The World Nuclear Industry Status Report 2022 (HTML)

Acknowledgments

The first thing to say is simply a huge, I mean a huge, huge thank you to the team that put the WNISR2022 together. The project has survived unfavorable if not adverse conditions for 15 years, but this year was simply unprecedented. For health and career reasons, several core contributing authors unexpectedly were not able to provide input this year. But… the extraordinary solidarity of the remaining team and a couple of exceptional contributors who together picked up the tab made it possible to produce this report together against all odds.

It has been 30 years that we produced a precursor WNISR. It has been 30 years that my friend Antony  Froggatt has been a solid partner in developing the report concept, contributing chapters, editing others, and presenting the outcome. Thank you for everything.

At the core of the WNISR is its database designed and maintained by data manager and information engineer Julie Hazemann who also develops most of the drafts for the graphical illustrations and manages much of the cooperation with designer and webmaster. She expanded her contribution significantly over the past few years. As ever, no WNISR without her. Thanks so much.

M.V. Ramana, over the years, has not only been a regular, reliable, professional, and insightful contributor but also a wonderful person to work with. Heartful thanks.

Very glad to count Tatsu Suzuki amongst the core team, following decades of cooperation under various circumstances and organizational arrangements. Thank you very much for your invaluable contributions.

Very happy to work with Michael Sailer again with whom I have crossed paths for some four decades now. Thank you for your crucial, timely contribution to this project.

Christian von Hirschhausen, thank you for being back on the project. Your constructive thinking and positivity are a real treat. Newcomer Alex Wimmers dived into the WNISR with skill and full engagement. Thank you and see you both next year!

Nina Schneider has further expanded her meticulous proof-reading, source verification, and fact-checking capacities. This year, she also drafted several sections of the report. Her production skills are indispensable to the outcome. Merci beaucoup.

Special thanks go to Tim Judson and another expert who not only filled in unexpected gaps but superbly mastered the tasks under impossible time constraints.

A big thank you to Aviel Verbruggen for his thought-provoking, generous foreword, delivered under unreal time constraints.

Artist and graphic designer Agnès Stienne created the redesigned layout in 2017 and is constantly improving our graphic illustrations that continue to get the praise they deserve around the world. Thank  you once again.

A big thank you also to Arnaud Martin for his continuous, highly reactive, and reliable work on the website www.WorldNuclearReport.org, dedicated to the WNISR Project.

For the fourth time in a row, we owe idea, design, and realization of the report-cover to renowned German painter Friedhelm Meinass and designer Constantin E. Breuer, (“who congenially implements my ideas”, dixit F.M.). Thanks so much for another striking, politically intelligent, and very generous contribution.

This work has greatly benefitted from partial proofreading, editing suggestions, comments, or other input by Anton Eberhardt, Frank von Hippel, Lutz Mez, Wenmin Yu, and others. Thank you all.

The authors wish to thank especially Geoff Fettus, Matthew McKinzie, Axel Harneit-Sievers, Tanja  Gaudian, Jutta Paulus, Christina Stober, and Fabian Lüscher for their enthusiastic and lasting support of this project.

And everybody involved is grateful to the MacArthur Foundation, Natural Resources Defense Council, Heinrich Böll Foundation, the Greens-EFA Group in the European Parliament, Elektrizitätswerke Schönau, and the Swiss Renewable Energy Foundation for their generous 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.

Lead Authors’ Contact Information

Table of contents

Acknowledgments

Foreword

Key Insights

Executive Summary and Conclusions

Introduction

General Overview Worldwide

Production and Role of Nuclear Power

Operation, Power Generation, Age Distribution

IAEA vs. WNISR Assessment

Overview of Current New-Build

Building vs. Vendor Countries

Construction Times

Construction Times of Reactors Currently Under Construction

Construction Times of Past and Currently Operating Reactors

Construction Starts and Cancellations

Operating Age

Lifetime Projections

Focus Countries

China Focus

Finland Focus

Fennovoima’s Hanhikivi Project Cancelled

The Olkiluoto-3 (OL3) Saga

France Focus

Introduction

After Worst Performance in Decades, Worse is Yet to Come

Nuclear Unavailability Review 2021

Lifetime Extensions – Fact Before License

Embattled Clientele, Financial Trouble, Volatile Market

The Flamanville-3 EPR Saga Continued

Germany Focus

Introduction

An Unexpected Debate Over Potential Lifetime Extensions

Nuclear Power vs. Renewables and Fossil Fuels

India Focus

Strong Push for Renewables

Ongoing Construction Experiencing Delays and Cost Overruns

Construction Plans and Reality

Japan Focus

Overview

Reactor Closures and Spent Fuel Management

Energy Policy and the Role of Nuclear Energy

Impact of Ukraine Crisis on Nuclear Power Debate

Prospects for Nuclear Power

South Korea Focus

South Korea Abandons Nuclear Phaseout Policy

Reactor Construction

Permanent Closure

Radiation Leakage at Wolsong NPP

Taiwan Focus

Reactor Closures

The Lungmen Saga

Energy and Climate Policy

United Kingdom Focus

Closure of the Advanced Gas-cooled Reactors  (AGRs)

Pathways to Net Zero

Security of Supply

Nuclear Newbuild

Conclusion

United States Focus

Overview

Large New Subsidies for Nuclear Power

Extended Reactor Licenses

Reactor Closures

Securing Subsidies to Prevent Closures

Reactor Construction

Criminal Investigations of Nuclear Power Corporations

Conclusion

Fukushima Status Report

Overview of Onsite and Offsite Challenges

Introduction

Onsite Challenges

Offsite Challenges

Health of Residents, Legal Cases, Compensation

Conclusion

Decommissioning Status Report 2022

Introduction

Elements of National Decommissioning Policies

Global Overview

Decommissioning Worldwide

Overview of Reactors with Completed Decommissioning

Overview of Ongoing Reactor Decommissioning

Country Case Studies

Decommissioning in selected countries

United States

Germany

Japan

Spain

United Kingdom

France

Italy

Lithuania

South Korea

Canada

Russia

Conclusion on Reactor Decommissioning

Potential Newcomer Countries

Bangladesh

Egypt

Nigeria

Poland

Saudi Arabia

Turkey

Suspended or Cancelled Programs

Indonesia

Jordan

Kazakhstan

Thailand

Uzbekistan

Vietnam

Small Modular Reactors

Argentina

Canada

China

France

India

Russia

South Korea

United Kingdom

United States

Conclusion

Nuclear Power and War

Introduction

Vulnerabilities of Nuclear Power Reactors and Spent Fuel Pools Due to Decay Heat

Nuclear Power Plants and Spent Fuel Storage in War

General Roles

Reasons for Military Action in Nuclear Power Plant Areas

Why it is Difficult to Exclude Nuclear Facilities from War

Specific Vulnerabilities of Nuclear Power Plants

Specific Vulnerabilities of Spent Fuel Storage Facilities

Possible Release Mechanisms and Scenarios

Timeline: War in Ukraine

Timeline

Nuclear Power vs. Renewable Energy Deployment

Introduction

Investment

Technology Costs

Installed Capacity and Electricity Generation

Status and Trends in China, the European Union, India, and the United States

China

European Union

India

United States

Conclusion on Nuclear Power vs. Renewable Energy

Annex 1 – Overview by Region and Country

Africa

South Africa

The Americas

Argentina

Brazil

Canada

Mexico

United States

Asia and Middle East

China

India

Iran

Japan

Pakistan

South Korea

Taiwan

United Arab Emirates

European Union (EU27)

Western Europe

Belgium

Finland

France

Germany

Netherlands

Spain

Sweden

Switzerland

United Kingdom

Central and Eastern Europe

Bulgaria

Czech Republic

Hungary

Romania

Slovakia

Slovenia

Former Soviet Union

Armenia

Belarus

Russia

Ukraine

Annex 2 - Status  of  Nuclear Power in  the World

Annex 3 – Nuclear Reactors in the World “Under Construction”

Annex 4 – Abbreviations

Annex 5 – About the Authors

Table of figures

Figure 1 · National Nuclear Power Program Development

Figure 2 · Nuclear Electricity Generation in the World... and China

Figure 3 · Nuclear Electricity Generation and Share in Global Power Generation

Figure 4 · Nuclear Power Reactor Grid Connections and Closures in the World

Figure 5 · Nuclear Power Reactor Grid Connections and Closures – The Continuing China Effect

Figure 6 · World Nuclear Reactor Fleet, 1954–2022

Figure 7 · World Nuclear Reactor Fleet – IAEA vs WNISR 1954–2021

Figure 8 · Nuclear Reactors “Under Construction” in the World (as of 1  July  2022)

Figure 9 · Nuclear Reactors “Under Construction” by Technology-Supplier Country

Figure 10 · Average Annual Construction Times in the World

Figure 11 · Delays for Units Started Up 2019–2021

Figure 12 · Construction Starts in the World

Figure 13 · Construction Starts in the World/China

Figure 14 · Cancelled or Suspended Reactor Constructions

Figure 15 · Age Distribution of Operating Reactors in the World

Figure 16 · Reactor-Fleet Age of Top 5 Nuclear Generators

Figure 17 · Age Distribution of Closed Nuclear Power Reactors

Figure 18 · Nuclear Reactor Closure Age

Figure 19 · The 40-Year Lifetime Projection

Figure 20 · The PLEX Projection (not including LTOs)

Figure 21 · Forty-Year Lifetime Projection versus PLEX Projection

Figure 22 · Age Distribution of Chinese Nuclear Fleet

Figure 23 · Operating Fleet and Capacity in France

Figure 24 · Startups and Closures in France

Figure 25 · Nuclear Electricity Production vs. Installed Capacity in France 1990–2022

Figure 26 · Nuclear Electricity Production vs. Nuclear Share in France 1990–2022

Figure 27 · Monthly Nuclear Electricity Generation 2012–mid-2022

Figure 28 · Reactor Outages in France in 2021 (in number of units and GWe)

Figure 29 · Forced and “Planned” Unavailability of Nuclear Reactors in France in 2021

Figure 30 · Scheduled vs. Realized Unavailability by Nuclear Reactor in France in 2021

Figure 31 · Unavailability of French Nuclear Reactors 2019–2021

Figure 32 · Age Distribution of French Nuclear Fleet (by Decade)

Figure 33 · Main Developments of the German Power System Between 2010 and 2021

Figure 34 · Rise and Fall of the Japanese Nuclear Program

Figure 35 · Status of the Japanese Reactor Fleet

Figure 36 · Age Distribution of the Japanese Nuclear Fleet

Figure 37 · U.K. Reactor Startups and Closures

Figure 38 · Electricity Generation by Source in the U.K. 2000–2021

Figure 39 · Age Distribution of U.K. Nuclear Fleet

Figure 40 · Age Distribution of the U.S. Nuclear Fleet

Figure 41 · Evolution of Average Reactor Closure Age in the U.S.

