envision a vast expansion of capacities. In February 2023, ORLEN reportedly announced it was planning to install a total of 79 GEH BWRX-300 reactors at 26 locations by 2038.481 As of June 2024, three sites of the OSGE project, namely Stawy Monowskie, Włocławek, and Ostrołęka, totaling up to 4.6 GW or 15 reactors, had entered environmental proceedings with GDOŚ to establish the required scope of Environmental Impact Assessment (EIA) Reports, while applications had yet to be filed for the remaining three sites.482 Applications for Włocławek and Ostrołęka have been under GDOŚ-review since August and September 2023, respectively, while Stawy Monowskie is the only site that received a decision on the required scope of its environmental report.483 Upon its issuance in February 2024, OSGE announced it was starting to carry out “environmental and location studies at [the] Stawy Monowskie site necessary for the preparation of the Environmental Impact Assessment Report.” According to the company, about two years can be expected to pass until completion of the EIA report.484

Additionally, the Polish Atomic Energy Agency (PAA) announced it would be joining the Joint Early Review of the French Nuward SMR project.485 In July 2024 however, EDF announced that the Nuward project would be scrapped and a whole new design would be drafted (see France in chapter on SMRs).486

These expansive newbuild ambitions stand against a Polish electricity system dominated by coal, which contributed 61 percent to the electricity mix in 2023, followed by wind (13.7 percent), natural gas (8.7 percent), and solar (7.3 percent). The remainder was generated through various other fossil and renewable sources such as bioenergy and hydro. A total of 168.8 TWh were produced that year.487

The extension of onshore wind capacities ceased in 2016 when restrictive distance laws (“10H legislation”) essentially brought onshore newbuild to a standstill. By 2022, only a total of about 8 GW had been installed. A 2022-amendment of the law might foster some project development; an additional 1.4 GW were installed in 2023, bringing total onshore wind capacity to 9.3 GW.488 The previous government’s target had lain at only 14 GW by 2030 and 20 GW by 2040. The first offshore wind farm is expected to come online in 2026, and a total of 12 GW of offshore capacity is planned.489

In comparison, solar energy is rapidly gaining significance. Throughout 2023, solar capacity grew from 12.17 GW in 2022, to 15.8 GW, a 30 percent increase.490 In 2023, solar contributed 7.3 percent to the national power consumption, a 17-fold increase of the solar share in four years.491 Estimates from November 2023 expect 27 GW of solar capacity to be reached as early as 2025.492 Coincidentally, a few months earlier, per provisional government announcements, this was to be the target featured in the Polish Energy Strategy for… 2030.493

In March 2024, the new government published a draft for the update of Poland’s National Energy and Climate Plan (NECP) and is currently working on reversing regulatory hurdles put in place by its predecessors.494 It now aims to achieve at least 50 percent of renewables in the 2030 electricity mix, with Prime Minister Tusk having promised 68 percent during his election campaign.495 Meanwhile, on 19 June 2022, renewables already covered 67 percent of the electricity demand in Poland.496

Russia Focus

“Russia is one of the few countries without a populist energy policy favoring wind and solar generation; the priority is unashamedly nuclear”

World Nuclear Association, March 2024497

In 1954, Russia was the first country to produce nuclear electricity for the grid. Since then, Russia has significantly influenced the global industry and turned into the largest exporter of reactors, currently constructing 26 units (20 outside the country) of the world’s total of 59 projects in active building, as of 1 July 2024.

In 2023, nuclear energy contributed 18.4 percent of the country’s power mix, generating 204 TWh of electricity, down from a record 209.5 TWh in 2022. With no additional reactor startups in 2023, as of mid-2024, 36 reactors were operating, with eleven permanently closed, the latest being Kursk-2, which generated its last kWh on 31 January 2024.498

Russia has the fourth largest nuclear power fleet, with 36 reactors across six classes: the RBMK, a graphite-moderated reactor of the Chornobyl type (7 units); VVER-440 (5 units); VVER-1000 (13 units); VVER-1200 (4 units); EGP-6, a Light-Water Gas-cooled Reactor (3 units); the KLT-40 (2 units); and FBRs (2 units). (See Annex 4.)

Russia is also one of the world’s largest producers of fossil fuels and a significant exporter of oil, coal, and gas globally. Russia’s economy is highly dependent on its fossil fuel exports and is consequently significantly impacted by fossil fuel prices on the global market. Europe, primarily the E.U., was Russia’s largest customer and has sought to rapidly reduce its dependency following Russia’s full-scale invasion of Ukraine in 2022, with the E.U. pledging to no longer import any gas by 2027.499 Prior to 2022, Russia had provided around 40 percent of the E.U.’s gas imports. While Russia has relatively easily found new markets for its oil and coal to make up for shrinking demand from the E.U., it has struggled to divert its gas supply to new customers, leading to a fall in domestic production. Due to a lack of infrastructure, Russian gas exports to the E.U. will likely not be able to find new offtakes for the next five to ten years, according to some estimates.500 The expansion of the nuclear sector was partly driven by a desire to substitute gas as a domestic electricity supply source, in turn making larger volumes available for export.

Russia is the fourth largest producer of greenhouse gas emissions, and in its approach to COP26 (2021), Russia adopted a net zero target by 2060. However, the Climate Analytics institute stated that the short-term climate change mitigation target would “not represent an increase in ambition as government projections show Russia will achieve this target under current unambitious policies.”501 Moreover, the use of solar and wind is extremely low accounting for only 0.45 percent of the electricity mix, which is “significantly below the global average of 13%” per Ember.502 This approach has been praised by some in the nuclear industry (see WNA quote above).

Nuclear Newbuild

There are six reactors under construction in or for Russia, including a barge built in China to house two reactors destined for Russia.

Two large units are under construction at Kursk II, which are to replace the four RBMK reactors at the site, two of which have already closed, and the last one is to close by 2031. These will be the first of the latest Russian designs (Generation III+), the VVER-TOI (VVER-V-510) with a capacity of 1200 MW, which are also earmarked for export. When construction started on Unit 1 in April 2018, completion was scheduled for 2022, a deadline which has already been breached, as certainly will the expected budget of around US$3.5 billion.503 In November 2022, plant director Alexander Uvakin said, “We hope that 2024-2025 will see the physical startup and commercial operation of the first and then the second unit of the Kursk-II NPP.”504 In June 2024, it was reported that the first turbine of Unit 1 was being installed, which is a “key operation” of commissioning505 and usually takes 1–2 years altogether,506 and the first batch of fuel was delivered.507 The grid connection of the power plant is expected in March 2025. In February 2023, public hearings began on the planned construction of Units 3 and 4.508

Construction of an innovative SMR fast reactor design using liquid lead as a coolant and uranium-plutonium nitride for fuel started in June 2021.509 The objective for the BREST-OD-300 reactor is to start up in 2027,510 and it is said to cost RUB100 billion (US$20211.4 billion).511 If achieved, that would be an impressive performance given that it is the first of its kind, but the project is not there yet.

In June 2020, Rosatom announced that preparation work had begun for the construction of four new reactors, Units 3 and 4 at Leningrad II (also referred to as Leningrad NPP Units 7 and 8 when including the existing reactors) as well as two reactors at Smolensk II, all four meant to replace existing RBMK reactors nearby.512 In December 2022, concrete was poured for the first buildings of the future units at Leningrad.513 The construction of Unit 7 formally began with the concreting of the reactor building’s foundation in March 2024, slightly ahead of schedule.514 Construction on Unit 8 is scheduled to start in May 2025, with startups planned for Unit 7 in 2030 and Unit 8 in 2032. Reportedly, the Smolensk units are expected to be built later, with the concreting of the reactor buildings only scheduled for March 2027.515

In August 2022, Rosatom announced the keel-laying ceremony—considered as construction start for floating reactors—in China of the first Arctic-type Nuclear Floating Power Unit (NFPU) to be equipped with two RITM-200C reactors and to be deployed in Russia in the framework of the Cape Nagloynyn project.516 The completed barge was supposed to be delivered to Russia before the end of 2023,517 but no information on the project’s progress has been published over the past two years.

In June 2023, Rosatom signed an agreement with TSS Group (a Russian oil and gas construction group) to jointly build floating reactors for export to the Middle East, Asia, and Africa.518

In March 2021, in its strategic review, Rosatom said that nuclear energy should provide 25 percent of the country’s electricity by 2045.519 Russian President Vladimir Putin reiterated this target at the launch of construction of the most recent Leningrad unit.520 According to Rosatom CEO Alexey Likhachev, this will require the commissioning of 24 blocks, including at new sites and in new regions. Rosatom reiterated these intentions in May 2022. According to the World Nuclear Association (WNA), the list of sixteen new reactors in the official plan up to 2035 includes:

• Baimsky GOK: four modernized FNPP units (RITM-200 reactors);
• Beloyarsk: Unit 5 (BN-1200M fast reactor);
• Kola-II: Unit 1 (VVER-S or VVER-600 reactor);
• Kursk-II: Units 1–4 (VVER-TOI reactors);
• ODEK in Seversk: BREST-OD-300;
• Leningrad-II: Units 3 & 4 (VVER-1200 reactors);
• Smolensk-II: Units 1 & 2 (VVER-TOI reactors); and
• a Small Modular Reactor in Yakutia: Unit 1 (RITM-200 reactor).521

A number of these will be at or close to existing nuclear power plant sites but also at three new sites: Baimsky and Yakutia in the far East and the proposed Seversk facility in the Tomsk Oblast, a closed city and site of military nuclear facilities. It is also important to note the range of reactor designs being considered, a strategy that makes it significantly more challenging to reach economies of scale.

Russia has closed eleven power-generating reactors: Beloyarsk-1 and -2, Bilibino-1, Leningrad-1 and -2, Kursk-1 and 2, Novovoronezh-1–3, and Obninsk-1, with a further ten units to potentially close by 2030 without operating lifetime extensions,522 which will make it more difficult to meet the target of generating 25 percent of power from nuclear by 2030.

The Russian reactor fleet is aged 30.5 years on average as of mid-2024, with two-thirds of its reactors being 31 years or older, of which 10 operated for 41 years or more and 2 for 51 years or more (see Figure 40). Therefore, a vital issue for the industry is managing its aging units. For example, Rosatom has proposed to extend the operating lives of the 2nd generation of RBMK reactors from 45 to 50 years.523

However, aging is not just a problem for the nuclear sector; the average age of the country’s 68 coal plants stood at 41 years in 2020.524

1. Age Distribution of the Russian Nuclear Fleet

Sources: WNISR, with IAEA-PRIS, 2024

Reactor Exports

Russia is an aggressive exporter of nuclear power technology. Rosatom’s website claims that there are 33 projects abroad in various stages of advancement.525 These claims must be taken with some skepticism; as of mid-2024, Rosatom is involved as the main contractor in the following projects abroad which are in various stages of active construction:

• Rooppur, Bangladesh. Construction started on two VVER-1200 reactors at Rooppur in 2017 and 2018, which were expected to begin operation in 2023 and 2024, respectively;526 commissioning is now expected to start in December 2024, and the project’s completion deadline was moved to 2027.527 The first fuel load shipment was delivered in October 2023;528 see Bangladesh in Potential Newcomer Countries.
• Tianwan and Xudapu, China. Two VVER-1200s each at Tianwan and Xudapu (or Xudabao) are being built. Construction of the respective first units (Tianwan-7 and Xudapu-3) started in 2021 and that of the second units (Tianwan-8 and Xudapu-4) in 2022.529 See China Focus.
• El Dabaa, Egypt. Four VVER-1200s are under construction at El Dabaa; the most recent started in January 2024. The construction of the reactors is scheduled to be completed between 2028 and 2031. The cost is given as US$30 billion, facilitated by a US$25 billion loan from Russia.530 See Egypt in Potential Newcomer Countries.
• Kudankulam, India. Four VVER-1000s are under construction at Kudankulam. Construction started on the first units in 2017 and the most recent ones in 2021. The first of these units is now supposed to be completed in November 2026, and the subsequent reactors are scheduled to be fully operational by 2027. In December 2023, Russia and India signed preliminary agreements for additional units at Kudankulam531, while negotiations on building another plant are also ongoing.532 See India in Annex 1.
• Bushehr, Iran. Construction of Bushehr-2 (also called Busheer-2) was initially started in February 1976 by the German company KWU-Siemens and was suspended in 1978. Work resumed in 1996, with Rosatom subsidiary ASE as the nuclear island provider. Construction work began on this unit and a third reactor at the site in 2017. Concrete pouring for Bushehr-2 took place in 2019, and its commissioning is expected in 2028—whereas the third reactor is not under-construction according to the IAEA.533 See Iran in Annex 1.
• Mochovce, Slovakia. Mochovce-4, a Russian VVER design, which originally started construction in 1985, is being completed by an international consortium and is scheduled to be commissioned in 2025.534 See Slovakia in Annex 1.
• Akkuyu, Türkiye. Four VVER-1200s are being built at Akkuyu. Construction started on the first unit in 2018 and Unit 4 in 2022. Unit 1 is expected to begin operation in 2025.535 See Türkiye Focus.

In addition, in Hungary preparation work is underway at Paks II where construction is expected to start by end of the year.536 The European Commission approved the contract in May 2023 despite the ongoing conflict between Europe and Russia on energy and the war in Ukraine.537 The June 2024 E.U. Foreign Affairs Council’s 14th sanctions package against Russia included provisions against LNG import.538 As Nuclear Engineering International reported: “Hungary had agreed to the EU’s latest package of sanctions, which provides for restrictions on supplies of liquefied natural gas, in exchange for assurances that no current or future measures will threaten Paks II, which is being built by Rosatom.”539 The Hungarian Minister of Foreign Affairs and Trade commented “We’ve reached the objective of having it stated in this directive that the construction of the new Paks nuclear power plant and all its processes, stages and elements are completely exempted from sanctioning measures.”540

It remains clear that Rosatom is the primary constructor and exporter of reactors, building 26 out of the 59 units under construction worldwide as of mid-2024 (see Figure 10 and Table 2).

Nuclear Interdependencies and Sanctions

For details see dedicated chapter Russia Nuclear Dependencies.

Since its illegal, full-scale invasion of Ukraine in February 2022, Russia is facing sanctions from forty-five countries—mainly in Europe and North America, but also from countries like Australia, Japan, New Zealand, and South Korea.541

The European Union

The E.U.’s 14 sanctions packages—given the importance of energy to the Russian economy—have included energy products and equipment, notably542:

• the prohibition of the import of seaborne crude oil and refined products;
• price caps which prevent E.U. operators from providing transport or insurance services for the transport of Russian oil above the cap;
• an import ban on all forms of coal;
• an import ban on liquefied petroleum gas;
• a ban on future investment in LNG projects under construction in Russia and a ban on the use of E.U. ports for the transshipment of LNG;
• a far-reaching ban on new investment across the Russian energy sector, with limited exceptions for civil nuclear energy.

There is no sanction specifically against the import of piped gas from Russia, but in 2022, the European Commission’s RePower E.U. proposed that the bloc would end reliance on fossils by 2027. The dependency on gas has significantly diminished, from 45 percent in 2021 to 15 percent in 2023.543 However, given differing political support, there remains considerable doubt if the 2027 deadline will be met.544

Also primarily excluded from the sanctions are nuclear equipment and fuel as a result of concern and political pressure from some Member States, including France and Hungary545, that have strong nuclear links with Russia. Hungary continues to develop Paks II, while France appears determined to maintain its nuclear relationship with Russia be it through the import of enriched uranium or numerous projects with Rosatom.546 In Germany, officials in the state of Lower Saxony are considering a request from Framatome to produce VVER fuel in a joint venture with Rosatom.547 Furthermore, a report by Greenpeace alleges that Framatome and Siemens Energy are (through export of technologies, software, and expertise) supporting Rosatom in its global trade.548

In February 2023, the European Parliament passed a resolution that called for expanding the sanctions to include individuals and entities, including Rosatom.549 However, despite initially suggesting it would propose sanctions against the Russian commercial nuclear sector, the European Commission abandoned such plans in February 2023 and none have subsequently been applied.550 The Euratom Supply Agency stated in their 2022 annual report (published in 2024) that “EU Stakeholders took measures to reduce their reliance on Russian nuclear fuel supplies.”551

Analysis undertaken by the Norwegian organization Bellona has uncovered that in 2023 Slovakia and the Czech Republic significantly increased their uranium imports from Russia to such an extent that, in total, the E.U. more than doubled its collective payment from €280 to €686 million. This was in part because new reactors (Mochovce-4) and new fresh fuel storage facilities (Czech Republic) were commissioned.552

Furthermore, as there are five E.U. countries—Bulgaria, Czech Republic, Finland, Hungary, and Slovakia—operating 19 Soviet-designed VVER reactors, fuel supply diversification is more complex. Westinghouse has become a fuel supplier in Ukraine, and Framatome is set to start fabricating VVER fuel. (See Russia Nuclear Dependencies).