Figure 42 · Timelines of 23  Reactors Subject to Early Retirement in the United States

Figure 43 · Two-Thirds of Stored Water Exceed Contamination Limits for Discharge Multiple Times

Figure 44 · Exposure for TEPCO Employees and Contractors (FY 2011–2021)

Figure 45 · Overview of Completed Reactor Decommissioning Projects, 1954–2022

Figure 46 · Progress and Status of Reactor Decommissioning in selected countries

Figure 47 · Example of decay heat in reactors: Decay heat of the reactors in Fukushima in 2011

Figure 48 · Spent Fuel Pool Residual-Heat Removal System

Figure 49 · Decay Heat in Spent Low Enriched Uranium and MOX Fuels

Figure 50 · Global Investment Decisions in Renewables and Nuclear Power 2004–2021

Figure 51 · Regional Breakdown of Nuclear and Renewable Energy Investment Decisions 2012-2021

Figure 52 · The Declining Costs of Renewables vs. Traditional Power Sources

Figure 53 · Variation of Wind, Solar and Nuclear Capacity and Electricity Production in the World

Figure 54 · Net Added Electricity Generation by Power Source, 2011–2021

Figure 55 · Nuclear vs. Non-Hydro Renewable Electricity Production in the World

Figure 56 · Wind, Solar and Nuclear Installed Capacity and Electricity Production in the World

Figure 57 · Nuclear vs Non-Hydro Renewables in China, 2000–2021

Figure 58 · Wind, Solar and Nuclear Installed Capacity and Electricity Production in China, 2000–2021

Figure 59 · Electricity Generation in the EU27 by Fuel, 2012–2021

Figure 60 · Wind, Solar and Nuclear Capacity and Electricity Production in the EU27 (Developments)

Figure 61 · Wind, Solar and Nuclear Capacity and Electricity Production in the EU27 (Absolute Numbers)

Figure 62 · Wind, Solar and Nuclear Installed Capacity and Electricity Production in India

Figure 63 · Wind, Solar and Nuclear Installed Capacity and Electricity Production in the U.S

Figure 64 · Nuclear Reactors Startups and Closures in the EU27 1959–1 July 2022

Figure 65 · Nuclear Reactors and Net Operating Capacity in the EU27

Figure 66 · Construction Starts of Nuclear Reactors in the EU27

Figure 67 · Age Evolution of EU27 Reactor Fleet, 1959–2021

Figure 68 · Age Distribution of the EU27 Reactor Fleet

Figure 69 · Age Distribution of the Western European Reactor Fleet (incl. Switzerland and the U.K.)

Figure 70 · Age Distribution of the Swiss Nuclear Fleet

Figure 71 · Corrosion at Mochovce-3 Reactor Pressure Vessel Prior to Startup

Figure 72 · Age Distribution of the Russian Nuclear Fleet

Table of tables

Table 1 – WNISR Rationale for the Classification of 53 Reactors as Non-Operational as of end 2012

Table 2 – Nuclear Reactors “Under Construction” (as of 1 July 2022)

Table 3 – Duration from Construction Start to Grid Connection 2012–2021

Table 4 – Total Unavailability at French Nuclear Reactors 2019–2021 (in reactor-days)

Table 5 – Legal Closure Dates for German Nuclear Reactors 2011–2022

Table 6 – Official Reactor Closures Post-3/11 in Japan (as of 1  July  2022)

Table 7 – 2021 Electricity Mix in South Korea

Table 8 – Projections of 2030 Electricity Mix in South Korea according to Different Plans

Table 9   – Status of U.K. EDF AGR Nuclear Reactor Fleet (as of 1  July  2022)

Table 10 - Overview of Reactor Decommissioning Worldwide (as of July 2022)

Table 11 – Status of Canadian Nuclear Fleet - PLEX and Expected Closures

Table 12 – Belgian Nuclear Fleet (as of 1 July 2022)

Table 13 – Status of Nuclear Power in the World (as of 1 July 2022)

Table 14 – Nuclear Reactors in the World “Under Construction” (as of 1  July  2022)

Foreword

by Aviel Verbruggen1

When you read these words, you have found the way to the world’s unique source of knowledge about the nuclear industry. The independent ‘coordinating lead authors’,2 Mycle  Schneider and Antony  Froggatt, compose the WNISR annually since 2007. Their rigorous, perseverant work has grown the scope and impact. The yearly editions provide the essential statistical series for a reliable assessment of the industry’s status, complemented with chapters exploring topical issues.

Consistent and transparent data series, updated until mid-2022, gives us a comprehensive and longitudinal perspective of the global industry. As usual, the text is illustrated with tables and figures, making the contents more accessible in shorter time, with reading even more pleasant. After the status of the global industry, we as readers are spoiled with a richness of information about the status of the nuclear industry in various nations and from various angles. The ten focus countries got a specific analysis in relation to the specific issues affecting their nuclear businesses. For example, for France, a specific section on “Nuclear Unavailability” provides all information you would like to assess the gravity of this problem. In addition to the ten focus countries, WNISR2022 holds a 75  pages Annex  1 with an Overview by Region and by Country. None escape from the scrutiny of the WNISR team. Further, the topical chapters cover, on the one hand, two thorny issues (Fukushima Status, and Decommissioning Status), on the other hand, two anticipatory issues (Potential Newcomer Countries, and Small Modular Reactors). The sobering approach of the issues by the WNISR team is enormously welcome in a world overridden by flawed and deceiving news.

In 2022, for the first time, there is a chapter on “Nuclear Power and War”, prompted by the war in Ukraine. First, the authors painstakingly discuss higher loss-of-coolant risks in nuclear reactors and in spent fuel ponds. Invading and defending combatants likely increase the probability of such loss and hinder fast and full emergency interventions. Second, the situation in Ukraine is documented by a selection of official statements by the International Atomic Energy Agency (IAEA) and the State Nuclear Regulatory Inspectorate of Ukraine, chronologically over the period 24 February–13 September 2022. Timely, yet frightening, information. The authors refrain from any comments on these statements, acknowledging that either source is not unbiased, and that truly independent sources of information on the situation at the Ukrainian nuclear facilities simply do not exist.

Valuable academic research depends on accurate data, unbiased information, and on the independent disposition of the researcher. For issues of global importance, such as climate change and related energy use, the worldwide involvement of scientists enhances diversity and quality of the research and its products. Free access to data and documents is vital for the participation of scientists who do not enjoy wealthy college privileges. In my energy research, I use BP Statistical Reviews, IRENA reports, and WNISRs, for data and information about respectively fossil fuels, renewable energy sources and technologies, and nuclear affairs. The three are open access. BP is a superrich oil major. IRENA is financed by national governments. WNISR thrives by the seemingly inexhaustible energy of the coordinating lead authors, boosted by contributions from several independent scientists and a few sponsors.

The WNISR is in good hands, guaranteeing ever improving reports. However, the longevity of the nuclear industry, and certainly of its legacy, encourages the consideration of a more robust WNISR financing and/or a stable institutional framework.

One of the observed flaws in the international regulation of the nuclear sector, is the double mission of the IAEA: on the one hand, reduce the proliferation of nuclear weaponry, and on the other hand, promote the proliferation of nuclear power generation. Once, a nation acquires the knowledge and technologies of nuclear power, it is capable of building atomic bombs. I support the recommendation that the governments of the world categorically dissolve the IAEA’s double role and limit IAEA tasks to control and enforcement of the Non-Proliferation Treaty, and to care for the nuclear legacy. A multiple win: finally, the IAEA would fully focus on minimizing proliferation; the high spending on propaganda for nuclear power would be reduced; and the Intergovernmental Panel on Climate Change (IPCC)3 Working Group  3 (WG3) “nuclear-gate” would be closed.

The IPCC assessment reports4 encompass three volumes, realized by three WGs. WG1 is phenomenal in assessing all available climate science. WG2 is less comprehensive because climate change impacts it assesses are many, diverse, and not fully inventoried. WG3 covers mitigation options, and it is problematic because of the influence of neoclassical economics, neoliberal viewpoints, incumbent interests. A salient case is how WG3 assesses the literature on nuclear power. The nuclear sections5 are skipping most of the peer-reviewed literature on nuclear performance, on its degree of sustainability, its compatibility with renewable power from sun and wind. The sections depend on nuclear sector non-peer reviewed literature of the IAEA, the Nuclear Energy Agency (NEA), and similar.