The United States

Rosatom is also a significant supplier of nuclear material to the U.S. covering 14 percent of its natural uranium consumption and 28 percent of the enriched uranium in 2021. As a result, the introduction of sanctions against Rosatom and the wider Russian nuclear sector has been slow; thus, the March 2022 Executive Order on the prohibition of energy imports from Russia focused on the fossil fuel sector.553 In 2023, further sanctions were introduced, which included ten subsidiaries of Rosatom, including Rusatom Overseas, which is—or at least was—in charge of implementing the construction projects of nuclear power plants in other countries (see section above), and activities related to shipping and defense co-operation, but not those relating to fuel services.554

However, in May 2024 a new law was introduced that banned the import of uranium from Russia, which came into force on 11 August 2024.555 Given the significance of Russian supply, a caveat allows for waivers until 2027 if the Department of Energy judges that no alternative supply is available. Tenex, the subsidiary of Rosatom primarily targeted by the legislation, has responded by sending a note to its clients in the U.S. saying it would stop enriching and delivering uranium unless it received a guarantee that it would receive payment regardless of if a waiver was granted.556 The industry in the U.S. has been preparing for the ban, with uranium mining taking place in the U.S. for the first time in eight years in 2024 and the startup of a small enrichment facility in Ohio. The legislation also unlocks $US 2.7 billion in federal support for domestic enrichment.557 (See United States Focus.)

South Korea Focus

South Korea (the Republic of Korea) has the world’s fifth-largest nuclear power program at 25.8 GW (including one reactor in LTO), not far behind fourth-place Russia. South Korea has been generating nuclear power since 1977, when its first nuclear plant, Kori-1, was connected to the grid. It now has 25 operating reactors and one reactor in LTO, all run by a market-based public corporation, Korea Hydro & Nuclear Power (KHNP), subsidiary of Korea Electric Power Corporation (KEPCO). As of mid-2024, there were two reactors—Saeul-3 and Saeul-4—under construction, and two units—Kori-1 and Wolsong-1—that were closed. In April 2023, then the oldest operating reactor in the country, Kori-2, was closed after 40 years of operation; however, as it is expected to be restarted, it is considered in LTO.

According to IAEA-PRIS, in 2023, nuclear power produced a record 171.6 TWh in South Korea. The share of nuclear power in electricity generation in 2023 was 31.5 percent compared to the historic peak of 53.3 percent in 1987.

Continued Pro-nuclear Policy of the Yoon Administration

On 31 May 2024, the Ministry of Trade, Industry and Energy (MOTIE) released the working draft of the 11th Basic Plan for Long-term Electricity Supply and Demand (BPE).558 The BPE is a plan established every two years in accordance with Article 25 of the Electricity Business Act and Article 15 of the Enforcement Decree of the same Act to stabilize the country’s mid- to long-term electricity supply and demand. The plan includes the basic direction of electricity supply and demand for the 15-year period from 2024 to 2038, as well as long-term forecast, power generation facility planning, and electricity demand management. The working draft released in 2024 will be finalized through consultations with related ministries, public hearings, reports to the Trade, Industry, Energy, SMEs [Small and Midsize Enterprises] and Startups Committee (TIESSC) of the National Assembly, and deliberations within the Electric Power Policy Council.

According to the working draft of the 11th BPE, total power generation is expected to increase to up to 641.4 TWh by 2030, which is slightly more than estimates from the 10th BPE.559 The nuclear power generation projection for 2030 has also increased by 2.5 TWh in the 11th plan compared to the 10th plan, while the share of nuclear in the electricity mix of 2030 has decreased from 32.4 to 31.8 percent as shown in Table 8 below. However, the nuclear share is planned to increase to 35.6 percent by 2038.

1. Government Plan for Electricity Mix in South Korea

Plan	Production / Share of Electricity	Nuclear	Coal	LNG	NRE(a)	Hydrogen & Ammonia	Other	Total
Actual Electricity Mix in 2023	TWh	180.5	184.9	157.7	56.6	-	8.3	588.0
	Share	30.7%	31.4%	26.8%	9.6%	-	1.4%
10th Basic Plan on Electricity supply and demand - Electricity Mix Targets
Target for 2030	TWh	201.7	122.5	142.4	134.1	13.0	8.1	621.8
	Share	32.4%	19.7%	22.9%	21.6%	2.1%	1.3%
Target for 2036	TWh	230.7	95.9	62.3	204.4	47.4	26.6	667.3
	Share	34.6%	14.4%	9.3%	30.6%	7.1%	4.0%
11th Basic Plan on Electricity supply and demand - Electricity Mix Targets
Target for 2030	TWh	204.2	111.9	160.8	138.4	15.5	10.6	641.4
	Share	31.8%	17.4%	25.1%	21.6%	2.4%	1.7%
Target for 2038	TWh	249.7	72.0	78.1	230.8	38.5	32.5	701.7
	Share	35.6%	10.3%	11.1%	32.9%	5.5%	4.6%

Sources: KEPCO, MOTIE, 2023 and 2024560

Notes:

(a) NRE: New and Renewable Energy. New Energy in South Korea includes Integrated Gasification Combined Cycle (IGCC) and fuel cells.

Renewable Energy includes solar, wind, hydro, marine, geothermal, and bio energy.

The peak electricity demand in 2038 is projected to be 129.3 GW. Including reserve capacity (22 percent), the required capacity by 2038 is estimated to reach 157.8 GW, and the target capacity is 147.2 GW when considering the renewable energy deployment plan (120 GW in 2038). Therefore, the draft concluded that an additional 10.6 GW of power generation capacity was needed. The gap is proposed to be met by large nuclear power plants, SMRs, and LNG cogeneration.

Regarding nuclear energy, the draft proposes to build three additional 1400-MW reactors, 4.2 GW total, but unlike past plans, it does not specify where they would be built. Also, the draft includes the construction of the very first SMRs in the country. According to government announcements as well as media coverage, the plan includes a first SMR-project with 0.7 GW.561 The announced SMR would be a so-called “innovative SMR” or “i-SMR” that KHNP is developing as a four-module plant, each unit with a 170 MW capacity.562 Therefore, in fact the plan is to build not one but four SMRs with a total capacity of 680 MW (i.e., about 0.7 GW).

The incumbent Yoon administration has taken for granted that the lifetime of all operating nuclear power plants will be extended, despite the fact that the decision to continue operation of a nuclear power plant must be based on the independent Nuclear Safety and Security Commission (NSSC)’s assessment of safety, as well as economic analysis and public acceptance. In addition, President Yoon amended the Enforcement Decree of the Nuclear Safety Act in December 2022 to expand the application period for extending the lifetime of a nuclear power plant from two to five years before the expiration of the existing operational license to five to ten years before.563

Since 2015, starting with Saeul-1, the first APR-1400 to be commissioned, the NSSC has provided the monopoly nuclear operator, KHNP, a 60-year operating license at a time.564 This system, together with the Yoon administration’s pro-nuclear legislation and policies, facilitates stable business opportunities for the foreseeable future for the Korean nuclear industry.

The current administration also showed its support by increasing the budget for nuclear power in the 2024 government budget plan.565 It newly allocated KRW100 billion (US$72.65 million) to finance the nuclear ecosystem and KRW25 billion (US$18 million) for nuclear export guarantees. The budget for building the export infrastructure for the nuclear power industry also increased from KRW6.9 billion (US$20235 million) in 2023 to KRW8.5 billion (US$6.2 million) in 2024. The budget for the i-SMR technology development project (R&D) was KRW3.9 billion (US$20233 million) in 2023 but increased nearly 10 times to KRW33.3 billion (US$24.2 million) in 2024. The budget for the construction of the Wolseong Low- and Intermediate-Level Radioactive Waste Disposal Center increased significantly from KRW52.8 billion (US$202340.4 million) in 2023 to KRW81.8 billion (US$59.4 million) in 2024, and the R&D project to strengthen nuclear power plant decommissioning competitiveness increased from KRW33.7 billion (US$25.8 million) to KRW43.3 billion (US$31.5 million) in 2024.

The World’s Largest Nuclear Power Plant Got Another Reactor

After over 10 years of construction, Shin-Hanul-2, a Korean pressurized water reactor (APR-1400) was first connected to the grid in December 2023 and began commercial operation in April 2024.566 With the startup of Shin-Hanul-2, Hanul Nuclear Power Plant (NPP) located in Ulchin-gun, Gyeongsangbuk-do, became one of only two NPPs in the world hosting eight units, along with Canada’s Bruce NPP in Ontario, which is the largest number of reactors at a single site.

The total installed electrical capacity of the eight Hanul units is 8678 MW (net), 1.5 times larger than Europe’s largest nuclear power plant, Zaporizhzhia in Ukraine with six units totaling 5700 MW (currently occupied by the Russian army, and in LTO). The implications of Russia’s seizure by force and military use of the Zaporizhzhia NPP are of great significance to South Korea, which is still technically at war with North Korea.

Construction of Saeul-3 and -4

Two APR-1400 reactors, Saeul-3 and -4, previously named Shin-Kori-5 and -6, are being constructed. These are the only reactors under construction in South Korea. Yet, with the exception of Türkiye that is building four units, South Korea and the U.K. have the largest number of nuclear reactors (two each) under construction among the OECD member countries. This illustrates the limited scope of nuclear power plant construction in industrialized countries.

Saeul-3 and -4 were first included in the 4th BPE issued in 2008, with expected commissioning by December 2018 and 2019.567 The construction licenses for the two reactors were approved by the NSSC on 23 June 2016,568 and construction of Saeul Unit 3 began in April 2017. However, on 27 June 2017, former President Moon’s administration decided to suspend the construction of these two reactors and leave the decision to a public deliberation. The public debate committee recommended, based on the deliberation by the citizen task force, that the construction of the two reactors be resumed, but while enforcing the outcome of the consultation, the government decided to pursue an energy policy reducing the share of nuclear power generation in the long term.569 According to the latest projection from May 2024 by KPX (Korea Power Exchange), a quasi-governmental agency under the MOTIE responsible for operating the electricity market and the power system in South Korea, the construction of Saeul-3 and -4 are scheduled to be completed by October 2024 and 2025, respectively.570

Construction of Shin-Hanul-3 and -4

The Yoon administration is also pushing ahead with the construction of Shin-Hanul-3 and -4, two APR-1400 units, which are to be the ninth and tenth nuclear reactor at the world’s densest and largest nuclear power plant, Hanul in Uljin (see The World’s Largest Nuclear Power Plant Got Another Reactor, above). KHNP has submitted documents for the construction license to the NSSC, and the Korea Institute of Nuclear Safety (KINS) has now completed the review of the construction license application, which will be reviewed and is expected to be approved by the NSSC. According to a recent media report, the NSSC is expected to discuss the construction license for Shin-Hanul-3 and -4 at a meeting to be held in August or September 2024.571

Even though the construction licenses for Shin-Hanul-3 and -4 have not been issued by the regulator yet, in March 2023, the sole operator for South Korea’s NPPs, KHNP, signed a KRW2.9 trillion (US$20232.2 billion) contract with the monopolistic provider of main equipment for nuclear power plants in South Korea, Doosan Enerbility, for the supply of components including the nuclear reactors, steam generators, and turbine generators.572 Doosan Enerbility has commenced production of the main components since May 2023.573 Also, in December 2023, KHNP signed another KRW3.2 trillion (US$20232.45 billion) contract with a consortium led by Hyundai Engineering & Construction together with Doosan Enerbility and POSCO Engineering & Construction for the construction of the main facilities at Shin-Hanul-3 and -4.574

It has been argued that this practice of pre-manufacturing equipment before a construction license has been granted is problematic and could be illegal under the nuclear safety regulations. After the commencement ceremony in May 2023, Korean environmental NGOs raised concerns, arguing that even if a design problem is found during the safety review for the construction license, safety may not be prioritized because a huge amount of money would have already been spent. Alternatively, if the permit is not granted, KHNP (after all, the government) that approved the prefabrication will have to compensate for it, most likely with taxpayers’ money.575 During the 2023 National Audit, a congressman also claimed that the ‘pre-manufacturing’ is illegal. MOTIE responded that it has been general practice for the main equipment supplier to send a proposal to KHNP before a construction license is secured. Once KHNP approves the proposal, manufacture of the main equipment begins on an out-of-pocket basis, in order to meet the production schedule agreed between KHNP and the supplier.576

Originally, Shin-Hanul-3 & -4 were included in the 4th BPE for the first time in 2008 to be constructed by June 2020 and 2021, respectively.577 However, the two units were excluded in the 8th BPE in 2017 under the Moon administration (2017–2022) in compliance with its policy to phase out nuclear by the 2080s and later re-included in the 10th BPE established in 2023 by the Yoon administration (2022–2027).578 According to the latest projection by KPX, the construction of Shin-Hanul-3 and -4 are scheduled to be completed by October 2032 and 2033, respectively.579

If the two reactors become operational as planned and the lifetimes of Hanul-1 and -2 are extended as planned (see Lifetime Extensions, below), the Hanul site would become the world’s first nuclear power plant with 10 operational reactors with around 11.5 GW of capacity.

Lifetime Extensions

According to the Nuclear Safety Act, to extend the lifetime of a nuclear power plant, the operator, KHNP, must submit a Periodic Safety Review (PSR) report to the regulator, NSSC, collect opinions from residents through public notices and hearings on the Radiological Environmental Impact Assessment report, and submit an application for a license to change operations to the NSSC for license review.580

There are a total of 10 nuclear reactors whose licenses expire before 2030, and the Yoon administration is seeking to extend all of them by ten years. On 8 April 2023, Kori-2, the country’s third nuclear reactor, which began operation on 9 April 1983, stopped generating electricity due to the expiration of its 40-year operating license. KHNP has announced a plan to restart the reactor by June 2025 by accelerating the scheduled activities as much as possible, including safety inspections for continued operation, and improving facilities.581

The fourth reactor, Kori-3, can only operate until 28 September 2024. NPPs with expiring operating licenses are waiting in line. Those of Kori-4 and Hanbit-1 are scheduled to expire next year, and those of Hanbit-2 and Wolsong-2 in 2026. In 2027, the licenses for Hanul-1 and Wolsong-3 will expire, followed by Hanul-2 in 2028 and Wolsong-4 in 2029.582

SMR Support and Demonstration Reactor Construction Plan

On 3 July 2024, at the SMR Alliance’s first anniversary general meeting, MOTIE announced its strategy to become a “leading SMR country.”583 The main ambitions include expanding private sector participation in the nuclear power market, supporting the construction and operation of Korean i-SMRs, promoting private businesses utilizing SMRs, establishing foundries, and maintaining infrastructure.

The ministry plans to promote ‘demonstration support projects’ for the construction and operation of the first reactor of the innovative SMR design (i-SMR) currently under development, establish a commercialization corporation in the form of a private joint venture (tentatively titled ‘i-SMR Holdings’), and create a KRW80 billion (US$58 million) policy fund for investments in the nuclear power industry, including SMRs. Nam-ho Choi, Vice Minister of MOTIE, stated that the government will “actively support the strengthening of flexible and efficient private sector capabilities while maintaining safety as the top priority.”584

On 17 June 2024, less than a month after the announcement that the 11th BPE would pursue SMR development, Daegu Metropolitan City and KHNP signed a Memorandum of Understanding (MoU) on the commercialization of the country’s first SMRs at the New Airport Advanced Industrial Complex. According to KHNP, the MoU includes cooperation on “feasibility studies such as site suitability and economic feasibility” for the commercialization and construction of SMRs, “commercialization efforts and cooperation in creating a SMR Smart Net-Zero City (SSNC)”, and “enhancing residents’ acceptance” among others.585

In a press release, Daegu Metropolitan Government also revealed that discussions with MOTIE, the Korea Atomic Energy Research Institute (KAERI), and the i-SMR Technology Development Project to build the country’s first SMR had been ongoing for two years.586 However, according to a media report, an information disclosure request revealed that there is no written MoU between Daegu Metropolitan City and KHNP. The media report by Newsmin quotes an official from the city’s Energy Industry Division as saying “Not all business agreements are made in writing. It can also be discussed verbally and in person. This MoU was also discussed over the phone and in person, and there was no formalized MoU.” Indeed, according to the publications’ information, the city’s ledger contained only six documents, including the internal approval for the purchase of banners intended for the signing ceremony. Leading Newsmin to conclude: “This means that even the coordination of the agreement was done verbally, with no written evidence.”587

Dr. Kwang-hoon Seok, a Policy Consultant at the Energy Transition Forum, said in an interview, “The MoU between Daegu City and KHNP is a cost-effective noise marketing scheme. KHNP is trying to secure government subsidies, and Daegu’s Mayor is using it as a show-off for the next election.” 588

South Korea has previously tried and failed to commercialize the SMART (System-integrated Modular Advanced Reactor). This has led to some skepticism about the revival of SMR development in the 2020s. SMART was a project that began development in 1997; in 2012, it was claimed that the 100-MW reactor obtained the world’s first standard design approval, and in 2015, it was heavily promoted in the media as being jointly developed with Saudi Arabia. However, to date, not a single SMART has been built either in South Korea or abroad. The latest attempts are strictly early agreements yet again: In April 2023, KAERI and the Government of Alberta signed an MoU to cooperate on the deployment of SMR technology in Alberta, Canada, including the SMART.589 Also, in December 2023, KAERI signed another MoU with Hyundai Engineering to collaborate on the commercialization and export of the SMART overseas.590

KEPCO/KHNP vs. Westinghouse

The legal battle between Westinghouse Electric Company and KHNP (subsidiary of KEPCO) centers around the alleged unauthorized transfer of nuclear technology in breach of U.S. regulations. This case has significant implications for international nuclear technology transfers and regulatory compliance. The lawsuit was filed on 21 October 2022 by Westinghouse to ensure that KHNP and KEPCO adhere to U.S. regulations governing the transfer of nuclear technology, specifically under Part 810 of the Atomic Energy Act.591

Westinghouse, a leading U.S. nuclear power company, brought this action to seek a declaration that KEPCO and KHNP’s transfer of APR-1400 reactor technology to countries like Poland, Saudi Arabia, and the Czech Republic would require authorization from the U.S. Department of Energy (DOE). Westinghouse argued that KHNP and KEPCO’s actions were in violation of Part 810, which mandates U.S. entities to obtain specific authorization before transferring certain nuclear technologies to foreign entities. Westinghouse emphasized that the APR-1400 design, developed by KHNP and KEPCO, is based on technology originally licensed from Westinghouse, thus falling under the purview of Part 810.592

On the other side, KHNP and KEPCO contended that they had independently developed the APR-1400 reactor and that their technology transfers were not subject to the restrictions of Part 810. They argued that their actions did not constitute a violation of U.S. regulations as claimed by Westinghouse. Furthermore, KHNP and KEPCO asserted that any disputes arising from the 1997 License Agreement, which originally facilitated the transfer of technology from Westinghouse’s predecessor to the Korean entities, should be resolved through arbitration as stipulated in their contract.593

In their defense, KHNP and KEPCO filed a motion to dismiss the lawsuit or, alternatively, to compel arbitration. They maintained that Westinghouse lacked a private right of action to enforce Part 810 regulations and that the proper avenue for resolving disputes related to the 1997 License Agreement was through arbitration before the Korean Commercial Arbitration Board. They emphasized that Westinghouse’s claim should be dismissed as it failed to state a claim under the Declaratory Judgment Act (DJA).594

The court’s ruling focused on whether Westinghouse had a private right of action to enforce Part 810. On 18 September 2023 the court concluded that Westinghouse did not possess such a right, as the Atomic Energy Act (AEA) vests enforcement authority with the U.S. Attorney General. The court noted that the AEA clearly indicates that only the Attorney General can seek injunctions or enforcement actions for violations of the Act or its implementing regulations. Thus, the court granted the motion to dismiss filed by KHNP and KEPCO, stating that Westinghouse had no standing to seek declaratory relief under the DJA for alleged violations of Part 810.595

Furthermore, the court did not address the request to compel arbitration, as it was contingent upon Westinghouse seeking to enforce the 1997 License Agreement. Since Westinghouse explicitly stated that its claim was separate from the 1997 License Agreement, the court’s decision focused solely on the regulatory obligations under Part 810. The ruling underscored that any such disputes over compliance with Part 810 must be pursued by the appropriate federal authorities, not through private litigation.596

In short, the court’s decision highlights the limitations on private entities attempting to enforce federal regulatory compliance in the context of nuclear technology transfers. While Westinghouse raised legitimate concerns about the potential unauthorized transfer of sensitive technology, the court affirmed that enforcement authority rests with the federal government. This ruling sets a precedent for how similar disputes may be handled in the future, emphasizing the role of federal oversight in international nuclear technology transfers.

On 16 October 2023, Westinghouse filed a notice of appeal with the Court of Appeals for the Federal Circuit against the district court’s summary judgment.597, 598

KHNP as Preferred Bidder for the Czech’s New NPP Project

In July 2024, KHNP was selected as the preferred bidder to supply new nuclear reactors to the Czech Republic. The project involves the construction of up to four new units at the Dukovany and Temelín sites.

Dukovany is an existing nuclear facility that has been operating since the 1980s. Two additional reactors would be built at an estimated cost of CZK400 billion (US$17.5 billion). KHNP’s role includes supplying advanced nuclear technology and expertise for these new units. The new reactors are planned to replace aging infrastructure and significantly increase the plant’s capacity. A contract for the construction of two APR-1000s at Dukovany is to be concluded by March 2025.

Negotiations will also address the possibility “to contract an option for up to five years, during which time it will be possible to decide on the construction of two more units at the Temelín site.”599

The bidding process for the Czech nuclear project was highly competitive, with major international players, e.g. EDF from France and Westinghouse from Canada/U.S., vying for the contract. The Czech Minister of Industry and Trade stated that “It is clear that the preferred bidder [KHNP] offered a better price and more reliable guarantees of cost control, as well as the timetable of the entire project.”600 However, in fact, not only the Barakah project in the United Arab Emirates (see United Arab Emirates in Annex 1) but also KHNP’s recent domestic projects were delayed by years.

With KHNP selected to supply the new reactors, the project will now advance to the next stages, including detailed planning and finalization of contractual agreements. This phase will involve working closely with Czech utility ČEZ, the main partner in the project, to finalize technical specifications and project timelines. Regulatory approvals will be sought from Czech and international nuclear oversight bodies to ensure compliance with stringent safety and environmental standards, with a construction permit expected by 2029. Construction is anticipated to begin in the early 2030s, with the new reactors expected to reach commercial operation in 2038.601

The news has been greatly welcomed by the South Korean Government and parts of the media as another important milestone after the first nuclear export deal to the UAE in 2009.602 In fact, following the 2009 UAE deal, then-President Lee Myung-bak’s administration announced a plan to export a further nine nuclear reactors by 2012 and 80 by 2030.603 In reality there has not been a single further export since 2009.

The Energy Transition Forum in South Korea published an issue briefing on 23 July 2024 to raise a number of major concerns around the nuclear export to the Czech Republic.604

The joint statement from the 2023 U.S.-Korea Summit in Seoul included the following unusual statement regarding nuclear exports—whose “weight” the Forum claims cannot be ignored—saying:

Our two nations are committed to the peaceful use of nuclear energy. The two leaders [U.S. President Joseph R. Biden and President of South Korea Yoon Suk Yeol] affirmed the importance of nuclear energy as a key means for overcoming the energy security crisis and achieving their goal of net zero emissions. The Presidents reaffirmed that both countries are committed to engaging in global civil nuclear cooperation consistent with the International Atomic Energy Agency (IAEA) Additional Protocol, while mutually respecting each other’s export control regulations and intellectual property rights [emphasis added]. They committed to promoting the responsible development and deployment of civil nuclear energy globally by leveraging financing tools, building capacity in recipient countries, and establishing a more resilient nuclear supply chain.605

Shortly after the Czech Government’s announcement of the preferred bidder, Westinghouse claimed that KHNP did not have the legal authorization to supply nuclear power plants to the Czech Republic and that it “reserves its rights to challenge this in front of the relevant national and international jurisdictions.”606

As mentioned above, the U.S. court dismissed Westinghouse’s lawsuit, but Westinghouse filed a notice of appeal in October 2023. According to the Forum, this dispute could pose a real threat to South Korea for the export of nuclear power plants to third parties. KHNP had requested approval from the U.S. Department of Energy in April 2023, but its filing was rejected as only U.S. entities are legally able to submit such applications.607

The Forum also claims that Europe’s relatively stringent nuclear safety regulations are also likely to pose a challenge for KHNP. The Czech State Office for Nuclear Safety (SÚJB) has been sharing Western European nuclear safety standards for more than 20 years, which means that it may enforce a significantly different level of nuclear safety regulation than the UAE. European safety regulators have tightened safety regulations since the Fukushima nuclear disaster began in 2011, which contributed to extended construction times and cost overruns in Finland, France, and the U.K.

In particular, the core catcher and double containment design, which have become the standard for new nuclear power plants in Europe, is something that KHNP has never built before. In March 2023, the APR-1000 nuclear power plant design—which includes the new core catcher and double containment design—was certified by the European Utility Requirements (EUR) organization, an advisory organization for European electricity operators.608 However, when it comes to the actual construction-permit process, the company will have to prove the safety of the equipment under the SÚJB’s strict safety regulations. Furthermore, since the Dukovany site is located inland, rather than on the coast, it will require the construction of cooling towers, which is also a first for KHNP—the South Korean reactors are located on the coast—adding to construction time and cost.

Furthermore, the Czech labor standard is a 40-hour workweek, which is significantly different from KHNP’s practice at home. The Forum’s issue paper said that KHNP has been building nuclear power plants in Korea with a 69-hour workweek for decades and that it even raised concerns over the introduction of a 52-hour workweek in South Korea.609 The Forum questioned whether KHNP could meet the construction timeline under conditions that differ as much from its home country.

Finally, the Energy Transition Forum pointed out that the most mysterious aspect of the Czech nuclear export appears to be the financing model. While the Czech Government has selected KHNP as the preferred bidder for two reactors, the financing plan, which was approved by the European Commission in April 2024, is limited to the first reactor at Dukovany.610 Nuclear power plant investments in Europe are risky, and private investors are hard to find in the first place. The estimated construction cost of CZK400 billion (US$17.5 billion) is too much for Czech governmental financing, so it will be interesting to see what financing model will be adopted. The only possible financing option for the Czech Government appears to be a loan from South Korea through the Export-Import Bank of Korea or equity participation from KHNP, and then selling power over several decades after construction to recover investment. However, there is still a great deal of uncertainty as to whether it would be beneficial for South Korea to finance a project with a payback period of maybe 30 years or more.

KEPCO’s Continued Financial Crisis

According to KEPCO’s Semi-annual Report611, its total debt as of the end of June 2024 was approximately KRW202.9 trillion [US$147.4 billion]. This is about KRW440 billion [US$320 million] more than the KRW202.5 trillion at the end of last year. KEPCO’s total debt has been rising since the end of June last year, when it surpassed KRW200 trillion for the first time.

KEPCO’s growing debt is mainly due to its operating losses of more than KRW47 trillion [US$34 billion] since 2021, as international energy prices, which soared after the Russia-Ukraine war, were not reflected in the electricity tariff. KEPCO has raised residential electricity tariffs by 44 percent since 2022 and industrial rates by 63 percent since December 2020612, and the decline in international energy prices has eliminated the company’s reverse margin structure for electricity sales. Since the third quarter of last year, the company has posted four consecutive quarters of profitability. However, the accumulated deficit of KRW40 trillion (US$30 billion) for 2021–2023 remains unchanged due to the rising won/dollar exchange rate and the weakening effect of last year’s increased electricity tariff.613

Sweden Focus

Sweden’s nuclear fleet of six reactors generated 46.65 TWh in 2023, a 6.7 percent decrease compared to the previous year. Nuclear accounted for 28.6 percent of the country’s total electricity production. The share of nuclear power in the country’s electricity mix peaked in 1996 at 52.4 percent when 12 reactors were operating, while the fleet reached its highest output of over 75 TWh in 2004 with 11 units still on the grid.

The 1100-MW reactor Ringhals-4 was taken off the grid for routine maintenance work in August 2022. During tests, the reactor pressure vessel was damaged, pushing the restart back to November 2022, as Vattenfall had to first build a mock-up to train staff and test procedures and equipment for the repair of damaged components.614 This replacement work proved to be more complex than initially imagined, prompting Vattenfall to push the restart date first to January, then February, and finally March 2023.615 However, in late March, start-up activities were interrupted by leakage “from a small valve in a chemical sampling tube” adjacent to the reactor. The unit eventually came back online at full capacity on 12 April 2023.616 Over the year, the reactor experienced continuous operational challenges, and an unplanned outage of Ringhals-4 that occurred in parallel with an unplanned outage at Finland’s newest reactor Olkiluoto-3 (see Finland in Annex 1), sent Nordic wholesale electricity prices skyrocketing from around €20/MWh (US$202321.6/MWh) in mid-October 2023 to over €130/MWh (US$2023140.6/MWh) in November 2023.617 Prices remained elevated until at least January 2024.618 During the same time, Swedish reactor Forsmark-3 also experienced an unplanned outage that lasted for three days.619

During the summer of 2023, another reactor, Oskarshamn-3, had to reduce power output for two weeks due to “a problem in the turbine system.”620 Operational problems reappeared at Forsmark-3 in March621 and more recently in June 2024. Production was halted on 10 June 2024, with the plant expected to return to full capacity three days later.622 However, it was then announced that further work was to be conducted that, as of end-July 2024, had not yet been completed.623 Media reports speak of an “indefinite” delay.624 Despite these challenges, all currently operational reactors are scheduled to operate for 60 years, with plans, announced in June 2024, to further extend tne operational lifetimes of all five reactors at Ringhals and Forsmark to 80 years.625 Ongoing developments regarding reactor lifetime extensions in Sweden are further discussed below.

Reversing the Phaseout Policy

For more than four decades, a planned nuclear phaseout had been a central part of energy policy in Sweden. A 1980 public referendum set the target to end commercial utilization of nuclear power by 2010. Sweden retained the 2010 phaseout date until the middle of the 1990s, but an active debate on the country’s nuclear future continued and led to a new inter-party deal to start the phaseout earlier but abandon the 2010 deadline. The first commercial reactors to close were Barsebäck-1 in 1999 and Barsebäck-2 in 2005. In June 2010, Parliament voted by a tight margin to abandon the phaseout legislation and aim for carbon neutrality by 2050. Following this decision, new reactors were allowed to be built, but only at pre-existing sites.626 Later, the goal of carbon neutrality was pulled forward to 2045,627 with the target of a “100% renewable” electricity system by 2040, though it was explicitly stressed that it did not automatically correspond to a nuclear phaseout.628

The cooperation agreement of Sweden’s current center-right Government (a coalition of the Moderate Party, the Christian Democrats, and the Liberal Party) with the far-right party of the Sweden Democrats, signed on 14 October 2022, is referred to as the “Tidö Agreement”. It contains a pledge to change the energy policy goal “from 100% renewable” to “100% fossil-free”, thus paving the way for the inclusion and expansion of nuclear power in the future energy mix. The new government indicated it would also provide special credit guarantees for nuclear power investments “with more generous terms”, totaling SEK400 billion (US$202239.5 billion).629

This rephrasing was approved by Parliament in June 2023. Consequently, Sweden now aims for “100% fossil-free” instead of “100% renewable” electricity generation by 2040.630 The updated draft of the National Energy and Climate Plan (NECP) (finalized in June 2024, see below) was submitted to the European Commission in July 2023, officializing the newly adopted formulation.631

In mid-November 2023, the government presented a roadmap for the envisioned nuclear power expansion in Sweden which “clarifies the Government’s objectives and provides long-term conditions for new nuclear power.” This roadmap consists of four steps:632

• The government is to appoint a so-called “nuclear power coordinator” mandated to identify necessary measures, remove regulatory hurdles, coordinate all stakeholders, and promote new nuclear. Carl Berglöf, secretary general of the Swedish Atomic Forum (SAFO), was appointed to this role in January 2024, effective 1 February 2024. His final mission report is due by 31 December 2026.633 Berglöf submitted his first report in June 2024, in which he calls for a dedicated project management organization as well as separate commissions to further develop concrete plans and regulations.634
• A financing scheme shall be developed that will split the financial risk between the state and private investors. The Swedish National Debt Office was tasked with developing “preparatory measures” for the issuance of state credit guarantees in compliance with EU regulations, as SEK400 billion (US$38 billion) in credit guarantees were included in the proposed 2024 Budget Bill.635 An investigator was appointed to propose models for the government to take on further financial burdens and risks.636
• New policies shall allow for a minimum of 2.5 GW of new nuclear capacity to be connected to the grid by 2035.
• Regulatory and financial changes shall allow for the subsequent “massive expansion” of new nuclear that “could, for example, correspond to ten new large-scale reactors” by 2045. The exact composition and location of this new fleet has not yet been defined.

Many of these envisaged “new policies” or “changes” seem to disregard the fact that Sweden does not have its own reactor-building industry anymore. Construction of the most recent reactor started in the country in 1980 with grid connection in 1985; no other projects were carried out in the past 40 years. This means that Sweden—just as most of the other countries making newbuild plans—will depend on the same handful of potential builders.