The lopsided treatment of such an important subject means a grave infliction on the “Principles Governing IPCC Work, Section 4.3.3”, requesting full assessment of the available literature, and “clearly identify disparate views for which there is significant scientific or technical support, together with the relevant arguments”. A balanced assessment of the literature on nuclear power would be a formidable challenge for IAEA’s nuclear advocacy. It would help to dissolve the juxtaposition “renewables, nuclear, carbon capture and storage” as mitigation options.6 This deceiving triptych mantra retards the transformation of the global energy systems to 100% renewable energy supplies, the substrate for a genuine common future as spelled out in the Brundtland report (1987).

WNISRs are vital reality checks of the nuclear industry’s performance. Every yearly report is a barrier against utopian fantasies and wishful thinking, a tool to connect with reality. We count on the perseverance of the WNISR coordinating lead authors, contributing authors, and the entire team.

Executive Summary and Conclusions

As much of 2021 has been dominated by the ongoing COVID-19 pandemic, the end of the year saw the beginning of a global energy crisis with unprecedented price levels for natural gas and electricity that will likely impact the well-being of many and the economic systems for years to come. The war in Ukraine dramatically exacerbated the energy crisis and will profoundly alter international geopolitics for the long term. For the first time in history, operating commercial nuclear facilities were directly attacked and then occupied by hostile forces during a full-scale war.

As with earlier reports, The World Nuclear Industry Status Report 2022 (WNISR2022) provides a comprehensive overview of nuclear power plant data, including information on age, operation, production, and construction of reactors. But due to the unprecedented situation in Ukraine, WNISR2022 includes a dedicated chapter that assesses the specific challenges and risks of Nuclear Power and War.

WNISR2022 analyses the status of newbuild programs in some of the 33 nuclear countries (as of mid-2022) as well as in potential newcomer countries. WNISR2022 includes sections on ten Focus Countries representing 30  percent of the nuclear countries, two thirds of the global reactor fleet, and four of the world’s five largest nuclear power producers.

The Decommissioning Status Report provides an overview of the current state of nuclear reactors 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. Finally, Annex  1 presents overviews of nuclear power programs in the countries not covered in the Focus Countries sections.

Production and Role of Nuclear Power

Prior to the entry into force of the Treaty on the Non-Proliferation of Nuclear Weapons (NPT) in 1970, 14 countries were operating nuclear power reactors. By 1985, 16 additional countries had reactors on the grid. Over the 30-year period 1991–2020 (none in 2021), only five countries started up their first power reactors—China (1991), Romania (1996), Iran (2011), United Arab Emirates, and Belarus (both 2020); in 2021, no newcomer country started any reactor. Three countries abandoned their nuclear power programs, Italy (1987), Kazakhstan (1998), and Lithuania (2009).

Reactor Operation and Capacity. As of 1  July  2022, a total of 411 reactors—excluding Long-Term Outages (LTOs)—were operating in 33  countries, four units less than WNISR2021, seven less than in 1989, and 27  below the 2002-peak of 438. The nominal net nuclear electricity generating capacity declined in 2021 over the previous year by 0.4  GW.7 As of mid-2022, operating capacity reached the same level as in mid-2021 at 369  GW, representing a peak just above the 2006-end-of-year record of 367  GW. (This might change at the end of the year.)

IAEA versus WNISR Assessment. International Atomic Energy Agency (IAEA) statistics show a historic peak in officially operating reactors, both in terms of number (449) and capacity (396.5  gigawatt), in 2018. As of December 2021, the IAEA included 33  units in Japan in its total of 437  reactors “in operation” in the world while 23 of these reactors have not produced electricity since 2010–2013 (of which, three since 2007). Again, as of December 2021, WNISR classified 29  units are as LTO, of which 23 in Japan, three in India, two in Canada, and one in South  Korea. These 29 reactors are still in LTO status as of mid-2022, and amount to three more than classified in that category in WNISR2021.

Nuclear Electricity Production. In 2021, the world nuclear fleet generated 2,653  net terawatt-hours (TWh or billion kilowatt-hours) of electricity. Nuclear production increased by 3.9  percent in 2021 but remained just below the 2019 level.

China produced more nuclear electricity than France for the second year in a row and remains in second place—behind the United States—for the top nuclear power generators. Outside of China, nuclear production increased 2.8  percent to a level similar to 2017.

Share in Electricity/Energy Mix. Nuclear energy’s share of global commercial gross electricity generation in 2021 dropped to 9.8  percent—the first time below 10  percent and the lowest value in four decades—and over 40 percent below the peak of 17.5  percent in 1996, as globally electricity generation continues to rise.

Reactor Startups and Closures8

Startups. Six units were connected to the grid in 2021, of which three were in China, and one each in India, Pakistan (built by China), and the UAE. Five new units became operational in the first half of 2022, including two in China, one each in Finland, Pakistan (built by China), and South Korea.

Closures.9 Eight reactors were closed in 2021, including three in Germany and one each in Pakistan, Russia, Taiwan, U.K., and U.S. Two additional closures in the U.K. were announced during the year but they had not generated any power since 2018 (thus WNISR retroactively considers them closed since 2018).

Over the two decades 2002–2021, there were 98 startups and 105  closures. Of these, 50  startups were in China which did not close any reactors. As a result, outside China, there has been a drastic net decline by 57  units over the same period; net capacity declined by over 25  GW.

Construction Data10

As of 1  July 2022, 53 reactors (53.3  GW) were considered as under construction, the same number the WNISR reported a year ago, but 16 fewer than in 2013 (five of those units have subsequently been abandoned).

Four in five reactors are built in Asia or Eastern Europe. 15  countries are building nuclear plants, two less (Finland and Pakistan) than in WNISR2021. Only four countries—China, India, Russia, and South Korea—have construction ongoing at more than one site. Since mid-2021, construction started on seven reactors worldwide, including six in China and one in India  (Kudankulam-6).

Building vs. Vendor Countries

• As of mid-2022, with 21 units or 40  percent, China has by far the most reactors under construction. However, China is currently not building anywhere outside the country.
• Russia is largely dominating the international market as a technology supplier with 20  units under construction in the world as of mid-2022 of which only three are being built domestically. The remaining 17  units are being constructed in seven countries, including four each in China and India, and three in Turkey.11 It is uncertain at this point to what extent these projects will be impacted by the sanctions imposed on Russia and other consequential geopolitical developments following the invasion of Ukraine.
• Besides Russia’s Rosatom, there are only French and South Korean companies acting as leading contractors building nuclear power plants abroad.

Construction Times

• For the 53  reactors being built, it is an average of 6.8  years has passed since construction started, slightly lower than the mid-2021 average of seven  years.
• All reactors under construction in at least 10 of the 15  countries have experienced mostly year-long delays.
• At least half (26) of all projects are delayed. Of these, at least 14 have reported increased delays and two have reported new delays over the past year.
• WNISR2020 noted a total of  19  reactors scheduled for startup in 2021, and at the beginning of 2021, 16 were still planned to be connected to the grid but only six of these made it, while the other 10 were delayed at least into 2022.
• Construction starts of two projects date back 37  years, Mochovce-3 and -4 in Slovakia, and their grid connection has been further delayed. Bushehr-2 in Iran originally started construction in 1976, over 45  years ago, and resumed construction in 2019 with grid connection currently scheduled for 2024.
• Six additional reactors have been listed as “under construction” for a decade or more: the Prototype Fast Breeder Reactor  (PFBR), Kakrapar-4 and Rajasthan-7 &  -8 in India, Shimane-3 in Japan, and Flamanville-3  (FL3) in France. The French and Indian projects have been further delayed this year, and the Japanese reactor does not even have a provisional startup date.

Construction Starts

• Construction started on 10 reactors in 2021, including six in China. The other four are implemented by Rosatom in India (2), in Turkey, and domestically. Two of the construction starts in China were also by Russia. In other words, of the global total of ten, six reactors were designed by Russian builders and four by the Chinese industry.
• Construction of three reactors started in the first half of 2022, all of them in China, two of which are of Russian design.
• Chinese and Russian government-owned or -controlled companies launched all of the 18  reactor constructions in the world over the 30-month period from the beginning of 2020 to mid-2022.

Operating Age

• The average age (from grid connection) of operating nuclear power plants has been increasing since 1984 and stands at 31  years as of mid-2022.
• A total of 270  reactors, two-thirds of the world’s operating fleet, have operated for 31  or more years, including 105—more than one in five—for at least 41  years.
• If all currently licensed lifetime extensions and license renewals are maintained, all construction sites completed, and all other units operated for a 40-year lifetime (unless a firm earlier or later closure date has been announced), in the decade to 2030, the net balance of operating reactors would turn negative as soon as 2024, and an additional 110  new reactors (83.5  GW)—one unit or 0.7  GW per month—would have to start up or restart to replace closures. This would mean the need to double the annual building rate of the past decade from six to twelve over the period to 2030.

Focus Countries

The following ten countries covered in depth in this report represent 30  percent of the nuclear countries, which operate two thirds of the global reactor fleet. Some key developments in 2021 and the first half of 2022:

China. Nuclear power generation increased by 11  percent and provided a stable 5  percent of total electricity generation. Meanwhile, wind energy output grew by 40  percent and solar by 25  percent. China failed its 2020-target for operating nuclear capacity and will miss its 2025-target of 70  GW by at least 9  GW.