In January 2024, amendments to the Environmental Code took effect, removing the previous limit of ten operational nuclear reactors in Sweden. Additionally, the changes now allow for new plants to be built at new locations other than previous or current reactor sites. The changes were proposed by the government in October 2023 and adopted by Parliament the following month, with all three coalition parties and the right-wing extremist party of the Sweden Democrats voting for, and all other parties against.637

In their most recent report, the government-appointed Climate Policy Council criticizes the climate policies for their “one-sided emphasis on new nuclear reactors” that would reduce incentives for the expansion of other non-fossil energy production infrastructure, especially in the short term, and, assuming first reactors could come to the grid by 2035, it would be too late, as “half the time to reach zero emissions [would have] already passed.”638

The final NECP, published in June 2024, assumes that 52 TWh of nuclear power will be generated by 2030—10 percent higher than today’s production. Remarkably, however, while it states that nuclear “is a prerequisite for reaching climate objectives”, i.e., fossil-free electricity production by 2040, the NECP includes no explicit target for nuclear power capacity beyond 2030 (albeit including scenarios on the potential expansion of renewables).639 However, some of the NECP’s projections are based on the Swedish Energy Agency’s 2023 report on Scenarios of Sweden’s Energy System.640 This report analyzes three scenarios regarding the future electrification of Swedish energy demand. The scenarios assume an increase from 134 TWh of electricity demand in 2020 to 264, 349, and 228 TWh, respectively. An update on the “high demand scenario” was published in December 2023.641

In the original report, all scenarios assumed that existing reactors would operate for at least 60 years, and three of them would run for 80 years. Reactors are assumed to produce at a load factor varying from 85 to 90 percent.642 Newbuild costs lie at an optimistic SEK50,000 (US$20234,712) per kW, less than half of current European newbuild projects (see Nuclear Economics and Finance in WNISR2023).

Nonetheless, nuclear power production from new reactors in 2050 is projected to be limited. In Scenario 1, with medium electrification, production falls to 31 TWh, of which 2.7 TWh are covered by new reactors, corresponding to roughly 340 MW643 of new capacity. The original Scenario 2, that assumes the highest electrification levels, showed an increase of nuclear power production to 66 TWh, of which 38 TWh are covered by new reactors, roughly 4.8 GW. The updated version of this scenario, with “an adapted electricity demand” (not specified, but definitely increased) and a “higher potential for nuclear power,” but with slightly higher costs of SEK55,000 (US$20235,183) per kW, adds an additional 63 TWh of nuclear power production, covered by a total installed capacity of 16 GW (10 GW of which from new reactors).644 In Scenario 3, which corresponds to the lowest electrification rate, nuclear power production falls from 47 TWh in 2020 to 28 TWh in 2050, and there is no newbuild. The original report, published before the government’s announcement of substantial newbuild, showed that the plans were overambitious—and this is sustained by the updated report in which the planned capacities only become necessary when electricity demand exceeds 360 TWh. For comparison, the final NECP states that government plans assume a demand of only 300 TWh in 2045,645 a demand level that could easily be covered under the original Scenario 2.

Swedish SMR Ambitions

Nonetheless, before the amendment of the phaseout legislation in late 2023, in June 2022, state-owned utility and nuclear operator Vattenfall had launched a feasibility study on the commercial, legal, and technological prerequisites to build at least two SMRs at Ringhals, to be followed by a public consultation process,646 and notified the grid operator in December 2022 on the possibility of connecting 2.8 GW of new unspecified nuclear capacity at Ringhals by 2032.647 The results of the study were published in February 2024 and also include preliminary assessments of high-capacity reactor projects to “create the most favorable preconditions for a successful project.” Therein, Vattenfall draws from the experiences of other international nuclear newbuild projects to conclude that a reactor construction project should only begin once a final design has been completed (and is not modified thereafter). The utility further advocates for a whole fleet of new reactors to be built, potentially “3 to 5 SMRs” or 1.5 GW at Ringhals. It considers that the “existing Swedish legislation can be applied for SMR technology”, though “the permit process needs to be simplified to become more predictable and efficient.” Based on the “overall assessment” that “the commercialization of the technology will take slightly longer than previously communicated by suppliers” (six were evaluated), while acknowledging that “timing of commercialization is [the] main uncertainty with SMRs” yet noting that “shorter construction time is expected with SMRs,” the study concludes that a first reactor could be connected “between 9-11 years from today.” However, several necessary steps remain to be completed before Vattenfall would be able to make a final investment decision, including a risk sharing model with the state, a positive net-present value, a finalized reactor design, that would have to include construction plans with “robust supply chains”, and the granting of all permits. An evaluation of high-capacity reactor feasibility was announced as a “next step”.648

In October 2022, Finnish company Fortum, which operates the Loviisa plant in Finland, also launched a two-year feasibility study for the deployment of new nuclear—including SMRs—in both Finland and Sweden.649 In August 2023, Swedish “nuclear-only” electricity provider Kärnfull Next launched a feasibility study together with Swedish nuclear service provider Studsvik regarding the deployment of SMRs at Studvik’s Nyköping site. It had been planned to complete the pre-feasibility study by December 2023 and make “key decisions regarding financing, permitting and PPAs [power purchase agreements] with off-takers (…) in the second half of 2024.”650 In November 2023, Studsvik signed an MoU with Fortum to “explore conditions for new nuclear in Sweden”, including to “assess the potential to construct small modular reactors (SMR) or conventional large reactors at the Studsvik site outside Nyköping.” This investigation is supposed to be a part of Fortum’s large-scale feasibility study mentioned above (see Finland in Annex 1), and will run in parallel to that of Kärnfull Next.651 However, as of writing in mid-2024, there have been no indications that the latter study had been completed at the end of 2023 as planned. Instead, Kärnfull Next announced a strategic partnership with Finnish SMR developer Steady Energy to provide district heating,652 and plans to assess another location for an industrial SMR site in Sweden near Valdemarsvik.653

In August 2023, Michael Lewis, CEO of Uniper, co-owner of all three currently operating nuclear power plants, reiterated that his company would “not invest any further in nuclear power” but rather in “new flexible capacities like batteries and gas plants that can be converted to being zero carbon.” Uniper is planning to leave the coal sector and boost its non-fossil, low-carbon options from today’s 20 percent to 80 percent by 2030 and become carbon neutral by 2040.654 However, during a press conference held in November 2023 to present the Swedish Government’s roadmap for new nuclear deployment, Energy Minister Ebba Busch said that Uniper was one of the private investors that had expressed interest in co-funding the construction of new reactors.655 Regardless, the company’s spokesperson reportedly stated “we do not have any plans currently to invest in new nuclear power.”656

Swedish Prime Minister Ulf Kristersson visited Paris in January 2023 where he reiterated that the “new Swedish government is determined to build new nuclear power plants” and stated that he was “entirely open to France being one of the countries that will make sure that Sweden has more nuclear power.”657 In December 2023, a declaration of intent for the establishment of a long-term cooperation in the field of civil nuclear power was signed by Ebba Busch and her French counterpart.658 In January 2024, a “strategic innovation partnership” was signed between France and Sweden to broaden cooperation in “three new areas: forestry, nuclear energy, and security”.659 The subject of international cooperation was also on the agenda in May 2023 when South Korean Prime Minister Han Duck-soo visited his Swedish counterpart, who promised that “Sweden is going to build new nuclear power plants,” and explained, “South Korea is a role model when it comes to developing new nuclear energy, and we are now enhancing our cooperation.”660

Swedish Lifetime Extension Strategy

With electricity prices sky-rocketing resulting from the energy crisis caused by Russia’s invasion of Ukraine, Vattenfall was asked by the new government to investigate whether recently closed reactors Ringhals-1 and -2 could be restarted.661 This option was swiftly declined by Torbjörn Wahlborg, Vattenfall’s Head of Electricity Production, as it would be “risky, costly and perhaps not even possible”, going as far as stating that it was “neither feasible nor desirable.” Wahlborg explained that even if carried out, the restart would offer no relief on electricity prices in the 2020s, as the restart of Ringhals-1 alone would take at least six or seven years (if successful) and cost “many billions [SEK]” in any case.662 Further, the restart of Ringhals-2 was not possible at all due to the damaged bottom plate of the reactor tank. Wahlborg stressed that Sweden should instead focus on operating facilities and pave the way for new nuclear capacities.663

Despite the postponement of the nuclear phaseout, several reactors have closed in the past decade for economic reasons. In 2015, operators decided to close the country’s four oldest reactors.664 Consequently, Unit 2 at Oskarshamn, which last produced electricity in 2013, was officially closed in January 2016, followed by Unit 1 in June 2017, then Ringhals-2 in December 2019, and Ringhals-1 in 2020. First grid connection for these units occurred in 1974, with the exception of Oskarshamn-1, which started up in 1971.665 Decommissioning work is underway at both sites (see Decommissioning Status Report). The closure of these reactors is often attributed to a controversial tax on nuclear power plants that had existed since the year 2000 and had been increased over time by both left- and right-wing governments.666

Six reactors, half of the original fleet, are thus still in operation at Forsmark, Oskarshamn, and Ringhals. It is planned to operate each reactor for a full 60 years, resulting in the youngest reactors, Forsmark-3 and Oskarshamn-3, to be closed as late as 2045.667 In June 2024, plans were announced for continued operation of up to 80 years of the reactors at Forsmark and Ringhals. Most investments for this would be necessary in the 2030s.668

In the past, due to historical nuclear phaseout plans and the current limitation of nuclear newbuild to existing sites and the replacement of old reactors, the Swedish strategy has focused on uprating existing reactors.669 For example, at Forsmark, this has been ongoing since the 1980s and, according to IAEA-PRIS data, consecutive uprating has increased installed capacity of the three units by 15.6 percent, 24.6 percent, and 11.6 percent, respectively. Further plans included the uprating of Unit 1 by another 100 MW670 and Forsmark-3 by a further 200 MW.671 It appears that the former has been completed, while the latter was not.672 In total, this strategy has, as of July 2024, led to around 999 MW of additional nuclear capacity in operational nuclear power plants.673

To operate reactors into the 2040s, owners need to win approval following ten-year periodic safety reviews. The first reactors to get permission were 39-year-old Forsmark-1 and 38-year-old Forsmark-2, which secured approval from the regulatory authority (SSM) on 18 June 2019 to operate for 10 more years until 2028.674 SSM approved continued operation of the reactors, while also finding

deficiencies regarding the containment and aging of concrete structures deemed as small in the current situation, but it may increase in the long term if the deficiencies are not remedied since serious degradations [...] may occur in the reactor containment and other building structures of importance for radiation safety.675

This could mean significant refurbishment work will be required in the coming years.

Major upgrading work at all of Sweden’s reactors was completed in 2020. This relates to the SSM requirement that all reactors operating beyond 2020 have Independent Core Cooling Systems (ICCS) designed to withstand extreme external hazards. The new system obligation is a consequence of the stress tests carried out following the Fukushima disaster in 2011.676 On 18 December 2020, SSM confirmed that the six reactors predominantly meet set conditions and requirements.677 Further modernization of components at Ringhals-3 and -4 will be conducted by Framatome that in May 2023 was contracted by Vattenfall to update reactor control systems as well as refurbish reactor coolant pumps. This work is to commence in 2026 at Unit 3 and in 2027 at Unit 4.678

In 2023, 166 TWh of Swedish electricity (gross) were produced by mainly hydro (40 percent), nuclear (29 percent), and onshore wind (21 percent); the remainder coming from fossil fuel and bioenergy sources. Solar PV generation has been increasing over the past few years but remains small with 2.5 TWh in 2023, representing just 1.5 percent.679 According to the new NECP, annual wind power production is expected to increase by 50 TWh by 2030, solar expansion remains limited, with only 8 TWh of expected additional annual production.

Taiwan Focus

Taiwan has two operating reactors at Maanshan, owned by the Taiwan Power Company (Taipower), the state-owned utility monopoly. The latest reactor to close was the 985-MW BWR Kuosheng-2 (or Guosheng) on 14 March 2023, following the closure of Kuosheng-1 in July 2021. Maanshan-1 is scheduled for closure in July 2024680 and Maanshan-2 in May 2025.681

This is the lowest nuclear share in the power mix since 1978.

As a logical consequence of the latest reactor closure, nuclear generation declined again in 2023. According to Taipower, nuclear power production decreased by 25.2 percent, generating 17.15 TWh which amounts to 7 percent of the country’s electricity.682 This is the lowest nuclear share in the power mix since 1978. Nuclear generation reached a maximum contribution of 41 percent in 1988.

After the January 2020 re-election of President Tsai Ing-wen of the Democratic Progressive Party (DPP), the government continued its strategy of phasing out nuclear and enacting an energy-transition policy.683

In a 2018-referendum, citizens had voted to remove the amendment to the Electricity Act which made the 2025-phaseout deadline legally binding. The amendment was withdrawn, but the government’s commitment to the policy remained intact; thus, Kuosheng-2 was the fourth Taiwanese reactor to be closed under the national nuclear phaseout plan, marking another milestone in the island’s energy transition.

National Politics

After DPP candidate William Lai won the presidential election in January 2024, Chinese Nationalist Party (KMT) legislators renewed calls for scrapping the nuclear reactor closure deadline, currently set to come after 40 years of service.684 Although William Lai previously defended President Tsai’s energy policy to phase out nuclear and will probably continue the policy, he rhetorically stated during his election campaign that “if emerging technologies can resolve nuclear waste and guarantee safety, nuclear power could be a viable option for the nation.”685

On assuming the presidency on 20 May 2024, Lai made a pledge to carry on Tsai Ing-wen’s energy policy (see the section below Energy and Climate Policy). Thus far, Lai’s government has been characterized by an ambivalent attitude,686 which can be understood as a tactical move rather than a policy change. Premier Jung-tai Cho, appointed by Lai, reaffirmed that the new government has no plans to extend the Maanshan Nuclear Power Plant’s operational lifetime.687 However, he has also indicated the government’s openness to “new nuclear power” after 2030, if safety concerns associated with nuclear technology resolve.688 This might be nothing more than lip service to those industrialists who have reiterated the significance of a stable supply of electricity through nuclear energy.689 The newly established National Climate Change Response Committee, thus, includes both proponents and opponents of nuclear electricity. Two of the three conveners particularly characterize the opposing view: Pegatron Chairman and nuclear advocate Tung Tzu-hsien and Vice Premier Cheng Li-chun, who actively mobilized against the fourth nuclear power plant project in her youth, continued to criticize it as a lawmaker, and has recently emphasized the need to address the fundamental problem of nuclear waste.690

Lai and the new cabinet might also continue to face difficulties in stopping KMT legislators’ attempts to delay the nuclear phaseout, as DPP no longer holds a majority in the Legislative Yuan, the country’s parliament; the KMT is currently the biggest party by one seat over the DPP, while the upstart Taiwan People’s Party (TPP) now holds key votes to support or block legislation.691

TPP’s 2024 presidential candidate and current party leader Ko Wen-Je criticized President Tsai’s nuclear policy and expressed support for using nuclear power as part of Taiwan’s energy transition.692 As of July 2024, the KMT proposed an amendment to the Nuclear Reactor Facilities Regulation Act, which would extend the operation limit of nuclear reactors; the amendment did not garner sufficient consensus during the standing committee’s review and is rescheduled for further scrutiny.693

The challenging political environment might explain the new DPP government’s contradictory declarations of intentions to close nuclear power plants,694 while not excluding the possibility of extending operations.695

Pro-nuclear lobbying had experienced a major setback in December 2021, when a proposal to resume the construction of two reactors at the Fourth Nuclear Power Plant in Lungmen was rejected in a referendum, indicating popular support for a nuclear-free policy.696 Regardless of the vote’s outcome though, the plant was unlikely to be completed or become operational owing to the dire state of the project (see The Lungmen Saga.)

In a major governmental reform in September 2023, a new independent body, the Nuclear Safety Commission (NSC), replaced the former nuclear regulator, the Atomic Energy Commission (AEC).697 While scaled down from second-level to a third-level agency, the NSC will keep its staff size and shift focus from nuclear development to monitoring and regulating nuclear decommissioning,698 as stipulated by the Nuclear Safety Commission Organization Act, the legal framework for NSC’s establishment.699 According to the Act, the new commission shall oversee and implement waste management, which will be a major challenge in the coming decades due to the scheduled closure of Taiwan’s remaining nuclear fleet by 2025 and the ensuing decommissioning activities.

The authority was to be set up about a decade ago,700 and the Executive Yuan (the government’s executive branch) drafted an organizational Act in early 2013 as part of restructuring ministerial affiliations,701 but it was delayed by KMT legislators.702

More recently, some KMT politicians have also promoted the idea of deploying small modular reactors (SMRs) “in every administrative region of Taiwan.”703 While the DPP has thus far evaded the subject, some environmental organizations such as Green Citizens’ Action Alliance (GCAA) and Citizen of the Earth, Taiwan, have argued that SMRs would be a false solution to a real problem creating more waste than traditional plants. Moreover, environmentalists emphasize that new nuclear power would be too slow and too expensive to be a feasible solution to Taiwan’s urgent need for an energy transition in the face of the climate crisis.704

Reactor Closures

As reported in previous WNISR-editions, Taipower announced the closure of Chinshan-1 on 5 December 2018. The reactor had not generated power since the end of 2014. Chinshan-2 had been off-grid since June 2017, but was not officially closed until 15 July 2019, when its 40-year operating license expired.

On 1 July 2021, Taipower stated that due to lack of spent-fuel storage-capacity, Kuosheng-1 was closed six months ahead of schedule.705 The closure of the reactor, located on the northern coast, only 22 km away from Taipei, was originally slated for 27 December 2021, the day its operating license expired. A new batch of nuclear fuel had been loaded into the reactor during the refueling and maintenance outage in 2020, but in February 2021, Taipower reduced the reactor power-level to 80 percent to save fuel and extend operations until the higher-consumption month of June.706

Kuosheng-2 ceased operating in March 2023. The 985-MW BWR/6 unit was supplied by General Electric (GE) and connected to the grid on 29 June 1982.

The remaining two PWRs at Maanshan are scheduled for closure on 26 July 2024 and 17 May 2025, respectively. In line with the nuclear phaseout and current regulation, the application to disconnect the units from the grid was submitted in July 2021.707

Despite the fact that the spent-fuel pools of the Chinshan and Kuosheng power plants have reached full capacity, for various reasons, the government has made little effort to arrange dry cask storage for the high-level radioactive waste. Little attention has been paid to intermediate storage and final disposal of spent fuel. In 2023, GCAA and other environmental groups lobbied in vain to legislate on the issue.708

Reactor closures, in general, have not ushered in the actual technical decommissioning phase, which would come only after the spent-fuel assemblies in the reactors have been unloaded and placed in fully operational dry cask facilities.

The Lungmen Saga

In an attempt to reverse the nuclear phaseout policy, a national referendum was held on 18 December 2021. The voters were asked whether they back the resumption of the construction of two long-mothballed ABWRs at the Lungmen site on the northern coast. Official results indicated that voters rejected the proposal by 52.84 percent against to 47.16 percent in favor, by a small 5.68 percent margin.709 Residents of Gongliao, the neighboring town, delivered an overwhelming ‘no’ vote at 75.7 percent.710

Construction of the plant and the two reactors started in 1999. In stark contrast to the three other twin-unit plants built under turnkey contracts during the 1970–80s, construction at Lungmen was characterized by a complex chain of more than 500 contractors and subcontractors, who tended to cut corners and replace long-term with temporary workers.711

According to the now defunct AEC, as of the end of March 2014, Lungmen-1 was 97.7 percent complete,712 while Lungmen-2 was 91 percent complete. The plant was by then estimated to have cost NT$300 billion (US$20149.9 billion).713 After multiple delays, budget blowouts, numerous exposés of dubious construction practices,714 and large-scale public and political opposition, including through local referendums, on 28 April 2014, then-Premier Jiang Yi-huah announced that Lungmen-1 would be mothballed after the completion of safety checks, while work on Unit 2 was also to be stopped. In December 2014, it was announced that the project was put on hold for three years,715 and it has not resumed since.

There is little prospect that the units would ever operate even with a favorable political decision. Numerous obstacles stand in the way of resuming construction. First, resumption would require approval from both Taiwan’s legislature and the NSC.716 In addition, the initial construction permit expired at the end of 2020. The acquisition of a new permit would require a new environmental impact assessment and an additional geological survey. Research conducted in 2009 by the Central Geological Survey (CGS), a government agency of the Ministry of Economic Affairs, found a fault line extending up to 90 kilometers off the coast of the Lungmen site.717 According to a survey conducted by Taipower four years later, the fault line was only 34.5 km-long, but the area of investigation was limited to 50 km from the coastline, thus suggesting a substantial underestimation of the potential risk.718

Even if the seismic fault was proven inactive, many technical challenges would need to be addressed. Taipower explained in February 2019 that it would not be possible to simply replace major electronic components installed nearly two decades ago, including instrumentation and control. Moreover, the resumption plan entailed that full-scale difficult negotiations with the main supplier, General Electric (GE), were to be expected.719 In 2021, the AEC chairman cited a “10 years or more” timeline until grid connection of both units. 720

Moreover, in November 2021, the government revealed confidential documents from 2015 that showed the impact of unresolved safety issues if the project were to relaunch. The documents came to light as a result of the Control Yuan’s (the country’s highest ombudsperson institution) 2019-investigation into two settlement payments made by Taipower to GE Hitachi. The first was a US$158 million compensation for equipment supplied at Lungmen awarded to GE by the International Chamber of Commerce (ICC). This was awarded in a December 2018 ruling (notified in March 2019), following a 3-year investigation initiated at GE’s request over Taipower’s cessation of payments. A second ruling by ICC resulted in a settlement agreement between the two companies, with Taipower paying a third of the US$66 million that GE had originally demanded (Taipower said it agreed to a settlement in order to minimize the compensation payment and avoid further legal fees).721

Compliance with safety specifications has long been subject to contradicting or inconsistent assertions. For instance, citing the task force report he had commissioned, the former Minister of Economic Affairs Chang Chia-chu declared in 2014 that Unit 1 was cleared for hot-testing and fuel-loading. An AEC investigation later concluded that Minister Chang’s July 2014 claims had “no legal standing,” yet they “created the mistaken understanding among a part of society that the report meant that the nuclear power plant was safe.” 722 See Taiwan in WNISR2023 for further details on the investigation.

WNISR took the Lungmen units off the construction listing in 2014 and has retained that stance as of 1 July 2024. The IAEA had classified the Lungmen reactors as “under construction” at least until the end of 2019723 and removed them from the list before releasing its annual statistics for 2021.724

Energy and Climate Policy

Public opposition to nuclear power in Taiwan reached a new high in the immediately after the Fukushima disaster was triggered.725 Sending shock waves through Taiwan, the event increased public acceptance for a nuclear phaseout and an energy transition. Having returned to power in 2016, the DPP announced the “New Energy Policy Vision” aimed at establishing “a low carbon, sustainable, stable, high-quality and economically efficient energy system” through an energy transition and energy industry reform.726 On 12 January 2017, the Electricity Act Amendment completed its third reading in the legislature, ushering Taiwan’s energy transition, including the nuclear phaseout.727

During the second term of Tsai’s presidency (2020–24), Taiwan aspired to become a leading country of renewable energy in the Asia-Pacific region.728 The island’s renewable energy potential is significant, and in 2021, the Global Wind Energy Council estimated Taiwan’s offshore wind technical potential to be as high as 494 GW.729 Taiwan aims to develop 5.7 GW of offshore wind capacity by 2025. In 2020, the government set a goal to add an additional 10 GW of offshore wind capacity between 2026 and 2035.730 In May 2021, the target was increased to 15 GW with annual deployment of 1.5 GW over the decade. The target has been confirmed in 2023.731

However, until a significant boost in 2022, the development of renewable energy had been slow. In 2022, the installed renewable energy capacity reached 14.1 GW, representing 23 percent of installed capacity, and renewable power generation increased by 37 percent to reach 23.8 TWh, contributing 8.3 percent of the total electricity production. The year 2022 marked the first time that the share of renewable energy—including geothermal, biomass, waste, and hydro—in total electricity production slightly surpassed nuclear power (8.3 percent versus 8.2 percent), with a 163-percent increase in offshore wind power generation compared to the previous year and a 57-percent increase in total wind production.732

The trend continued in 2023, when the share of renewable energy in total electricity production reached 9.5 percent (compared to nuclear power’s 6.3-percent contribution), with wind power (onshore and offshore combined) and solar PV power generation achieving growth rates of 74.4 percent and 20.9 percent, respectively. The installed capacity of renewable energies reached 18 GW (a 27-percent increase compared to 2022), of which 12.4 GW were solar PV (+27.2 percent) and 2.7 GW wind (+69.4 percent).733

However, over the past two decades, Liquefied Natural Gas (LNG)-generated electricity shot up from less than 20 TWh in 2000 to 111.6 TWh in 2023, making up 39.5 percent of total electricity generation, coming close to the 42.2 percent share of coal-fired electricity generation,734 see Figure 41.

1. Electricity Production in Taiwan, 2000–2023

Sources: MOEA, Energy Handbook, Various Years

Current targets for 2025 place solar capacity at 20 GW and combined renewable energy capacity at 20 percent of the power mix.735 These goals remain ambitious, but the deployment acceleration has also been noted by investors. Taiwan again moved up two places in the Ernst & Young’s Renewable Energy Country Attractiveness Index 2023 to rank 21th in 2023736 and maintained that position in 2024737.

Despite not being able to participate in the Paris Agreement and COP negotiations, in April 2021, the Taiwanese Government unilaterally pledged to achieve Net-Zero by 2050, announcing that it would draft regulations to that end, accelerate the implementation of existing targets and achieve the energy transition towards renewables.738 In 2022, Taiwan passed the Climate Change Response Act, which replaced the former Greenhouse Gas Reduction and Management Act of 2015, making legally binding the goal of Net-Zero by 2050.739 Regulatory measures regarding carbon pricing schemes and carbon footprint verification have, thus far, not been put into place. The actual implications of the Climate Change Response Act for carbon reduction therefore remain to be seen.

As of 2023, the island remained heavily dependent on imported fossil fuels (see Figure 41). Coal-based electricity production has only slightly decreased to remain over 100 TWh, and gas imports have exploded to reach a level similar to coal; instead of an energy transition from fossil fuels to renewables, these data rather suggest and accumulation of various energy sources. Per capita energy consumption has hardly gone down over the past decade, and per capita electricity consumption has increased by 14 percent over the decade 2013–2022 and decreased only slightly, by 1.2 percent, in 2023. Peakload experienced the strongest growth rate at 19.5 percent over that decade to exceed 40 GW for the first time in 2022,740 hitting a new record in February 2024 at 41.2 GW.741

The government’s strategy has aimed to “promote green energy, increase natural gas, reduce coal-fired power, and achieve nuclear-free.”742 This implies that Taiwan would continue to see a substantial increase in natural gas consumption which would then provide 50 percent of gross electricity production by 2025.

In March 2022, Taiwan’s National Development Council unveiled its latest Pathway to Net-Zero Emissions in 2050. The strategy was based on a NT$900 billion (US$202232.4 billion) budget to 2030, of which NT$210.7 billion (~US$20227.6 billion) were allocated to “renewables and hydrogen”, and another NT$207.8 billion (~US$20227.5 billion) were to be invested in “grid and energy storage”. The plan included 40 GW of combined wind and solar capacity by 2030, and by 2050, an installed capacity of 40–80 GW in solar and 40–55 GW of offshore wind alone, for a combined share of more than 60 percent.743

Deputy Minister of Economic Affairs Tseng Wen-sheng reportedly stated on 20 September 2023 that as Taiwan “excels at manufacturing,” the future energy trend, “which no longer relies on [natural resources] but manufactured devices especially solar panels and wind turbines to get hold of power” would pose a challenge but was in itself an economic opportunity for the country.744

A second stage of the electricity market reform (2019–2025) includes grid unbundling and the restructuring of Taipower into a holding company with two separate entities: a power generation corporation and a transmission and distribution corporation within six to nine years.745

Under the presidency of William Lai, the new DPP government is expected to follow the preceding administration’s footsteps for the energy transition, but tensions in national and international politics might render implementation more challenging.

Türkiye Focus

There are four nuclear reactors currently under construction in Türkiye, at Akkuyu in Mersin province. President Recep Tayyip Erdoğan announced in early June 2024 that the construction of the first VVER-1200 unit—started in 2018—has reached 90-percent completion.746 The three other units have been under construction since April 2020, March 2021, and July 2022 respectively.747 As previously reported, the project has experienced delays at various stages (see earlier editions of the WNISR). Originally, Unit 1 was scheduled to start up in 2023.

In October 2023, Alparslan Bayraktar, Minister of Energy and Natural Resources, set the commissioning date of Unit 1 to 29 October 2024.748 Six months later, Alexey Likhachev, Director General of Rosatom, announced that commissioning would be delayed into 2025 without specifying a precise date.749 In May 2024, Denis Sezemin, Director for Construction and Production Management of Akkuyu Nuclear JSC, stated that commissioning of the first unit would occur in April 2025.750 Only one month later, the Russian State Duma Committee on Energy, while visiting the Turkish Parliament, indicated that it anticipated the startup of the first unit in October or November 2025. According to media reports, in a meeting with members of the Committee on Industry, Trade, Energy, Natural Resources, the Russian delegation stated that, “We have given the necessary information to your Ministry of Energy. We are trying to avoid delays, but the most important thing is the continuation of sanctions against Russia and the withdrawal of our contracts for equipment for cooling systems.”751 It was also stated that some equipment was produced by Chinese companies in a short time as a replacement.752 Denis Sezemin gave more details in an interview, informing that some switchgear equipment that could not be delivered from Germany has been waiting for export permits on German soil since July 2023, and that the company decided to change suppliers when joint initiatives with Türkiye to ensure the delivery of this gas-insulated 400 kilovolt voltage equipment did not yield results.753 Sezemin added that his team ordered this equipment from China in January 2024 and is striving to commission the first unit in 2025 in accordance with the terms of the intergovernmental agreement.754 Two days later President Recep Tayyip Erdoğan also pointed at Germany and said that, “We currently have a problem with Germany as the turbines that are supposed to arrive for the Akkuyu Nuclear Power Plant are waiting at German customs. This has seriously disturbed us.”755

During his June 2024 visit to Türkiye, Pavel Zavalny, Chairman of the Russian State Duma Energy Committee, emphasized the risk of Akkuyu startup delays associated with supply issues caused by sanctions. He stated that, in the absence of a solution, the commissioning deadline for the first unit, scheduled for 2025, may not be met.756 Zavalny identified two primary issues contributing to the delay. The first was the non-delivery of the electricity distribution system, which was re-ordered from a Chinese company. The second issue was the non-arrival of a special watercraft required for the installation of the cooling system. Zavalny stated that “Rosatom had paid for both elements, that the orders had not been fulfilled, and that the amounts paid had not yet been returned.” Zavalny responded to the question of whether Russia would request a price revision by saying, “If there is such a need, the parties will discuss. Some of the electricity will be sold in the free market. (…) It may be possible to extend the repayment period in the contract to 20 years [from 15 years]. If necessary, the parties will discuss this further.”757

The cost of the Akkuyu nuclear plant was estimated at US$20 billion when the project was first announced in 2010.758 The cost has risen to US$24–25 billion according to the Director General of Rosatom Alexey Likhachev who spoke at the meeting of the Russian Council of Science and Education in June 2024.759 This indicates a further increase in costs in less than a year. In September 2023, during a public meeting in Nizhny Novgorod Oblast, Russian President Vladimir Putin asked Likhachev for an update on the Akkuyu NPP cost. Likhachev replied that the cost in Türkiye would be US$23–24 billion rather than the US$17 billion suggested by President Putin in his question.760

The Turkish Government has announced plans to construct eight additional reactors in two other locations, with the goals of reaching 7.2 GW of installed nuclear capacity by 2035 and over 20 GW by 2050.761 The Minister of Energy and Natural Resources (MOE), Alparslan Bayraktar, indicated that the initiative would encompass not only conventional large-scale nuclear power plants but also Small Modular Reactors (SMRs).762 There has been a notable increase in interest in SMRs in Türkiye in recent years. In 2020, Rolls-Royce and Türkiye’s EUAS International ICC signed a Memorandum of Understanding (MoU) to conduct a study evaluating various aspects of SMRs’ applicability and a potential joint production.763 In September 2023, MOE Alparslan Bayraktar met with Rolls-Royce Group to discuss the possibility of collaboration on SMRs.764 The U.S. is also interested in the Turkish market for SMR technology, as evidenced by occasional statements made by Justin Friedman, a senior advisor for the U.S. Department of State, during his visits to Türkiye in recent years.765 In May 2024, Bayraktar invited American companies to invest in Türkiye in the field of SMRs.766 During his visit to China the same month, to sign an MoU on cooperation in the field of energy between the two countries, Bayraktar mentioned SMRs and renewables amongst the range of discussed energy technologies.767

A Brief History of Nuclear Energy in Türkiye

Türkiye’s nuclear ambition dates back to the 1950s. In 1956, Türkiye established its Atomic Energy Commission with the objective of encouraging, coordinating, and supervising scientific, economic, technical, and administrative studies related to atomic energy.768 In 1962, a 1-MW ‘pool’ type experimental nuclear research reactor, named TR-1, was commissioned at the Çekmece Nuclear Research and Training Centre (ÇNAEM) and operated until 1977.769 TR-2 achieved its first criticality on 19 December 1981 at the same location.770 The third and only operational research reactor, Triga Mark-2, was commissioned in March 1979 and is located at the Ayazağa Campus of Istanbul Technical University.771

Between 1965 and 2000, Türkiye attempted to launch a commercial nuclear power plant project on four occasions, but none of these attempts reached the construction phase.772 Between these attempts, Akkuyu was granted its first site license in 1976.773