Finland. The country’s fifth reactor, the first European Pressurized Water Reactor (EPR) on the continent, under construction since 2005, finally started up in March 2022, 13  years later than scheduled. However, commissioning of the reactor has been hampered by a series of “unexpected” events. The Russian-designed Hanhikivi follow-up project was cancelled following the invasion of Ukraine.

France. Nuclear generation was up 7.5  percent following a 12-percent fall in 2020. In December 2021, stress corrosion cracking was first identified in safety injection systems of the largest and most recent reactors. Later the default was detected on other units.12 The problem adds to extended outages due to ageing issues, backfitting, decennial inspections, and upgrading requested by the safety authorities. The subsequent decline in electricity generation is expected to lead in 2022 to an annual level last seen in 1990. The government has announced the renationalization of operator EDF, which faces potential bankruptcy.

Germany. Nuclear generation increased by 7.4  percent after a 14-percent drop in 2020. According to the legally binding phaseout schedule, three reactors were closed at the end of 2021, and the three remaining are scheduled to close by the end of 2022. Accordingly, the nuclear share declined to 5.6  percent in the first half of 2022. Triggered by the unfolding energy crisis, an unexpected controversy is underway about the potential stretching of the operation or a lifetime extension of the remaining three units. The government has proposed to put two of them into reserve status until the end of winter in mid-April  2023.

India. Nuclear generation has been slightly declining since 2019 and represented 3.2  percent of total electricity production. Eight reactors are listed as under construction, including four of Russian design. Meanwhile, both wind and solar continued growth and contributed more than 150  percent of nuclear power generation each.

Japan. One reactor was restarted from LTO since WNISR2021 (none was slated for closure). Nuclear generation increased by 42.2  percent but to provide 7.2  percent of the country’s electricity. However, as of July 2022, only seven of ten licensed units generated power. In an unprecedented ruling, a Hokkaido District Court prohibited the restart of the only three reactors on the island due to concerns about spent fuel storage safety and protection levels against tsunamis.

South Korea. Nuclear generation slightly declined and provided 27.5  percent of electricity. The new administration clearly aims to shift nuclear policy away from a long-term phaseout (then rather a program limitation) and contemplates a stronger role for nuclear power further lowering the part of renewables. The country already has the lowest share of renewables in the power mix of any OECD member state.

Taiwan. Nuclear generation dropped by 11.6  percent following the closure of one reactor in mid-2021. The country follows a nuclear phaseout plan that will see the remaining three reactors closed by 2025. An attempt by the opposition and the nuclear lobby to overturn the phaseout policy by referendum and reactivate the construction of two reactors at Lungmen failed in December  2021. Renewables only contributed 4.2  percent of electricity, and, so far, only solar photovoltaics are developing rapidly with 1.9  GW in capacity added over the year.

United Kingdom. The nuclear program is declining faster than anticipated. Since June  2021, two reactors were closed, and the decision was taken to close two additional units that had not generated any power since 2018. Nuclear power contributed 14.8  percent to national power production, down from 26.9  percent in 1997. Renewables have seen a rise in two decades from 2.5  percent in 2001 to 39.6  percent in 2021, while coal declined in just the past decade from 39.2  percent to 2.6  percent. The construction project at Hinkley Point C continued to experience cost overruns and delays.

United States. Nuclear output peaked in 2019 and has dropped by a cumulated 3.9  percent by 2021; its share of commercial electricity generation declined to 18.9  percent, its lowest level since it peaked in 1995. The U.S. nuclear fleet is still the largest with 92  units and one of the oldest in the world with a mean age of 41.6  years. Cost estimates for the only two reactors under construction at the Vogtle site now exceed US$30  billion. Substantial new subsidy programs for uneconomic operating reactors and for new projects have been enacted on federal and state levels. Three major corruption and fraud investigations involving both new reactors and nuclear subsidies continued and involve politicians, utility-, and industry-executives.

Fukushima Status Report

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

Overview of Onsite and Offsite Challenges

Onsite Challenges

Spent Fuel Removal from the pool of Unit  3 was completed in February 2021. Preparatory work has only started on Units  1 and  2, with removal planned to begin in FY  2024 at the earliest.

Core Cooling. Water levels dropped in all three reactor pressure vessels after a 7.4  magnitude earthquake on 16  March  2022. Water injection rates have been increased again as a result.

Fuel Debris Removal, last planned to start with Unit  2 by 2021, had been delayed by “about one year due to the spread of COVID-19” and was delayed again following transmission loss of the camera mounted on a remotely operated vehicle. There is no new timeline for debris removal.

Contaminated Water Management. As water injection continues to cool the fuel debris, highly contaminated water runs out of the cracked containments into the basements where it mixes with water that has penetrated the basements from an underground river. Various measures have reduced the influx of water from up to 500  m3/day to about 130  m3/day. An equivalent amount of water is partially decontaminated and stored in 1,000-m3 tanks. Thus, a new tank is still needed almost every week.

About 1.3  million  m3 of treated water are stored in 1,020 tanks. As of 28  July  2022, capacity saturation had reached 96  percent, so the existing tanks would be full by summer or fall of 2023.

The safety authority agreed to operator TEPCO’s plan to release the contaminated water into the ocean. Close to three quarters of the water would have to be treated again, then the water would be diluted by a factor of 100 (or more) before being released via a one-kilometer-long sub-seabed tunnel. The operation would take at least three decades. The plan remains widely contested, including overseas.

Offsite Challenges

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

Evacuees. As of March 2022, about 32,400 residents of Fukushima Prefecture were still living as evacuees; the number decreased from a peak of close to 165,000 in May  2012. In June  2022, for the first time, the evacuation order was lifted for a district designated as “difficult-to-return” zone (an area with high levels of radiation). But only eight people from four households expressed an interest in returning to the district. For the first time, the evacuation order was also lifted for part of Okuma city that hosts the Fukushima plant. Only 3.6  percent of the residents returned. Rates of return have been much higher, 62–85  percent, in cases where evacuation orders have been lifted for entire municipal territories.

Food Contamination. According to official statistics, a total of 41,361 samples were analyzed in FY2021, of which 157  samples (30 more than a year earlier and 0.4  percent of total) exceeded the legal limits. As of February  2022, 14 countries—down from a peak of 54  countries—still had import restrictions for Japanese food items in place. In June 2022, the U.K. lifted its import restrictions.

Decontamination and Contaminated Soil Management. The contaminated soil in the temporary storage area in Fukushima Prefecture is currently being transferred to intermediate storage facilities in eight areas. As of the end of August  2022, a total of about 13.3  million  m3 of contaminated soil had been transferred to such interim storage facilities. The government is legally responsible for the final disposal of the contaminated soil.

Health Issues and Legal Cases. In a first-of-a-kind procedure, in January 2022, a group of six men and women, diagnosed with thyroid cancer as children, filed a class action suit against TEPCO, seeking US$5.4  million in compensation. In March  2022, Japan’s Supreme Court ordered TEPCO to pay compensation to 3,700  people impacted by the disaster but ruled out government responsibility for the catastrophe in a separate June-2022 judgement. In July  2022, the Tokyo District Court ordered four former executives of TEPCO to pay 13 trillion  yen (US$٩5  billion) in damages to the company. The case was brought by TEPCO shareholders, and the ruling was the first time a court has found former executives responsible for the nuclear accidents.

Decommissioning Status Report

As more and more nuclear facilities either reach the end of their pre-determined operational lifetime, or close due to deteriorating economic conditions, their decommissioning is becoming a key challenge (note that the status of radioactive waste management is not part of this analysis).

• The number of closed power reactors exceeded 200 at the end of 2021, reaching 204 units with 97.4  GW of capacity as of mid-2022, eight more than one year earlier. 182 units are awaiting or are in various stages of decommissioning, five more than one year earlier.
• Only 22  units or 11  percent have been fully decommissioned, two more than a year earlier: 17 in the U.S., four in Germany13, and one in Japan. Of these, only 10 or 5  percent of all closed reactors have been returned to greenfield sites for unrestricted use.
• The average duration of the decommissioning process is about 21  years, with a large range of 6–45  years (both extremes for reactors with very low power ratings of respectively 22  MW and 63 MW).
• Only three countries amongst the 23 with closed nuclear power reactors have completed the technical decommissioning process of at least one reactor: the United States (17  units), Germany  (4), and Japan  (1).
• The analysis of 11 major nuclear countries hosting 85  percent of all closed reactors shows that progress in decommissioning remains slow: of 146  units in various stages of advancement, 66 are in the “warm-up stage”, 24 are in the “hot-zone stage”, 11 are in the “ease-off stage”, while 45 are in “long-term enclosure”.
• None of the early nuclear states—U.K., France, Russia, and Canada—has fully decommissioned a single reactor yet.

Potential Newcomer Countries

Two potential newcomer countries had nuclear reactors under construction as of mid-2022: Bangladesh and Turkey. [Egypt started construction shortly after]. All of these projects are implemented by the Russian nuclear industry. The impact of sanctions and potential other geopolitical developments on the future of these projects is uncertain.

Other countries like Nigeria, Poland, or Saudi Arabia have more or less advanced plans, but so far neither selected a design nor assured a financing package. Several countries, including Indonesia, Jordan, Kazakhstan, Thailand, Uzbekistan, and Vietnam have suspended or cancelled earlier plans. Some key developments:

Bangladesh. Two reactors of Russian design have been under construction since 2017–2018. Both units are scheduled to start up in 2023. There is widespread concern in the country about the safety and security of the plant.

Egypt. On 20  July  2022, despite the war in Ukraine, construction of the first, Russian designed, nuclear power plant was launched at the El-Dabaa site.

Nigeria. The country signed nuclear cooperation agreements with several countries and considers the option of developing up to 4  GW of nuclear capacity. Plans are vague and no design or provider has been chosen and no investment decision has been taken.