In 2004, Türkiye’s Ministry of Energy and Natural Resources announced the construction of three nuclear power plants, each with four units and an installed capacity of 5 GW. The initial plan was for the first reactor to commence construction in 2007 and become operational in 2012. However, this did not proceed as planned.774 In the final nuclear tender of Türkiye’s history, which opened on 24 September 2008, thirteen companies or partnerships received specifications, six of them submitted their bid envelopes, of which five contained ‘thank you’ notes signaling the bidders’ withdrawal. Only the Turkish-Russian consortium led by Atomstroyexport, with Inter RAO and Park Teknik, submitted a bid based on the Russian VVER design. The proposal met all nine of the Turkish Atomic Energy Agency’s (TAEK) criteria.775 On 19 January 2009, the kilowatt-hour price offered by Atomstroyexport-Inter RAO-Park Teknik Group in the framework of a build-own-operate scheme was revealed to be US$21.16 cents.776 Later, it became known that the consortium subsequently made a new, lower price offer, claiming that there had been a change in input costs, as the initial offered price was considered high by the public. Since the tender for the nuclear power plant was organized as a competition, according to the law, a bidder could not submit a second bid with a lower price. The tender commission did not accept this envelope, but ministry officials did.777 The subsequent attempt to reduce the given price led to objections and a stay of execution decision was taken from the relevant court against the lawsuit filed by The Union of Chambers of Turkish Engineers and Architects. This decision also played an important role in the subsequent cancellation of the tender,778 which took place on 20 November 2009.779

Following the failure of previous initiatives including the most recent proposal, the Turkish Government pursued an alternative course of action by entering an intergovernmental agreement with Russia. On 12 May 2010, during former Russian President Dmitry Medvedev’s visit to Ankara, it was announced that Türkiye’s first nuclear power plant will be constructed by the Russian industry.780 On the same day, Türkiye and Russia signed the Agreement on Cooperation on the Construction and Operation of a Nuclear Power Plant at the Akkuyu site.781 The agreement was published in the Official Gazette on 6 October 2010.782 At the time, projected startup dates of the four reactors were set “between 2016 and 2019.”783

The Russian Deal

The intergovernmental agreement contains important provisions regarding the cost of the project for Türkiye and the ownership and management of the plant. The construction of the Akkuyu NPP is entirely financed by Russia.784 This was an advantageous deal for cash-strapped Türkiye but led to problems with the start of the sanctions against Russia.785 Article 5 of the intergovernmental agreement specifies that the project company, owner of the plant, will be established by the Russian party. Furthermore, the cumulative shares of the Russian authorized organizations in the project company must always remain at 51 percent or above.786

The power purchase guarantee is set out in Article 10. It states that 70 percent of the power generated from the first two units and 30 percent from the other two units will be purchased by the Turkish Electricity Trade and Contract Corporation (TETAŞ) for 15 years at a weighted average price of US$12.35 cents per kWh, excluding VAT.787 Any remaining electricity generated will be sold on the open market. The Chamber of Electrical Engineers calculated the sum to be paid to Akkuyu Nuclear JSC in 15 years under the purchase guarantee as US$35.2 billion based on the assumption that the plant generates 38 TWh of electricity per year.788

The opposition has strongly criticized the build-own-operate agreement, particularly due to its purchase-guarantee requirement and Russian ownership.789 Ahmet Akın, former Deputy Vice President of the main opposition party CHP (Cumhuriyet Halk Partisi/Republican People’s Party), expressed concern that the guaranteed purchase price was three times higher than the current market price (as of May 2021).790 Former Energy Minister Fatih Dönmez offered a different perspective, noting that nuclear will initially be costly under current market conditions, but that it should be seen as an 80-year investment. “The average price over its lifetime will be very, very low. One should think of it as an investment which is expensive for 15 years but reasonable for 65 years,” Dönmez said.791

Alpay Antmen, a CHP Member of Parliament, expressed concern about the lack of technology transfer, the 60 years of Russian ownership, and the potential environmental impact of the plant, as well as its limited contribution to the Turkish economy.792 Meral Akşener, former leader of the center-right İYİ Parti (Good Party), called on the Ministry of Energy in August 2022 via social media to intervene in a dispute between local contractors and the Russian project company, requesting the nationalization of the power plant if necessary.793 The dispute began when the Russian side terminated the engineering, procurement, and construction contract with the Turkish company IC İçtaş on 26 July 2022.794 Rosatom stated that IC İçtaş committed contract violations that affected the quality and delivery time of the project.795 IC İçtaş, on the other hand, denied these allegations and claimed that Rosatom’s aim was to minimize the presence of Turkish companies in the project.796 The dispute was later resolved with the intervention of Putin and Erdoğan, and IC İçtaş resumed work at Akkuyu.797

Article 10.9 of the agreement also contains a provision on waste management, which sets out Akkuyu Nuclear JSC’s payment obligations:

The Project Company shall pay a separate amount 0.15 US dollar cent per kWh to the account for spent fuel, radioactive waste management and 0.15 US dollar cent per kWh to the account for decommissioning for electricity purchased by TETAŞ within the framework of the PPA.798

Article 12.2 states that potential reprocessing of Russian-origin nuclear fuel in the Russian Federation would be subject to a separate agreement.

One of the most crucial elements of the agreement is Article 6 which stipulates that the construction of Unit 1 must be completed within seven years of the issuance of “all documents, permits, licenses, consents and approvals necessary to start the construction.” Subsequent units must be placed in commercial operation at one-year intervals. The construction license for the first unit was granted on 2 April 2018,799 meaning Unit 1 would have to commence operation in April 2025 at the latest to comply with the terms.

Further Newbuild Options

Historically, three sites have been proposed for a nuclear power plant in Türkiye, Akkuyu (Mersin province), Sinop, and İğneada (Kırklareli province), mainly because they are claimed to be far from active fault lines. However, the Chamber of Geological Engineers of Türkiye argues that the Akkuyu site is very close to the Ecemiş-Deliler Fault (3–5 kilometers), as well as the Biruni Fault, which is the previous fault’s continuation in the Mediterranean Sea.800 Many environmental groups, such as the East Mediterranean Platform of Environment Associations (DACE), called for a halt to the construction of the Akkuyu NPP after major earthquakes struck the south-eastern part of the country in February 2023 killing more than 50,000 people.801 Two weeks after the earthquake, Akkuyu Nuclear JSC responded to these concerns with a media release, claiming that “the Akkuyu NPP project is designed for a safe shutdown [in case of an] earthquake of magnitude up to 9.”802

The northernmost tip of Türkiye, Sinop has long been identified as one of the possible sites to build a nuclear power plant. Preliminary studies for Sinop began in the early 1980s but were halted following investigations into earthquake risks.803 Although the last and most serious attempt to build a nuclear power plant by a Japanese-led consortium ended in failure,804 the recent site approval by the Nuclear Regulatory Authority (3 April 2024) can be interpreted as preparation for a new process.805 In March 2024, Energy Minister Alparslan Bayraktar spoke of possible cooperation with Rosatom for Sinop, but also mentioned interest of South Korea and China.806 As of June 2024, Pavel Zavalny, Chairman of the State Duma’s Energy Committee, was “90 percent certain” that Rosatom would be selected for the Sinop project.807 He also revealed Rosatom plans to build two units with a capacity of 1250 MW each at the site.808

The Thrace region, and particularly a small town called İğneada in the province of Kırklareli close to the Bulgarian border, is the third site proposed for the construction of a nuclear power plant in Türkiye since the 1970s.809 Recently, government officials have been using “Thrace region” to identify the location of the third site instead of “İğneada”, which could indicate that a new site in the region is being considered. Energy Minister Alparslan Bayraktar revealed during his visit to China that Türkiye is negotiating with China for the planned nuclear power plant in the Thrace region to be equipped with four reactors and is working to finalize the intergovernmental agreement in a few months.810

Incidents During Akkuyu Construction Raise Criticism

According to the Akkuyu Nuclear JSC, there are 25,000 workers involved in the construction of Akkuyu NPP where four units are being built simultaneously.811 This number went up to 30,000 in Rosatom’s other statements, and it is stressed that the four units must be constructed by the end of 2028 according to the intergovernmental agreement.812

The first unit was granted a commissioning permit on 21 November 2023.813 Commissioning work was announced to commence in the beginning of April 2024.814 Construction of the other units is also underway. Installation of the roof on the turbine building of the second unit was completed in May 2024.815

Throughout the project’s history, the construction work has been heavily criticized by environmental groups and opposition parties. The discovery of cracks in the concrete of the reactor building’s foundation of the first unit became a major controversial issue.816 According to news reports, the (former) Turkish Atomic Energy Agency intervened twice and had problematic sections of the foundation redone.817 Rosatom denied the claims saying that the reactor’s base had been completed in accordance with International Atomic Energy Agency safety standards.818 Over the years, media reports covered several incidents that occurred due to construction activities at the site, including damage to nearby houses caused by planned dynamite explosions and several fire outbreaks.819

From time to time, the media also reported on poor working conditions with dire consequences such as widespread food poisoning or flooding of a canteen.820 There were also claims of mobbing and non-payment of salaries, and once some of the workers publicly complained that they had to go to the hospital by their own means when they had a work accident.821

In early 2024, a deadly meningitis outbreak became public, and the Mersin Medical Chamber attested that it was aware of two fatalities, though one could not be confirmed as a meningitis case. At the time, the alleged number of casualties was five.822 Rosatom confirmed the deaths of two workers.823 In early February 2024, Dr. Nasır Nesanır, President of the Mersin Medical Chamber, said that the number of identified cases had reached four. Two of them died, with meningitis being the established cause of death for one of them according to medical records. The cause of death for the second person could not be established with certainty.824 Nesanır stressed that the contraction of the disease is often linked to poor housing, hard working conditions, and malnutrition.

Another event related to the workers of Akkuyu Nuclear Power Plant was the discovery in February 2024 of a suspected ISIS member amongst the workers. According to the local police, the arrested suspect was a Russian citizen who used a fake identity.825

One of the major setbacks was the above mentioned dispute between Akkuyu Nuclear and one of its subcontractors, IC İçtaş İnşaat, which took two months to resolve involving Russian President Vladimir Putin and Turkish President Recep Tayyip Erdoğan.826

The Cases of Gennady Sakharov and Cüneyd Zapsu

There were several changes at the Akkuyu Nuclear JSC Board of Directors over the years, but two of these are particularly noteworthy. Gennady Sakharov, the Director of Capital Investments, State Construction Supervision and State Expertise of Rosatom was arrested on 28 March 2024 on bribery charges.827 His “request to resign from the Board of Directors of Akkuyu Nuclear JSC”, as it is labeled in the Trade Registry Gazette, was to be discussed at Akkuyu Nuclear JSC’s General Assembly Meeting on 29 March 2024.828 Sakharov may face up to 15 years in jail.829

Beside Sakharov, another board member of Akkuyu Nuclear JSC is also facing trial. Henri Proglio, former CEO of French state-controlled utility EDF from 2009 to 2014, is on trial at the Paris Criminal Court accused of favoritism in the award of 44 consultancy contracts worth €36 million (US$39 million) omitting the required competitive bidding process.830

On 24 July 2024, Akkuyu Nuclear JSC announced managerial changes and the CEO Anastasia Zoteeva was replaced by Anton Dedusenko.831 Media saw this change as a termination not a handover.832

Another significant managerial change, officialized in December 2022, that attracted media attention was the resignation of Cüneyd Zapsu, who had previously served as an advisor to President Erdoğan.833 Zapsu was the only Turkish citizen to ever make it to the board, and since his departure there has been no Turkish representation on the Board of Directors of Akkuyu Nuclear JSC.834 Zapsu had initiated legal proceedings against the company prior to his resignation, citing a national security issue with Russia—a radar system to be installed at the nuclear power plant—as the reason for the dispute.835 Cüneyd Zapsu also asserted that a disagreement with the subcontractor company resulted in an additional US$2 billion loss for the NPP company.836

Nuclear Waste

Türkiye does not currently have a permanent or temporary waste repository. The intergovernmental agreement stipulates that Akkuyu Nuclear JSC is responsible for the decommissioning of the power plant and waste management, but this responsibility is limited to its contribution to the relevant fund.837 According to the environmental impact assessment report, used nuclear fuel will be sent to Russia.838 However, Akkuyu Nuclear JSC on its old website had the following information: “If Turkey wants to buy the waste, it [the spent fuel] could stay in Turkey.”

The Akkuyu JSC’s former Vice President, Rauf Kasumov, discussed the issue of low- and medium-level waste in a TV interview with BloombergHT in 2014, and he stated that these waste categories would remain in Akkuyu.839 In 2022, correspondence between the Gendarmerie and the Directorate of Environment and Urbanization revealed that a “Radioactive Waste Disposal and Storage Site” spanning 4 million square meter was planned to be built in the grassland of the Polatlı district of Ankara.840 There is limited information available about the nuclear waste management plans in Türkiye, and the messages are confusing.

Opinion Polls

Despite the ongoing construction of a nuclear power plant in Mersin province, surveys indicate a strong anti-nuclear sentiment in Türkiye. In one of the latest Konda surveys, carried out in November 2022, 77 percent included nuclear energy amongst two power plant technologies they would be “most opposed to”.841 This rate was 75 percent in September 2021.842 In 2021, Konda conducted another study and found that a total of five percent of respondents indicated a preference for the use of nuclear power plants to generate electricity.843

Energy Outlook

Türkiye’s installed electricity generating capacity had reached 110 GW by the end of May 2024.844 Thermal power plants account for the largest share in the power mix, with a total capacity of 49 GW, while hydroelectric power plants represent the second largest source, with 32-GW capacity. With recent additions, wind and solar power capacity passed 27 GW (12 and 15 GW respectively), as of 1 June 2024. In 2023, with over 3 GW, solar energy was by far the largest contributor to the annual capacity additions.845 The peak demand for Türkiye remains low compared to the installed capacity; at its highest, demand reached 55 GW on 26 July 2023.846

Two recent plans offer insights into the government’s vision for Türkiye’s energy future. The “Türkiye National Energy Plan”, released at the end of 2022, outlines a strategy to increase the installed capacity of wind energy to 29.6 GW and solar energy to 52.9 GW by 2035.847 The Türkiye National Energy Plan indicates that hydroelectric power plants are expected to have an installed capacity of 35.1 GW, while geothermal and biomass power plants would have a combined 5.1 GW installed capacity. If that happens, Türkiye will have 122.7 GW of renewable energy capacity by 2035.

The Plan foresees adding 2.4 GW in gas power plant capacity by 2030, and possibly a further 10 GW by 2035 “in addition to the abovementioned investments to contribute to the management of the imbalance of intermittent renewable energy plants in the system, and to the sustainability of energy supply security.” By 2030, 1.7 GW of coal power capacity is to be added. By 2035, a further 1.5 GW of coal and 7.2 GW of nuclear capacity (including Akkuyu) would be available, according to the Plan.

As a result, by 2035, as shown on Figure 42, thermal sources would still cover 34.2 percent of the power production with 17.7 percent provided by wind, 17.3 percent by hydro, 16.5 percent by solar, 11.1 percent by nuclear, and 3.2 percent by biomass and geothermal.

1. 2025–2035 Targets for Electricity Generation in Türkiye

Sources: Türkiye National Energy Plan 2022 and TEIAŞ, 2024848

The Twelfth Development Plan approved on 31 October 2023 also includes some indications on the country’s energy planning. The plan anticipates that the total installed capacity will reach 136 GW by 2028, including 18 GW of wind power, 30 GW of solar power, and 5 GW in battery storage. Renewable energy is planned to cover 50 percent of the electricity generation by 2028 and all four units of the Akkuyu nuclear plant are expected to be operational. Efforts are to be pursued to further increase the installed nuclear power capacity, including through new technologies “such as small modular reactors, fusion technologies, and advanced generation reactors.”849

Due to the struggling economy, electricity demand stagnated and the high price of gas led to cheaper imported coal taking over. In 2023, for the first time in Türkiye’s history, thermal power plants running on imported coal became the leading source of electricity generation with a share of 22.3 percent.850 The share of fossil fuels in the electric mix was 57.8 percent and that of renewables including hydro was 41.9 percent. Non-hydro renewables contributed 22.4 percent of the total electrical energy generated in the country in 2023 with wind contributing 10.5 percent, solar 5.8 percent, geothermal 3.4 percent, and biomass 2.7 percent.851 (See Figure 43)

1. Electricity Production by Source in Türkiye

Source: Energy Institute, 2024

In the past five years, electricity consumption has increased by an average of 4.5 percent per year but drew a fluctuating graph. In one of the five years it increased by more than 8 percent, while in another two (including in 2023) it slightly declined.852 The reference scenario of Turkish Electricity Transmission Company’s (TEİAŞ) 10-Year Demand Forecast Report, released in March 2023, estimated that the electricity demand would be 335 TWh for the running year, over 358 TWh in 2025, and 450 TWh in 2032.853

In reality, Türkiye’s electricity consumption was 330 TWh in 2023,854 i.e. above the low case scenario but below the reference scenario and far below the high case scenario of 352 TWh.855

Ukraine Focus

The war in Ukraine, following Russia’s aggression and full-scale invasion in February 2022, continues to cause destruction and death on a level not seen in continental Europe for close to 80 years.