Poland. The country abandoned two reactors under construction following the Chernobyl accident in 1986. There have been repeated attempts to revive the program ever since. In December  2021, the site of Choczewo in Pomerania was chosen for a first plant. However, no design and no supplier have been selected, and no financing package has been assured.

Saudi Arabia. In 2013, a plan for the deployment of 18  GW of nuclear power was announced, with the first reactor to start operating in 2022. It did not happen. In May  2022, the government finally invited bids from China, France, Russia, and South  Korea for the construction of two 1400  MW reactors.

Turkey. The Akkuyu site was selected in 1976 and several attempts to implement the project had failed until a 2010 agreement with Russia to build four reactors that were all to be in operation by 2019. After repeated delays, construction of these four units started between 2018 and 2022. Construction on Unit  4 started in July  2022, in the middle of the war in Ukraine. Turkish authorities hope to connect Unit  1 to the grid in 2023, to coincide with the 100th anniversary of the foundation of the Republic of Turkey.

Small Modular Reactors (SMRs)

Following assessments of the development status and prospects of Small Modular Reactors (SMRs) in earlier WNISR editions, this year’s update does not reveal any major advances but still increasing media attention and some additional public funding commitments. The country-by-country status:

Argentina. The CAREM-25 project has been under construction since 2014. Following numerous delays, the latest estimated date for startup is 2027. The lower end of cost estimates per installed kilowatt correspond to roughly twice the cost estimates for the most expensive Generation-III reactors.

Canada. There is continuous strong federal and provincial government support for the promotion of SMRs. While several grants to the value of tens of millions of dollars have been awarded to different design developers, the amounts remain small when compared to what would be required to advance one of these designs to the point of being licensed for construction. No design has yet been transmitted to the safety authority for review, leave alone for certification.

China. Construction on two high-temperature reactor modules started in 2012. The first module was connected to the grid for a few days in December 2021, almost five years behind schedule. Reportedly, neither unit has generated power since. The reasons are unknown. Construction started on a second design, the ACP100 or Linglong One, in July 2021, six years later than planned. It is scheduled to be completed by early 2026.

France. In February 2022, President Macron announced a €500 million contribution (US$559 million) until 2030 to the financing of the development of the Nuward SMR design. However, EDF made it clear that the project is not high amongst its priorities.

India. An Advanced Heavy Water Reactor (AHWR) design has been under development since the 1990s, but its construction has been continuously delayed. Earlier in 2022, the government announced that a “Pre-Licensing Design Safety appraisal of the reactor has been completed”.

Russia. Russia operates two SMRs on a barge called the Akademik Lomonosov. Both reactors were connected to the grid in December 2019, nine years later than planned. Since then, their performance has been mediocre. A second SMR project, a lead-cooled fast reactor design, was launched in June 2021.

South Korea. The System-Integrated Modular Advanced Reactor  (SMART) has been under development since 1997. In 2012, the design received approval by the safety authority, but there have been no orders. Reportedly, several other designs are in very early stages of development.

United Kingdom. Since 2014, Rolls Royce has been developing the “UK  SMR”, a 470  MW reactor (exceeding the size-limit of 300  MW for the usual SMR definition). In November  2021, Rolls Royce announced it had received US$281  million in government funding and US$261  million from private sources (including company funding), far short of its earlier calls for US$2.8  billion in support. In March 2022, the regulator accepted the design for a Generic Design Assessment  (GDA).

United States. The Department of Energy (DOE) has already spent more than US$1.2  billion on SMRs and has announced further awards over the next decade that could amount to an additional US$5.5  billion. However, there is still not a single reactor under construction. Only one design, NuScale, has received a 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 unsolved. In October  2021, eight municipalities withdrew from the only investment project in Utah, leaving the 6-module 462  MW project with subscriptions amounting to just 101  MW. Cost estimates (including financing) have ballooned to US$5.3  billion.

Nuclear Power and War

Russia’s invasion of Ukraine has led to several unprecedented events including the operation of commercial nuclear power plants during a full-scale war, shelling of commercial reactor sites, the occupation by enemy forces of nuclear facilities, and the operation of reactors under physical threat. No nuclear power plant in the world has been designed to operate under those conditions.

Vulnerabilities of Reactors and Spent Fuel Pools

• A nuclear power plant depends on continuously functioning cooling systems to evacuate decay heat from reactor cores and spent fuel pools, even when the reactor is shut down.
• Immediately after shutdown, a reactor core still generates about 7  percent of the nominal thermal power. Decay heat decreases with time, first rapidly, then slowly. After one day residual heat is at about 0.5  percent (considerable 15  MWth in the case of a 1,000  MWe reactor) and still half of that after ten days.
• After the service life, the spent fuel is unloaded from the reactor core and placed in a pool filled with water. The residual heat must be permanently evacuated from the pool in order to prevent the fuel from overheating.
• Failure to evacuate residual decay heat will lead to core meltdown or spent fuel fire with potentially large releases of radioactivity.
• Effective cooling chains—usually three cooling circuits linked together via heat exchangers and a final heat sink like a river, a lake, or the ocean—must be available at all times to evacuate residual heat from the reactor core and from the spent fuel pool.

  Nuclear Power Plants and Spent Fuel Storage in War

Power Supply in War Times

• Some countries heavily rely on nuclear power. In 2021, eight countries generated over one third of their electricity from nuclear plants (Ukraine 55  percent). The higher the nuclear share, the more difficult to shut down all reactors as a precautionary measure in case of war.
• The attacker might want to disrupt the power supply of the attacked country in the short term but might also wish to maintain power supply in the longer term in case the objective is the occupation of attacked territories. In any case, nuclear power plants are strategic sites.

Nuclear Power Plants and Nuclear Weapons

• Nuclear explosive devices can contain plutonium and/or highly enriched uranium as fissile material.
• Highly enriched uranium (HEU) is not used in common commercial nuclear power reactors (although some research reactors, naval applications, and fast reactors run on HEU).
• Every nuclear power plant generates weapons usable plutonium in its fuel during normal operation. The extraction of plutonium from highly radioactive irradiated fuel requires remote-handling equipment (a large hot cell or a reprocessing plant).
• An attacker can either suspect or insinuate that the designated enemy has used or is planning to use its power reactors to produce plutonium for a weapons program.

Fear of an Accident as Political Pressure Tool

• Nuclear power plants can release large quantities of radioactive substances in case of accident. Wartime destruction would lead to similar consequences.
• The attacker can use the threat of destruction as blackmail as the country hosting the nuclear facilities has an obvious interest in preserving public health and the environment.

  Multiple Indirect Threats to Nuclear Safety in Wartime Situations

Regardless of whether there is a military rationale to occupy, recapture, or destroy in a scorched-earth mode a nuclear power plant site, there can be multiple unintended causes of impact on nuclear safety.

• Accidental hits due to limited accuracy of weapon systems.
• Collateral damage in the course of a military campaign.
• Limited knowledge of combatants of safety relevance of parts of a nuclear plant.
• In a life-or-death combat situation, nuclear safety will likely not be a priority.
• The power plant site can be used as a shield, thus becoming an impregnable fortress.

  Specific Vulnerabilities of Nuclear Power Plants

Nuclear power plants are complex industrial facilities. Their safe operation depends on a stable technical, human, regulatory, political, and economic environment. Previous research on nuclear safety have taken these stable conditions for granted.

The consequences of system failures are nevertheless the same, whether they are triggered by accident or by the effects of war.

• Direct destruction of safety-relevant parts can be caused by military munitions on purpose or by mistake.
• Some important safety systems are located in the reactor buildings that vary greatly in design. While many are robust buildings, only few are truly bunkered.
• Many important safety systems are located in other traditional industrial buildings including parts of the cooling chains, large parts of the power supply, transformers, diesel generators for emergency power, generator fuel, switchgear, and the control room.

Power Supply

• A stable connection to the power grid is the most important requirement for electricity supply.
• Electricity is required at all times to operate large pumps in the various cooling chains.
• In the case of grid loss, emergency generators can supply the minimum required to maintain the cooling systems operational for a short time, but they are not designed for continuous long-term operation.
• A shutdown nuclear power reactor cannot be restarted from diesel generators and needs the grid connection to operate again.
• In case of multi-unit sites, one operating reactor can also supply its own and the other units’ basic needs for electricity (island mode). Switch to island mode frequently fails and is highly unstable.

Cooling Water Supply and Other Important Infrastructure

• An operational cooling capacity is as vital for nuclear safety as a reliable power supply.
• Interruption of pipelines, destruction of the links to the final heat sink, or pump inlets blocked by debris would jeopardize the cooling capacity.
• Free road access is essential for rotating shifts, delivery of spare parts, outside personnel, and emergency services like fire departments.

Skilled Operating Staff

• Reactor operators are trained for a specific individual plant. They cannot be simply replaced by operators from other plants, including those from an attacker country.
• Under war conditions, staff are unsure whether they can leave the plant at the end of their shift, uncertainties that heighten their stress level.
• Operating a nuclear facility at gun point could easily lead to considering even standard safety procedures as secondary.
• Staff will likely be deprived of their usual communication tools like their cell phones, restricting their ability to exchange with colleagues, supervisors, and regulators. Uncertainty about the well-being of family and friends in the middle of an active war zone further increases the stress level.

Maintenance

• Regular maintenance is indispensable, including the delivery and installation of replacement parts, some of which might have to be ordered from foreign suppliers.
• Annual outages usually involve a large number of subcontractors. These companies might not want or be able to send their employees into a war zone or into an occupied nuclear power plant.