Ukraine has 15 operating or operable reactors, two of which are VVER-440 designs, and the rest are VVER-1000s. These include six units at Zaporizhzhia that have been closed for nearly two years and enter the LTO category as of end-2022.856

Nuclear power provided 49.8 TWh or about 51 percent of power generation in the country in 2023, according to the Statistical Review of World Energy857; this is a fall from over 80 TWh before the war partly because the control of the Zaporizhzhia power plant in the East, which houses six VVER-1000 reactors, has been under the control of the Russian military.

The country has four closed reactors at the Chornobyl nuclear power plant, including Unit 4, which underwent a disastrous accident in 1986. Three nuclear reactors (two VVER-440s and one VVER-1000) at Rivne have been granted lifetime extensions of 20 years,858 and three units at South Ukraine, one at Khmelnytskyi and five units at Zaporizhzhia for ten years respectively. Following its 10-year extension, the license of Unit 1 at the South Ukraine plant was set to expire in December 2023, but it was extended in November of that year for another ten years.859 Licenses of even more units will expire before 2030, and all others will expire before 2040.860 Ukraine has carried out a safety upgrade program for all its reactors at an estimated cost of €1.45 billion (US$20131.9 billion) in total, of which the European Bank for Reconstruction and Development (EBRD) and Euratom contributed €600 million (US$2013797 million) in loans between them.861

Newbuild Projects

Two reactors, Khmelnytskyi-3 and -4 (IAEA spelling, also spelled Khmelnytskyi) have been officially under construction since 1986 and 1987 respectively, but WNISR removed them from the construction list as no active work has been reported in over three decades, despite several attempts to revive the project. While preparatory work seems underway, according to a knowledgeable Ukrainian source, no actual construction activity is being carried out. The Ukrainian Government appears however determined to have the units finished as they believe this is a way to address the current energy crisis, but it seems to some experts as misguided.862

In 2018, the government approved a feasibility study announcing an 84-month construction schedule, allowing for commissioning the first unit in 2025.863 Reportedly, preparatory works resumed in August 2020.864 In September 2020, a Presidential decree instructed the Cabinet to submit a series of legislative bills for Ukraine’s power sector, including a long-term program for developing nuclear energy to 2035 and addressing the two units’ “location, design, and construction”.865 At the time, suggestions were that the total cost of completing Khmelnytskyi-3 and -4 was estimated at UAH76.8 billion (US$20202.8 billion).866 There has been no independent evaluation of the cost estimate, that some Ukrainian experts—who do not wish to be named—say could be “much higher”.

In January 2023, the Cabinet of Ministers approved a feasibility study for constructing two Westinghouse AP-1000 reactors, Khmelnytskyi-5 and Khmelnytskyi-6, with preparatory work to continue until 2025 when construction officially begins and to have them operational in 2032, with an expectation that they would cost around US$5 billion each. Reportedly, Ukraine’s Energy Minister stated on that occasion, “We hereby finally renounce Russian nuclear technologies in our nuclear power industry.”867 The timeline and cost do not appear realistic if compared with historic experiences, e.g. the U.S. Vogtle plant that took more than 10 years to complete at a cost over three times the amount announced for Ukraine.

In January 2024, Energy Minister German Galushchenko announced that Ukraine intended to build four plants at Khmelnytskyi, with construction to start in 2024. This would include completing two Russian designed VVERs with equipment from Bulgaria, cannibalizing the part-build Belene power plant, as well as the two Westinghouse AP-1000s.868 In February 2024, Energoatom stated they had almost wholly restored Unit 3, and the onsite equipment was ready to be installed.869 Ukrainian experts questioned by WNISR claim that the equipment is “not complete” and that there would be, so far, “no agreements to manufacture the missing equipment”. The same experts state that as of mid-2024, “there is no law authorizing the construction of Units 3 and 4, no design, no safety report, no construction license”.

In April 2024, it was announced that a “symbolic cubic meter” of concrete was poured in front of U.S. and Ukrainian officials. The CEO of Westinghouse, the French elite engineer Patrick Fragman, was reported by Energoatom as saying that “The two twin units that were recently commissioned in Georgia, the US state, [Vogtle-3 and -4] are identical to the power units that will be built here, at the Khmelnytsky NPP.”870 According to the same Ukrainian sources previously quoted, the current situation is similar to that of Units 3 and 4, that is a lacking feasibility study, no safety report, no construction license.

In April 2023, the Cabinet of Ministers approved a new Energy Strategy for Ukraine until 2050.871 In an attempt to increase energy security and meet climate commitments by phasing out the use of fossil fuels, it targets nuclear power providing at least 50 percent of power and renewables providing 27 percent of final energy by 2030.872

Ukraine has deployed efforts to move away from dependency on Russia for its nuclear fuel, with Westinghouse providing fuel for some VVER 1000 reactors since 2005. (See also Russia Nuclear Dependencies). In June 2022, Energoatom and Westinghouse signed a contract covering the fuel supply for all 15 Ukrainian reactors and any future AP-1000 units.873 In September 2023, the first VVER 440 fuel assemblies delivered by Westinghouse were loaded at the Rivne plant,874 and in March 2024, VVER 1000 fuel assemblies were delivered to the Khmelnytskyi facility.875

In September 2023, Energoatom and Westinghouse signed an MoU on the development and deployment of an AP300, an SMR. The MoU established a joint working group to develop licensing, contracting, and local supply chains. Westinghouse is hoping that certification could take place by 2027 and construction start in 2030.876

Power Sector in War Conditions

From the outset of the full-scale invasion of Ukraine by Russia, starting in February 2022, energy infrastructure has been targeted and seriously damaged. The consequences of the war on the energy sector were further impacted by two factors, firstly that Russia (26 percent) and Belarus (22 percent) supplied nearly half majority of Ukraine’s imported energy, and secondly that the now-occupied regions in the East of Ukraine host the country’s largest nuclear power station, at Zaporizhzhia, as well as 30 percent of Ukraine’s solar capacities and 90 percent of its wind power capacities.877

In the first few months of 2024, Russia increased the intensity of its attacks on Ukraine’s infrastructure, particularly energy, resulting in the damage or destruction of up to 90 percent of fossil fuel and 60 percent of hydropower plants.878 Other figures suggest that 35 GW out of a total capacity of 55 GW of generating capacity in the power sector is inoperable.879 This has resulted in the introduction of power rationing, even as this was written in the summer of 2024, raising serious concerns over the up-and-coming winter and the consequences for the population and economy.880

The international community has recognized the seriousness of the situation, and the G7 and Energy Coordination Group, at the “Ukraine Recovery Conference” in June 2024, vowed to “commit to continue to support Ukraine with significant emergency assistance to help repair and stabilize the energy grid and restore power generation, first and foremost in preparation for the next winter,” and further noted that the G7 and partners had made available US$3 billion for the Ukrainian energy sector. The statement further said that they “collectively reaffirm our unwavering commitment to supporting Ukraine’s goal of rebuilding its energy system to be secure, sustainable, more decentralised and smarter, fit for a Net Zero future and integrated with the European market.”881

There is increased focus on rebuilding Ukraine’s power sector with a more decentralized renewable energy approach to meet decarbonization targets but also to add security, as Germany’s Minister for Economic Affairs and Climate Action, Robert Habeck, reportedly explained at the Ukraine Recovery Conference, “renewable energies also have a safety aspect. One nuclear power plant is an easy target, 10,000 solar panels are more difficult to shoot.”882

Before the Russian invasion, proposals were developed to introduce a direct power line from Khmelnytskyi-2 to the European market. The Ukraine-E.U. Energy Bridge project, with an estimated cost of €243.5 million (US$2019273 million), was to be carried out in the form of a public-private partnership between the Ukrainian state and an investor consortium consisting of Westinghouse Electric Sweden, Luxembourg-based Polish Polenergia International, and U.K.-based EDF Trading.883 However, on 24 February 2022, Ukraine decoupled its grid from Russia and operated in isolation until 16 March 2022, when it became synchronized to the E.U.’s grid.884

While initially connections to the West enabled some electricity exports from Ukraine to raise revenues, they are now used to import. Recently, Ukrainian authorities called for an increase in capacity from 1.7 GW in June 2024 to 2.3 GW before the winter 2024–25, which would also require strengthening of the grid and export links from Romania and Hungary.885

In June 2022, Ukraine was granted candidate status to the E.U., and its first intergovernmental conference was held in June 2024.886 The Accession process will require considerable changes to Ukraine’s energy sector, including issues around energy market reform, energy efficiency, and the deployment of renewable energy. Ukraine will need to implement an ambitious national energy and climate plan in line with the 2030 Energy Community energy and climate targets. Some requirements concern directly the nuclear power sector, e.g. turning Energoatom into a joint stock company of the public sector and appointing an independent supervisory board, which is in the direction of the E.U.’s framework on nuclear safety. However, as the European Commission noted, “Gaps exist in the field of radiation protection of personnel, the population and the environment and on radioactive waste and spent fuel management.”887

Russian Attacks on Nuclear Facilities

Russia invaded Ukraine from several directions: from the North via Belarus, from the South through Crimea and from the East through Donetsk and Luhansk. Russian forces (accompanied from day one by Rosatom staff) immediately sought to take control of nuclear facilities, first the Chornobyl facility in the North on 24 February 2022, but troops were withdrawn on 31 March as Ukrainian troops were approaching. Then, the unprecedented attack on an operating civil nuclear power plant at Zaporizhzhia (ZNPP), Europe’s largest by installed capacity, took place on 4 March 2022, followed by a military takeover of the facility. The same month, attempts of a military takeover of the South Ukraine nuclear power plant were thwarted by Ukrainian Forces.888

In September 2022, President Putin formally declared that the regions of Luhansk, Donetsk, Kherson and Zaporizhzhia were part of Russia and then in October 2022, in violation of international law, Vladimir Putin signed a decree that transferred ZNPP to Russian jurisdiction managed by Rosenergoatom, a Rosatom subsidiary. Rosenergoatom established a “Russian Federal State Unitary Enterprise ZNPP” to operate the plant.889 The IAEA has acknowledged that they have no authority to enforce any of the resolutions that have been passed by the United Nations organization calling on Russia to withdraw from the power plant.890

In June 2023, the State Nuclear Regulatory Inspectorate of Ukraine (SNRIU) issued an order for all six reactors of the ZNPP to be put into cold shutdown.891 However, Russia decided to keep one unit in hot shutdown (generating steam but no power), which serves “various nuclear safety purposes including the processing of radioactive waste collected in storage tanks,” according to the IAEA.892 The situation changed in April 2024 at the end of the winter heating season, as the remaining unit was used to heat the nearby city of Enerhodar (home to power plant staff), and as of mid-2024 it was in cold shutdown.893

The concerns over the safety and security of ZNPP are related to the ongoing operation/management of the facility, the use of the facility as a launchpad for military operations and the threats of deliberate or accidental attacks on the facility.

The war is affecting the ability of the plant management to undertake the necessary maintenance of the plants due to the lack of permanent staff—the IAEA noted that in May 2024, the plant employed 5,000 people, with a further 800 positions remaining unfilled894—absence of external contractors, and lack of spare parts, including critical components. The IAEA stated that in April 2023, at the Zaporizhzhia plant, there was only about one-quarter of its regular maintenance staff, which affected safety and security.895 The IAEA reported also that supply chain logistics remain fragile.896 IAEA Director General Grossi stated in May 2024:

The world’s attention is rightly focused on the continued danger of Europe’s largest nuclear power plant being hit or losing its off-site power. But there are several other challenging areas that we must continue to monitor closely to help prevent the risk of a nuclear accident, including maintenance, as well as staffing and the availability of spare parts. They all form part of our deep concern regarding nuclear safety and security at the plant.897

Research undertaken by the Ukrainian NGO Truth Hounds documents cases of systematic detention, mistreatment, and torture of citizens associated with the ZNPP.898

In its February 2023-report, the IAEA documents 13 occasions in the first year of the conflict in which the power station was either shelled or mined and 16 occasions where it was fully or partially disconnected from the grid—external power is needed to continuously cool the reactors and spent fuel even if the reactors are shut down (see Nuclear Power and War in WNISR2022).899 The IAEA noted in early 2024 that “the status of the off-site power supply to the ZNPP remained vulnerable throughout the reporting period.”900 In a later report, the IAEA also documented occasions in which the facility was attacked by drones, including in April 2024, when it was observed that there was damage, but not critical to nuclear safety, to the containment dome of Unit 6, which, according to the IAEA, was the first time since November 2022 that the facility had come under direct attack.901

There are no continuous independent observers at nuclear facilities in Ukraine. It is thus impossible to make affirmative, definitive assessments of the situation. Only the IAEA has representatives at the Ukrainian nuclear power plants.

It is not just direct attacks on the nuclear facilities that threaten their safety. The IAEA also reported that on 23 and 24 November 2022, the Rivne, South Ukraine, and Khmelnytskyi nuclear power plants were automatically disconnected from the grid due to decreased grid frequency.902

In early June 2023, an explosion at the Russian-controlled Kakhovka dam in Southern Ukraine resulted in its breech and the flooding of vast amounts of land and numerous settlements, but the dam also retained the cooling water, the ultimate heat sink, for Zaporizhzhia.903 As ZNPP was not operational at the time and mainly in cold shutdown, there was only a limited immediate impact on the plant. Following the explosion, the Ukrainian nuclear regulator issued the previously mentioned order for the remaining reactor in hot shutdown, Unit 5, to be moved to cold shutdown, but the Russian occupiers of the plant ignored the request.904 The destruction of the dam was described in June 2023 as “ the worst act of ecocide that Russia has committed since the beginning of its full-scale invasion of Ukraine” by the Ukrainian Environment Minister, Ruslan Strilets, referring to the destruction caused by the flooding and resulting pollution.905

Despite the international condemnation and the clear and immediate danger of the shelling and bombing of a nuclear facility as well as its power and water supplies, reportedly, attacks and threats of attacks have continued.

United Kingdom Focus

As of mid-2024, the United Kingdom (U.K.) operated nine reactors, the same as in the previous edition of the WNISR. The average fleet age is 37.1 years (see Figure 45). The last reactors to close were the two units at Hinkley Point B on 6 July 2022 (B-2) and 1 August 2022 (B-1), respectively. This followed the closure of the two reactors at Hunterston in 2021 and 2022, and two units at Dungeness officially closed in 2021 (last power generation in 2018, see Figure 44).

In total, 36 nuclear reactors have been closed in the U.K., the second largest number of any country behind the United States (see United Kingdom in Decommissioning Status Report). This includes all 26 Magnox reactors, two fast breeders, one small Steam-Generating Heavy Water Reactor (SGHWR), and seven Advanced Gas Reactors (AGRs). There is now 5.8 GW of nuclear capacity in operation, with 7.8 GW awaiting decommissioning.

1. U.K. Reactor Startups and Closures

Sources: WNISR with IAEA-PRIS and EDF Energy, 2022–2024

Type of Reactors: AGR: Advanced Gas Reactors; FBR: Fast Breeder Reactor; PWR: Pressurized Water Reactor; SGHWR: Steam-Generating Heavy Water Reactor

In 2023, electricity generated from nuclear power decreased over the previous year, going from 43.6 TWh (14.2 percent of electricity) to 37.3 TWh (12.5 percent), down from a maximum share of 28 percent in 1997.

Eight of the nine operating reactors are AGRs in pairs at Torness, Heysham (four reactors), Hartlepool, and one PWR at Sizewell. All operating AGRs were completed in the 1980s, while Sizewell B started operating in 1995.

Managing reactors as they age is a constant problem of any technology design, and the AGRs are no exception. As has been commented on in previous editions of the WNISR, issues with the core’s graphite moderator bricks have raised concerns. Previously, Hinkley Point B and Hunterston B were due to operate until 2023, while Dungeness B was due to operate until 2028, however, by early 2022, the situation had changed dramatically. With ongoing graphite issues and other age related problems, EDF officially closed Dungeness B-1 and -2 in June 2021, Hunterston B in January 2022, and Hinkley Point B in July/August 2022.906 In January 2024, EDF announced that it was planning to extend the operating lifetimes for eight reactors, two each at Torness, Heysham A and B, and Hartlepool and that a decision would be taken by the end of 2024.907

Hartlepool and Heysham A were due to close in 2024, but EDF delayed closure by two years in March 2023908 “with a plus or minus one year window on either side of this date” according to Centrica.909 The Office for Nuclear Regulation (ONR) has said that while a plant life extension does not require formal approval, EDF must produce updated safety cases for the plants, which the regulator will assess.910 (See Table 9)

1. Status of U.K. EDF AGR Nuclear Reactor Fleet (as of 1 July 2024)

Source: EDF Energy, 2024

« The Nuclear Decommissioning Authority (NDA), overseen by DESNZ [the Department for Energy Security and Net Zero], does not fully understand the UK’s civil nuclear sites, making it difficult to judge the cost and timescale of decommissioning them »

Public Accounts Committee – U.K. Parliament

The decommissioning cost estimates for nuclear, military, and civil facilities continue to rise. According to the Public Accounts Committee of the Parliament, “The Nuclear Decommissioning Authority (NDA), overseen by DESNZ [The Department for Energy Security and Net Zero], does not fully understand the UK’s civil nuclear sites, making it difficult to judge the cost and timescale of decommissioning them,” and they further say that “currently, the NDA estimates that decommissioning the UK’s civil nuclear sites will cost £132 billion [US$2020169 billion] and take until 2333,” some 300 years from now.911 The annual cost of decommissioning civil nuclear facilities owned by the NDA for 2022–2023 is £4.69 billion (~US$20245.9 billion)912 (for more details on decommissioning in the U.K. see United Kingdom in Decommissioning Status Report). When defueling the AGRs is complete, ownership and responsibility for carrying out and paying for decommissioning will pass from EDF to NDA.