Inspection

• Inspections by the state regulator or other third parties are an integral part of the safety approach. They will likely not be carried out under warlike conditions.
• International organizations like the IAEA have certain inspection rights under international law. These will likely not be implemented, at least not under usual conditions.

  Specific Vulnerabilities of Spent Fuel Storage Facilities

• All nuclear power plants have spent fuel storage pools, some are in the reactor buildings, some are in separate, considerably less robust buildings.
• While spent fuel pools are better protected inside the containment, there is a possibility that in case of a severe accident on the reactor, the pool will be impacted as well.
• Spent fuel pools, especially centralized pools that serve several reactors, contain the equivalent of several, up to several dozen reactor cores and thus cumulate very large radioactivity inventories.
• After several years of cooling, spent fuel can be moved to dry storage casks. The residual heat is removed by the air flow and no active cooling system is needed.
• Pool destruction or disruption of power and cooling water supply:
  • The cooling chain of the pool could be interrupted, which would lead to the progressive evaporation of the cooling water and uncover the fuel within days or weeks.
  • If the pool itself is damaged or destroyed the water would be lost. The fuel would likely self-ignite and release a large share of its radioactive inventory.
  • In case of a power cut, the cooling chain would become dysfunctional. The grace time would be significantly longer compared to the reactor core cooling but could eventually lead to fuel destruction.

Possible Release Mechanisms and Scenarios

Nuclear Power Plant

• The interruption of core cooling at an operating nuclear reactor would lead to a core-melt accident within less than one hour to several hours. A meltdown would also occur at a shutdown reactor with a delay depending on various parameters, especially the time elapsed since shutdown.
• During a core meltdown, free hydrogen is formed that can explode (see Fukushima events).
• If the containment is breached, e.g. by a military strike in a wartime situation, a meltdown would release a significant fraction of the radioactive inventory into the environment.

Spent Fuel Storage

• The interruption of cooling spent fuel in a pool leads to progressive evaporation until the fuel elements are partly or wholly uncovered. They then heat up until the cladding is destroyed and release radioactivity into the environment. At higher temperatures, explosive hydrogen can also be formed. When strongly heated cladding material is exposed to air, it can also catch fire. Under this scenario a very large fraction of the radioactive inventory would be released to the environment and lead to widespread contamination.
• In the case of a dry storage facility, only the destruction of the container integrity would lead to war-induced radioactivity releases. Most cask-destruction scenarios would lead to geographically limited radiation effects, except for a munition-triggered spent fuel fire.

Timeline: War in Ukraine

• It should be noted that the Nuclear Power and War chapter has been drafted in May  2022. It is striking to what extent, many of the theoretical assumptions have—reportedly—turned into reality in the following months of the war in Ukraine.
• In a war situation, it is particularly difficult to verify whether certain reports cover indisputable facts, are exaggerated, or false. We have therefore refrained from attempting an objective account of what is happening in Ukraine with and at nuclear facilities.
• Nevertheless, some insight into the developments should be provided. Therefore, we have compiled a timeline from 24  February to 13  September  2022 based exclusively on two sources: the State Nuclear Regulatory Inspectorate of Ukraine  (SNRIU) and the International Atomic Energy Agency  (IAEA). Neither are neutral in this conflict, a situation requiring appropriate caution.

Nuclear Power vs. Renewable Energy Deployment

The year since the publication of WNISR2021 has been seminal for climate change and energy security, nuclear power, and renewable energy, with climate change high on the political agenda and an energy crisis in the making in the second half of 2021. Obviously, 2022 has been dominated by the events in Ukraine which had significant effects on energy-policy decisions for the short and medium term.

Investment. In 2021, total investment in non-hydro renewable electricity capacity reached a record US$366  billion, 15 times the reported global investment decisions for the construction of nuclear power plants that have nevertheless increased over the previous year by about one third to US$24  billion for 8.8  GW. Investment in solar surged by 37  percent to reach US$204  billion and investments in wind power plants increased by 2.8  percent to US$146  billion. Individually, solar investments total 8.5  times and wind six times nuclear power investment decisions.

Costs. Levelized Cost of Energy (LCOE) analysis by U.S. bank Lazard shows that between 2009 and 2021, utility-scale solar costs came down 90 percent and wind 72 percent, while new nuclear costs increased by 36  percent. The gap continues to widen. Estimates by the International Renewable Energy Agency  (IRENA) has seen the LCOE for wind drop by 15  percent and solar by 13  percent between 2020 and 2021 alone. IRENA also calculated that 800  GW of existing coal-fired capacity in the world have higher operating costs than new utility-scale solar photovoltaics  (PV) and new onshore wind.

Installed Capacity. In 2021, wind added 92  GW of new capacity and solar PV capacity grew by 138  GW, largely contributing to the new global record of 257  GW of non-hydro renewables added to the world’s power grids. These numbers compare with a net decrease of 0.4  GW in operating nuclear power capacity.

Electricity Generation. In 2021, the annual global growth rates for the generation from wind power were 17.0  percent (11.9  percent in 2020), 22.3  percent (20.9  percent in 2020) for solar  PV, and 3.9  percent (-4  percent in 2020) for nuclear power.

Share in Power Mix. In 2021, wind and solar alone reached a 10.2  percent share of power generation, the first time, they provided more than 10  percent of global power and surpassed the contribution of nuclear energy that fell to 9.8 percent. The nuclear share is below 10 percent for the first time in four decades. Non-hydro electricity generation outperformed nuclear power production by 30.6  percent. The gap widens.

China. In 2021, renewable-energy-based gross power generation grew faster than any other energy sources, with wind producing 656  TWh, solar, 327  TWh, compared to 407.5  TWh (383  TWh net) for nuclear and 1,300  TWh for hydro. Thus, wind turbines generated 71  percent more power than nuclear reactors and solar remained just 15  percent short of the nuclear output.

European Union. In 2021, renewable electricity generation in the E.U. reached a new record of 1,068  TWh—a 9  percent (+88  TWh) jump compared to 2019—and accounted for 37  percent of the E.U.’s electricity production, up from 34  percent in 2019. In comparison, nuclear power produced 733  TWh gross (699  TWh net), around 7  percent more than the previous year, but about 4  percent lower (-32  TWh) than in 2019. Nuclear accounted for 26  percent of E.U. electricity production in 2021.

India. Solar power capacity reached 49.7  GW at the end of 2021 overtaking for the first time the installed capacity of wind with 40.1  GW. Wind has outpaced nuclear in power generation since 2016. Solar passed nuclear generation in 2018 and wind power output in 2021. Wind and solar with each generating 68  TWh together produced 3.4  times more power than nuclear plants. Nuclear electricity production has been declining slightly since 2019.

United States. In 2021, installed wind capacity increased by a record 17  GW, solar added 15.5  GW. Wind power generation increased by 13  percent and solar output by 25  percent while nuclear energy generation dropped to the lowest level since 2012. Renewables provided 14  percent of commercial power while nuclear still contributed just under 20  percent.

Introduction

The year that passed since the publication of WNISR2021 has seen dramatic geopolitical changes in the world with energy issues playing a key role. Low natural gas supply and storage levels in the second half of 2021, and the war in Ukraine and its consequences in 2022 have laid bare Europe’s dependencies on fossil fuels from Russia.

Despite the world’s media focused on Russia and on energy supplies, there has been little attention given to the extent of interdependencies with Russia’s nuclear sector. About half of the natural uranium imported by the European Union (EU) in 2020 was purchased from Russia, and Kazakhstan and Uzbekistan, two Former Soviet Union countries (FSU). Five days after the Russian invasion of Ukraine began, and one day after the European Union closed its airspace to all Russian aircrafts, the Slovakian Government provided a special permission to a Russian plane to fly fresh nuclear fuel assemblies into the country. Slovakia is operating six Russian designed VVER reactors that, in 2021, generated more than half of its electricity. Two additional units, under construction at Mochovce since 1985, are expected to start up soon, with Russian fuel.

The shipment to Slovakia was not the only one to get exceptional flight permission for Russian nuclear fuel. Besides Slovakia, Bulgaria, the Czech Republic, Finland, and Hungary operate VVERs and depend on Russian fuel. Westinghouse, the only other manufacturer, has so far supplied VVER fuel mainly to Ukraine. Even though Ukraine started to get off Russian fuel several years ago, it has converted only about half of its 15 reactors to the alternative fuel. Some other European VVER operators have shown interest in the option in the past and that interest has obviously grown in the past six months.

There are many other services provided by the Russian nuclear industry, which also carries out joint activities with several EU entities. Rosatom has been cooperating with French utility EDF for 30 years in many areas. In 2009, Rosatom purchased the German former nuclear fuel manufacturing company Nukem, now specializing in decommissioning. In December 2021, Rosatom and EDF subsidiary Framatome signed a “long-term cooperation agreement” (see press release hereunder), and in early 2022, Rosatom subsidiary TVEL was about to take a stake in Framatome’s fuel manufacturing plant in Lingen, Germany. Rosatom was also to acquire a 20-percent share in Arabelle-turbine manufacturer GEAST. These turbines produce electricity for European Pressurized Water Reactors (EPR) and Rosatom’s VVER plants. With Russia dominating the narrow international nuclear newbuild market, sanctions against Rosatom would deprive EDF’s subsidiary GEAST from its main customer.

The European Parliament has explicitly called for the inclusion of the nuclear sector in sanctions against Russia. Do these commercial interdependencies explain why the call was not followed-up?

The Russian military occupation of the two nuclear sites, Chernobyl and Zaporizhizhia, and the involvement of Rosatom staff in the forced operation of the facilities by Ukrainian personnel raises questions about the relationship of commercial companies, whether public or private, with the Russian state-owned company.

It also raises questions about the role of the International Atomic Energy Agency (IAEA). The Agency’s Director General Rafael Mariano Grossi visited the Ukrainian nuclear sites and confirmed Rosatom’s presence in Zaporizhizha. While Grossi is lobbying for a security zone around nuclear facilities, Mikhail Chudakov, former longtime official of Rosatom companies, remains his Deputy Director General and Head of the IAEA’s Department of Nuclear Energy.

The IAEA General Assembly started on 26 September 2022, while this is being written. It will be an important challenge to clarify what the basic conditions for technical assistance are and will be in the future. Today, Russia is the country that implements the most new-build projects around the world, many, if not a majority, with the assistance of the IAEA. It is of utmost importance for the IAEA to clarify the conditions under which Russia, state-owned Rosatom, and its many subsidiaries can be seen as a responsible partner for nuclear cooperation in the future.

The issue of shared industrial interests between Russian and non-Russian companies would have merited a focus chapter in WNISR2022. It did not happen. WNISR2022 is nevertheless covering a large range of issues including, for the first time, the implications and risks of operating nuclear power plants in wartimes.

Other developments occurred during the past year that would have merited in-depth coverage in WNISR2022 but proved impossible within the limited capacity of the team. These include:

• The European Parliament’s adoption of the Commission’s proposed Delegated Act that includes certain nuclear and gas activities under the EU Taxonomy of environmentally sustainable economic activities. The regulation will enter into force on 1 January 2023.
• An expansion of our earlier analysis of the COVID-19 pandemic’s serious impacts on the operation, construction, inspection, and control of nuclear power plants.

Because the situation rapidly changed in many countries as a consequence of the war in Ukraine—e.g. the controversy about potential lifetime extensions in Germany—we paused WNISR’s standard editorial practice of limiting content to occurrences before 1 July of the year of publication and updated some chapters well into September 2022.

The winter 2022/2023 might turn into a tough test of the European energy system’s resilience. Some countries rely heavily on natural gas for heating homes and creating industrial process heat (e.g. Germany), while others rely on nuclear energy for electricity generation (e.g.  France). Both sets of countries encounter serious difficulties. While Germany is struggling to compensate for the lack of Russian gas, France is affected by a large fraction of its reactors not operating due to multiple causes. Of any EU-country, France has by far the highest thermal sensitivity in the electricity system. If the thermometer drops by 1°C, the power generating capacity needs climb by 2.4 gigawatt—the equivalent of two large reactors—to cover additional electric space heating needs. Another significant parameter will be the extent to which the wind blows over the European continent. The climate might provide the ultimate system test.

Framatome Press Release, 2 December 2021

General Overview Worldwide

Production and Role of Nuclear Power

In 1970, the Treaty on the Non-Proliferation of Nuclear Weapons (commonly known as the nuclear Non-Proliferation Treaty, or NPT) entered into force. It was seen as a key tool to limit nuclear weapons programs to the five “official” nuclear weapon states China, France, Russia (then the Soviet Union), the U.K., and the U.S.14 In return for not acquiring nuclear weapons capabilities, countries were guaranteed access to technology for nuclear power. Article  IV of the NPT stipulates that “nothing in this Treaty shall be interpreted as affecting the inalienable right of all the Parties to the Treaty to develop research, production and use of nuclear energy for peaceful purposes without discrimination”.15

As of the end of 2021, 33  countries operated nuclear power programs in the world. 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 NPT entered into force in 1970.
• Sixteen additional countries were operating power plants by 1985, the year when reactor startups peaked.
• Five countries (China, Romania, Iran, United Arab Emirates, and Belarus) started up power reactors for the first time over the 30-year period 1991–2020 (none in 2021).
• 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.
• Three countries (Italy, Kazakhstan, Lithuania) abandoned their nuclear programs.
• Fifteen of the current 33 nuclear countries have active reactor construction programs.
• Eighteen countries are not constructing any reactors currently; of these, eight countries have either nuclear phase-out, no-new-build or no-program-extension policies in place. Some of these policies are currently being reviewed.

In 2021, the world nuclear fleet generated 2,653  net terawatt-hours (TWh or billion kilowatt-hours) of electricity16, (see Figure 2) After a decline in 2020, nuclear production increased by 3.9  percent in 2021, but stayed just below the 2019 level. China, with an 11.3  percent increase, produced more nuclear electricity than France for the second year in a row, and remains in second place—behind the United States—for the top nuclear power generators. Outside of China, nuclear production increased 2.8  percent to a similar level as in 2017.

Sources: Compiled by WNISR, with IAEA-PRIS, 2022

Notes:

This figure only displays countries with operating or once operating reactors.

* Japan is counted here among countries with “active construction”; it is however possible that the only project under active construction (Shimane-3) will be abandoned.

Nuclear energy’s share of global commercial gross electricity generation in 2021 was 9.8 percent—the lowest value in four decades—and over 40 percent below the peak of 17.5  percent in 1996.17

Nuclear’s main competitors, non-hydro renewables, grew their output by 16  percent and their share in global power generation increased by 1.1  percentage points to 12.8  percent.18

In 2020, in a global economic environment depressed by the COVID-19 pandemic, fossil fuel consumption slumped: oil by 9.7  percent, coal by 4.2  percent, and natural gas by 2.3  percent. In 2021, in the power sector, the trend was reversed with significant increases in oil +8.9  percent and coal +8.5  percent, while natural gas-based electricity increased by only 2.3  percent.

Nuclear commercial primary energy consumption increased by 3.6  percent while its share in global consumption remained stable at 4.3  percent; it has been around this level since 2014. In the European Union  (EU) nuclear primary energy consumption increased by 6.7  percent, mainly due to generation increases in Belgium and France compared to 2020.

Non-hydro renewables, including mainly solar, wind and biofuels, continued their growth, with an unprecedented 14.7  percent increase, to reach a share of 6.7  percent in primary energy. While the share of non-hydro renewables is now 1.6 times the nuclear share, both figures illustrate how modest the current contribution of both technologies remain in the global context.19

In 2021, there were six countries that increased the share of nuclear in their respective electricity mix (including the two newcomer countries Belarus and United Arab Emirates) —versus eight in 2020— while nine decreased, and 18 remained at a constant level (change of less than 1  percentage point). Besides the two newcomer countries, six countries (Argentina, Belgium, China, Czech Republic, Pakistan, Russia) achieved their largest ever nuclear production. China, Pakistan, and the United Arab Emirates  (UAE) started up new reactors during the year, while the others either profited from startups in the previous year, returns from long upgrading, or backfitting outages.

The following noteworthy developments for the year 2021 illustrate the volatile operational situation of the individual national reactor fleets (see country-specific sections for details):

• Belgium had an exceptional 2021 after years of struggling with technical issues greatly varying nuclear power generation. Output increased by 46  percent in the past year, following a plunge of 21  percent in 2020, a 52-percent increase in 2019, and a 32-percent drop in 2018.
• China started up three units versus two in 2020, just as in 2019, with nuclear generation increasing 11.2  percent, despite the full outage of the Taishan-1 EPR since July 2021.
• France’s nuclear generation increased by 7.3  percent following a 12-percent drop in 2020 but remained below 400  TWh for the sixth year in a row. The outlook for 2022 is dire because numerous reactors have been shut down for various technical reasons.
• Germany generated 7.4  percent more nuclear electricity than in 2020. However, three reactors were closed at the end of 2021.
• Japan had restarted nine reactors after all of them were down in 2014. But after a progressive increase in output, nuclear generation plunged in 2020 by over 34  percent. In 2021, nuclear production increased again by a remarkable 42.2  percent.
• South Africa has a highly volatile nuclear generation pattern. In 2021, the country generated 5  percent more nuclear power than in 2020. In previous years, production declined by 15  percent in 2020, increased by 28 percent in 2019, and dropped by 30  percent in 2018.
• Sweden’s nuclear output increased by 8.6  percent following a 26.5  percent drop in 2020, partly due to the closure of one reactor (Ringhals-2).
• The U.K. nuclear generation has been decreasing steadily since 2016, by another 8.5  percent in 2021, partly due to the closure of three reactors. Since 2016, annual production has dropped by 36  percent. The trend will continue as three more reactors have been closed in 2022 (as of the end of August).
• In the U.S., following the all-time high in 2019, in 2020, nuclear electricity generation dropped (by 2.4  percent) below the 800  TWh mark for the first time since 2015. Five reactors were closed 2019–2021 and, as stated in WNISR2021, it is possible that the country has seen “peak nuclear” and will not get back to earlier production levels.

Sources: WNISR, with BP, IAEA-PRIS, 202220

Similar to previous years, in 2021, the “big five” nuclear generating countries—the U.S., China, France, Russia, and South  Korea, in that order—generated 71  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 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.

In 2021, the top three countries, the U.S., China, and France, accounted for 57  percent of global nuclear production, underscoring the concentration of nuclear power generation in a very small number of countries.

Sources: IAEA-PRIS, and national sources for France and Switzerland, compiled by WNISR, 2022

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

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). Eight countries achieved their historically largest nuclear share in the 1980s and seven in the 1990, in other words, almost half of the nuclear countries had seen the peak before the turn of the century.

Besides the two newcomers which started reactors in 2020 and 2021, only two countries, Pakistan and China reached new historic peak shares of nuclear in their respective power mix. China saw a negligible increase of 0.1  percentage  points to 5  percent and Pakistan’s nuclear share advanced by 3.5  percentage points to 10.6  percent.