1. Age Distribution of U.K. Nuclear Fleet

Sources: WNISR, with IAEA-PRIS, 2024

Pathways to Net Zero

Total electricity generation fell by 11 percent in 2023—to the lowest level in 30 years—partly due to continuing reductions in demand and high volumes of imported electricity. Despite leaving the E.U., the U.K. continues trading electricity with the continental and Irish electricity and gas markets. Over the past few years, electricity interconnector capacity has increased to enable a significant exchange volume, bringing market stability across Europe. The generation of electricity from fossil fuels decreased by 22 percent in 2023 to 103.8 TWh, its lowest level since the 1950s. Production from nuclear power also decreased by 15 percent, to 37 TWh, providing just 12.5 percent.

The generation of electricity from fossil fuels decreased by 22 percent in 2023 to 103.8 TWh, its lowest level since the 1950s

The electricity mix in the U.K. has changed rapidly over the past decades, as seen in Figure 46. The most significant trend was the rapid reduction in the use of coal; economic and environmental considerations drove this decline, and it has gone from providing about one-third of the electricity generated in the U.K. in 2000 to less than 2 percent in 2023, while renewables have grown so that they provided 47 percent from 2.8 percent at the turn of the century.

1. Electricity Generation by Source in the U.K. – The Coal Plunge

Source: DUKES, U.K. Government, 2024913

The U.K. has set one of the world’s most ambitious greenhouse gas emissions targets, committing to a 68 percent reduction from 1990 levels by 2030 and 78 percent by 2035914 compared to a 52 percent reduction to 384 Mt CO2e achieved in 2023.915

The Conservative Administrations (2010–2024)

Since 2010, when David Cameron was elected, there have been four consecutive Conservative administrations headed by Theresa May, Boris Johnson, Liz Truss, and then Rishi Sunak. All of these governments have supported nuclear power. In 2010, the Conservative Party pledged to encourage new low-carbon energy production, including “clearing the way for new nuclear power stations – provided they receive no public subsidy.”916 Then, in 2015, the Conservatives pledged, “We need a Conservative Government to see through this long-term plan and secure clean but affordable energy supplies for generations to come. This means a significant expansion in new nuclear and gas (…).”917 In 2019, they said, “We will support gas for hydrogen production and nuclear energy, including fusion, as important parts of the energy system, alongside increasing our commitment to renewables” [emphasis in bold replicated from the original document].918

In November 2020, the U.K. Government published The Ten Point Plan for a Green Industrial Revolution, which included a specific point on “Delivering New and Advanced Nuclear Power”.919 The plan put forward milestones for the sector, including the completion of Hinkley Point C (HPC) in the mid-2020s and the deployment of the first SMRs in the early 2030s. In December 2020, the government published a long-awaited Energy White Paper, which stated that the aim was to

bring at least one large-scale nuclear project to the point of Final Investment Decision by the end of this Parliament [2024], subject to clear value for money and all relevant approvals.920 [emphasis in bold from the original document]

In an accompanying press statement, the government said it would begin negotiations with EDF on Sizewell C.921 However, the approval requires a “value-for-money” hurdle to be passed, which could be challenging given the current economics of nuclear vs. renewables. This timetable was unmet, and no decision was made before the July 2024 election. The government also further outlined a plan for the development projects, including to “develop an overall siting strategy for the long term” targeted at eight designated nuclear sites (listed in this order): Hinkley, Sizewell, Heysham, Hartlepool, Bradwell, Wylfa, Oldbury, and Moorside.922

The government announced upon release of its British Energy Security Strategy published in April 2022 that “a new government body, Great British Nuclear [GBN], will be set up immediately to bring forward new projects, backed by substantial funding” and that it would “launch the £120 million [~US$2022148 million] Future Nuclear Enabling Fund this month.”923 However, it was not until the following year, in July 2023, that GBN was finally launched, and the statement announced “a massive revival of nuclear energy” and a “rapid expansion of new nuclear power plants in the U.K. at an unprecedented scale and pace.”924 There were two main elements of the launch:

• the announcement of a competition to get support for the construction of SMRs; and
• the award of £157 million (~US$2023195 million) of grant funding. This includes:
  • £77 million (~US$202396 million) for businesses to accelerate advanced nuclear designs,
  • £58 million (~US$202372 million) for further development of a new generation of SMRs that operate at higher temperatures—with three winning projects announced—and
  • £22 million (~US$202327 million) from the Nuclear Fuel Fund, allocated to fuel fabrication facilities for the development of a new type of nuclear fuel—High-Assay Low-Enriched Uranium (HALEU).925

The level of funding so far allocated, while politically relevant, will contribute only a small proportion of the costs needed to bring the designs to commercial deployment. In July 2023, the Parliament’s Science, Innovation and Technical Committee published a report reviewing the government’s nuclear plans. The Committee mainly supported nuclear power and the former government’s objective of having 24 GW of new nuclear in addition to HPC by 2050 but strongly questioned its (lack of) strategy to meet the goal. In particular, the Committee asked the government to clarify the role of Great British Nuclear beyond initially supporting SMRs and how it would engage with any projects beyond Sizewell C.926 The government responded to the Committee’s report and stated it was developing a “new nuclear National Policy Statement,” which would “cover the deployment of new nuclear power stations beyond 2025.”927

Over the fourteen years of the continually supportive set of administrations for nuclear power, the industry has declined.

Over the fourteen years of the continually supportive set of administrations for nuclear power, the industry has declined. Twelve reactors have closed; the only reactors under construction, at Hinkley Point C, have suffered extreme cost overruns and delays (see Hinkley Point C, below); and nuclear’s contribution to power production continues to decrease.

Labour Government

In May 2024, Rishi Sunak, the then Prime Minister, surprised many by calling for an early election on 4 July 2024 despite being significantly behind in the opinion polls—the administration could have remained in post until the end of the year. The party’s level of support did not increase, and the Labour Party, under Sir Keir Starmer, won the election with a considerable majority. This should enable the Party to be more ambitious about its agenda as it will not have to rely on other parties’ votes and risk disagreements with internal factions without derailing policy implementation.

At the heart of the incoming government’s energy and climate policy is said to be a new “Energy Independence Act”.928 It will support establishing a publicly owned energy company—Great British Energy, which will be capitalized with £8.3 billion (US$10.5 billion) from the government over the next five years and is to be designed to support capital-intensive low-carbon technologies. The objective for renewables is to “double onshore wind, triple solar power, and quadruple offshore wind by 2030.” In 2023, offshore wind generated 17.3 percent of power, onshore wind 11.4 percent, and solar 4.9 percent. Therefore, meeting these targets would mean that generation from solar and wind alone would exceed current levels of electricity consumption in the U.K., which is an extremely ambitious target. However, there is an opportunity for the government to facilitate the acceleration of renewable energy, with proposed changes in the planning laws. This is particularly pertinent as it has been shown that over 60 percent of renewable and battery projects in 2018–2023 have been stopped during the planning phase, which is partially a result of speculative applications but also an indication that the planning system does not have sufficient resources to process all the applications.929

On nuclear power the Labour Party has pledged to “ensure” the extension of the lifetime of existing reactors and get Hinkley Point C completed, neither of which is under its control, while also supporting the completion of Sizewell C and SMRs.930 Under the new government it is likely that Great British Nuclear, will become part of Great British Energy.

Nuclear Newbuild

The U.K. has one power station with two reactors under construction at Hinkley Point C, and one project with two units awaiting a Final Investment Decision (FID) at Sizewell C. Both projects are based on the Franco-German European Pressurized Water Reactor (EPR) design. The development of two new reactors at Bradwell, using the Chinese Hualong One design, has been halted. While the regulator completed the Generic Design Assessment (GDA) of the Hualong One, the project did not get beyond the study phase.

Hinkley Point C

The regulator concluded its five-year GDA of the U.K. EPR in December 2012, and EDF Energy was given planning permission to build two reactors at Hinkley Point in April 2013. (For more detailed information see previous editions of WNISR). In October 2015, EDF and the U.K. Government announced updates to the October 2013 provisional agreement of commercial terms of the deal for the £16 billion (US$201325 billion) overnight construction cost of Hinkley Point C (HPC).931 The Chinese company China General Nuclear Power Group (CGN), a state-controlled company, agreed to meet 33.5 percent of the investment in the FID. The estimated cost of construction has since risen at the following times:

• In 2017, it stood at £201519.6 billion (~US$201530 billion).932
• In September 2019, EDF announced new completion cost (still in 2015 values) of between £21.5 billion (US$201532.8 billion) and £22.5 billion (US$201534.4 billion).933
• In March 2022, EDF confirmed that Unit 1 is expected to generate power in June 2026, compared to end-2025 as announced in 2016. The project completion costs were then estimated in the range of £201522–23 billion (US$201533.6–35.1 billion).934
• Less than three months later, in May 2022, EDF announced that cost estimates had further risen to between £201525–26 billion (US$201538.2–39.7 billion) and that its start-up would be delayed by an additional year to June 2027.935
• In February 2023, EDF announced that the costs had risen to £32 billion (US$202144 billion) (note the previous £26 billion figures were in 2015 values, while £32 billion is in 2021 values, and so some of the rise in costs is inflationary).936
• In January 2024, further cost increases and delays were announced, with a new expectation that in 2015 prices the likely costs would be between £31–35 billion, with completion of unit one expected to be between 2029–2031.937 Or in current values in the order of £41.3–46.6 billion (US$52.5–59.2 billion), which has led to the French Government putting pressure, unsuccessfully, on the U.K. Government to help foot the bill for the cost overruns.938

The critical point of the deal was a Contract for Difference (CfD), effectively a guaranteed real electricity price for 35 years, which, depending on the number of units ultimately built, i.e. whether construction at Sizewell C proceeded, would be £89.50–92.50/MWh (US$2012141–146MWh), with annual increases until and from startup linked to the Consumer Price Index.939 In early 2020, EDF broke down the £92.50/MWh (US$2012146/MWh) strike price:

• overnight construction costs, excluding financing: only £11 (US$201217.4);
• operating and maintenance costs: £19.5 (US$201230.8);
• financing costs for “typical regulated asset without construction risk”: £26 (US$201241);
• first-of-a-kind construction risk: £36 (US$201257) to cover.940

EDF did not provide details of these calculations, so it is not possible to assess their accuracy.

Within the original 2016-CfD agreement, EDF is to receive a 35-year firm price per MWh, but if commercial operation starts after November 2029, the CfD is reduced in length, one year for every year of delay until 2033. This is the “longstop date”, after which the contract could be canceled if the project is not completed. On 29 November 2022, the longstop date was extended from 1 November 2033 to 1 November 2036.941

The expected composition of the consortium owning the plant changed from October 2013 to October 2015 with the effective bankruptcy and dismantling of AREVA, making their planned contribution of 10 percent impossible; the Chinese stake, through CGN, fell to 33.5 percent from 40 percent; and the other investors (up to 15 percent) had not materialized, leaving EDF with 66.5 percent rather than 45 percent it had hoped for in 2013.

The rising construction cost and its increased share have impacted the amount EDF has to pay. As of 2020, the cost of EDF’s expected project share had increased by about 150 percent since 2013.942 Responsibility for any delays and cost overruns falls solely on EDF under the CfD model, and when the company realized the scale of risk this entailed, it pushed for change. In response, in June 2022, the British Government set out its case for Sizewell C to be built under the Regulated Asset Base (RAB) rather than the CfD model.943

The costs of construction are continuing to cause problems for all parties, as the total financing needs exceed the contractual commitments of the shareholders. In the latter half of 2023, the shareholders were asked for voluntary contributions to meet the additional costs, but CGN refused and so EDF is having to cover all additional costs. In 2024, EDF announced in its annual financial report that it had written off €12.9 billion (US$202314 billion) in costs associated with HPC assets and EDF Energy (the U.K. arm of the company).944

The HPC delays and cost overruns were part of the credit-rating agency Standard & Poor’s (S&P) rationale to downgrade EDF’s rating in February 2022,945 and its placement on credit-watch negative in May 2022.946 In the same rating action, S&P downgraded EDF’s U.K. subsidiary EDF Energy to BB, deep in speculative territory (“junk”) and put it on credit-watch negative for potential further downgrade. In July 2023, EDF was fully renationalized (see France Focus).

In June 2023, Moody’s published a credit opinion on EDF Group reporting the downgrading of the Baseline Credit Assessment (BCA) from baa3 to ba1 due to slow progress in its recovery, high and volatile wholesale electricity prices, and the group’s significant debt burden. Around Hinkley Point they said:

The increasing cost estimates illustrate the execution risks that EDF and CGN face in constructing the power station. In addition, EDF’s balance sheet will have to suffer the financial implications of a very long construction phase, given that the cost will have to be debt funded because the group has entered into a fixed-price contract-for-differences agreement with the U.K. government and has no ability to recover the higher costs from customers; and the investment will not generate any cash flow until the power plant is operational.947

In June 2024, S&P gave EDF a more positive outlook, with nuclear generation increasing in France and an expectation that income should be able to cover “finance interests and taxes, and most of EDF’s capex” and the costs linked to the renationalization. However, on the issue of current construction, including both Hinkley and Sizewell, S&P was less confident about EDF, saying that the company’s stand-alone credit profile will be affected by the risks of newbuild, particularly the construction of Hinkley and the latest three-year delay in completion of the units, as well as the uncertainty over the funding of Sizewell,948 see Sizewell C, below.

Sizewell C

Initially, it was proposed that EDF and CGN would develop a follow-on to HPC, the Sizewell C project, which would be a copy of HPC, with two EPR 1.6 GW units. Chinese investment was to be limited to 20 percent, leaving EDF with 80 percent of the company that would take the project to FID; neither party was obliged to take any share in the company that actually built, owned, and operated it. In 2022, EDF stated that it had planned to pre-finance the development of its share of the initial budget of up to £458 million (US$2022564 million), with no agreement to invest beyond that stage.949 On 24 June 2020, the U.K. Planning Inspectorate accepted the application for development consent received the previous month,950 and in July 2022, the government gave its development consent to build Sizewell C.951

EDF was optimistic that it could reduce construction cost and in 2020 estimated it would be £18 billion (US$202023 billion).952 However, it is also hoping to reduce the financing costs of Sizewell C by shifting from the CfD mechanism to the RAB model. EDF has suggested that with a better financing model and no “first-of-a-kind costs”, it could “peel away” the strike price by £36/MWh (US$201256.9/MWh).953 However, in its planning documents, EDF confirmed construction cost estimates of “circa £20 billion” (US$202025.6 billion).954

In March 2021, EDF’s financial report for 2020 said an FID was likely to be made in mid-2022 but used cautious language on the whole about the project, stating “to date, it is not clear whether the group will reach this target.”955 It went on to say:

EDF’s ability to make a[n] FID on Sizewell C and to participate in the financing of this project beyond the development phase could depend on the operational control of the Hinkley Point C project, on the existence of an appropriate regulatory and financing framework, and on the sufficient availability of investors and funders interested in the project. To date, none of these conditions are met.

Failure to obtain the appropriate financing framework and appropriate regulatory approval could lead the Group not to make an investment decision or to make a decision in less than optimal conditions.

In January 2022, the government reiterated its intention to see an FID on “at least one” large-scale nuclear project in the current Parliament—which has not been met. The government has also pledged £100 million (US$2022123.3 million) for EDF to “help bring it [the project] to maturity, attract investors and advance the next phase in negotiations.” In return, the government will take rights over the land of Sizewell C and EDF’s shares in the project company, “should the project not ultimately be successful.”956

In June 2022, the U.K. Government announced that it had taken out the £100 million option which would be converted into equity to take a 20 percent share in Sizewell C, should the project reach an FID.957 However, as noted above, this share of costs in the company that will take the project to FID has no bearing on the stake it takes in the successor company. In July 2022 the U.K. Government announced that Sizewell C had been granted development consent.

Then in November 2022, the U.K. Government made its Investment Decision and confirmed it was investing a further £679 million (US$2022837 million), of which it refused to say how much has been used to buy out CGN, although the press suggested that it was £100 million (US$2022123.3 million).958 The departure of the Chinese investors from the project means that the U.K. Government and EDF will now each take a 50 percent equity stake in the Sizewell C project. The government invested a further £511 million (US$2023635 million) announced in the summer of 2023, taking the total, at this stage, to £1.2 billion (US$20231.5 billion).959

It is expected that private investment will come into the project, as EDF has stat