Operation, Power Generation, 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 in that year. The second reached a historic maximum in 1984 and 1985, just before the Chernobyl accident, 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 for the first time the number of reactor closures21 outweighed the number of startups.

The 1992–2001 decade globally produced twice as many startups than closures  (51/25), while in the decade 2002–2011, startups amounted to less than two third of the closures  (36/61). Furthermore, it took the whole decade 2000–2009 to connect as many units  (33) as in a single year in the middle of the 1980s (see Figure 4).

In the past decade 2012–2021, 62  reactors—of which 37 (60  percent) in China—were started-up, and 44 were closed.

Over the two decades 2002–2021, there were 98 startups and 105  closures. Of these, 50  startups were in China which did not close down any reactors. As a result, outside China, there has been a drastic net decline by 57  units over the same period (see  Figure 5). As larger units were started up (totaling 88  GW) than closed (totaling 66  GW) the net nuclear capacity added worldwide over the 20-year period was 22  GW. However, since China alone added 47.5  GW, the net capacity outside China declined by over 25  GW.

After the startup of 10 reactors in each of the years 2015 and 2016, only four units started up in 2017, of which three in China and one in Pakistan (built by Chinese companies). In 2018, nine reactors generated power for the first time, of which seven in China and two in Russia. In 2019, six units were connected to the grid, of which three in Russia, two in China, and one in South  Korea, while five units were closed, of which two in the U.S., and one each in Germany, Sweden and Switzerland.

In 2020, five units were connected to the grid, two in China and one each in Belarus, Russia and the United Arab Emirates  (UAE). During the year, six units were closed including two each in France and the U.S. and one each in Russia and Sweden. In 2021, six units were connected to the grid, of which three were in China, one each in India, Pakistan and the UAE, and eight were closed, including three in Germany and one each in Pakistan, Russia, Taiwan, U.K., and U.S. Two additional closures in the U.K. were announced during the year but they had not generated any power since 2018.

Five new units were connected to the world’s power grids in the first half of 2022, including two in China, while two reactors were closed, one each in the U.S. and the U.K. (See  Figure 5).

Sources: WNISR, with IAEA-PRIS, 2022

Notes:
As of 2019, WNISR is using the term “Closed” instead of “Permanent Shutdown” for reactors that have ceased power production, as WNISR considers the reactors closed as of the date of their last production. Although this definition is not new, it had not been applied to all reactors or fully reflected in the WNISR database; this applies to known/referenced examples like Superphénix in France, which had not produced in the two years before it was officially closed or the Italian reactors that were de facto closed prior to the referendum in 1987, or some other cases. Those changes obviously affect many of the Figures relating to the world nuclear reactor fleet (Startup and Closures, Evolution of world fleet, age of closed reactors, amongst others.)

As of 1  July  2022, a total of 411  nuclear reactors were operating in 33  countries, down four units from the situation in mid-2021.22 The current world fleet has a total nominal electric net capacity of 369  GW (no change since WNISR2021), representing a peak just above the former record of 367  GW 2006. As the annual statistics always reflect the status at year-end, the situation might change again by the end of 2022.

The number of operating reactors remains by seven below the figure reached already in 1989 and by 27 below the 2002 peak (see  Figure 6).

Sources: WNISR, with IAEA-PRIS, 2022

For many years, the net installed capacity has continued to increase more than the net number of operating reactors. This is a result of the combined effects of larger units replacing smaller ones. (In 1989, the average size of an operational nuclear reactor was about 740  MW, while that number has increased to 897.5  MW in 2022). Technical alterations raised capacity at existing plants resulting in larger electricity output, a process known as uprating.23 In the U.S. alone, the Nuclear Regulatory Commission  (U.S.NRC) has approved 171  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-2021.24

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 backfitting costs soar and alternatives become cheaper.

Sources: WNISR, with IAEA-PRIS, 2022

Note
Changes in the database regarding closing dates of reactors or LTO status slightly change the shape of this graph from previous editions. In particular, the previous “maximum operating capacity” of 2006 (overtaken in July  2019) is now at 367  GW.

As of mid-2022, the International Atomic Energy Agency  (IAEA) continues to count 33  units in Japan in its total number of 440  reactors “in operation” in the world.25 No nuclear electricity was generated in Japan between September  2013 and August  2015, and as of 25  July  2022, only seven of ten reactors with a valid operating license were operating. Nuclear plants provided 7.2  percent of the electricity in Japan in 2021 up from 5.1  percent in 2020 (for details see Japan Focus).

The WNISR reiterates its call 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” is misleading.

The IAEA does have a reactor-status category called “Long-term Shutdown” or LTS.26 Under the IAEA’s definition, a reactor is considered in LTS, if it has been shut down for an “extended period (usually more than one year)”, and in early period of shutdown either restart is not being “aggressively pursued” or “no firm restart date or recovery schedule has been established”. The IAEA currently lists one single reactor in the LTS category: the Rajasthan-1 reactor in India, which has not generated power since 2004 and is considered permanently closed in 2004 by WNISR. It was moved from the operating to the LTS category by the IAEA in June  2022.

The IAEA criteria are vague and hence subject to interpretation. What exactly are extended periods? What is aggressively pursuing? What is a firm restart date or recovery schedule? 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 has been 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.

Applying this definition to the world nuclear reactor fleet, as of 1  July  2022, leads to classifying 29  units in LTO—all considered “in operation” by the IAEA—three more than in WNISR2021, of which 23 in Japan, three in India  (Madras-1, Tarapur-1 &  -2), two in Canada (Bruce-6 and Darlington-3, scheduled to restart, after refurbishment, in 2023 and 2024), and one in South  Korea (Hanbit-4).

One reactor that re-entered the LTO category in Japan as of July 2021  (Ikata-3) was reconnected to the grid in October 2021.

IAEA vs. WNISR Assessment

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

“The evolution of the world nuclear fleet according to the IAEA shows a peak of officially operating reactors, both in terms of number and capacity, in 2018.”

The evolution of the world nuclear fleet according to the IAEA shows a peak of officially operating reactors, both in terms of number and capacity, in 2018, while WNISR analysis shows the number of units peaking as early as 2002 and capacity in 2006.

WNISR’s assessment of “operating” reactors shows significant differences with IAEA statistics since the beginning of the Fukushima disaster in 2011. The following section provides a detailed explanation and justification of the differences.

Although not the only case, the Japanese fleet provides the main and more visible differences, especially over the past decade. As of December 2021, the IAEA included 33  units in Japan in its total number of 437  reactors “in operation” in the world. However, 23 of these reactors have not produced electricity since 2010–2011 (of which three since 2007). When subsequently the decision is taken to close a reactor—whether or not it was previously considered in LTO—the closure status starts with the day of the last electricity generation, and the WNISR statistics are retroactively modified accordingly. Those are the reactors “Officially closed at a later date” in Figure 7.

Sources: IAEA-PRIS and WNISR

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). On the other hand, the Swiss research reactor in Lucens is not included. Reactors classified as in “Long-term Shutdown”  (LTS) by the IAEA are not represented here. Until July  2022, the IAEA list of operating reactors also included Rajasthan-1 in India, which has not produced since 2004, but has only been classified as “Long-term Shutdown” in June  2022 (with an LTS start date retroactively set to October  2004).27

Applying this definition to the world nuclear reactor fleet, as of 31 December 2021, leads to classifying 29  units as LTO —all considered “in operation” by the IAEA.

Besides the 23 Japanese reactors, the LTO definition also applies to three units in India  (Madras-1, Tarapur-1 & -2), two in Canada (Bruce-6 and Darlington-3), and one in South  Korea (Hanbit-4).

• Bruce-6 and Darlington-3 are under refurbishment since January and July  2020 respectively. They are scheduled to come back online in 2023 and 2024 respectively (see  section on Canada in Annex  1).
• Madras-1 is shutdown since January 2018 to carry out major repair work and has not restarted as of mid-2022. Tarapur-1 and  -2, the two oldest reactors in the world, are “under project mode…for extensive health assessment of primary system” since April and August 2020 respectively (see India Focus).28
• Hanbit-4, impacted by various ageing issues, has not been operating since May 2017. As of mid-2021, it was scheduled to be reconnected to the grid in August  2021, but this did not happen (see South Korea Focus).

The biggest difference is found as of the end of 2012, with 53 units less operating according to WNISR criteria, detailed in Table 1.

1. Table 1 – WNISR Rationale for the Classification of 53 Reactors as Non-Operational as of end 2012

   	Officially Closed at Later Date 21 Reactors		Still in LTO 23 Reactors	Restarted from LTO 9 Reactors
   Typology	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 an LTO period). Most of those reactors were considered “in operation” for many years before their official closure date.		Reactors not restarted since 2012, officially “in  operation” as of 31  December 2021.	Reactors in LTO as of December 2012 Restarted prior to 31 December 2021
   	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	23 Reactors Last production 2006–2012	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, 2022

   Note: *Garoña was subsequently considered in Long-term Shutdown (LTS) 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 sometimes sets at last production and sometimes as closure-decision date while WNISR systematically applies the day of last electricity generation.

   Overview of Current New-Build

   As of 1  July 2022, 53 reactors are considered as under construction, the same number the WNISR reported a year ago, but 16 fewer than in 2013 (five of those units have subsequently been abandoned). The number includes 21  units (40  percent) being built in China.

   Four in five reactors are built in Asia or Eastern Europe. In total, 15  countries are building nuclear plants, two less (Finland and Pakistan) than in WNISR2021 (see Building vs. Vendor Countries.)

   However, only four countries—China, India, Russia, and South Korea—have construction ongoing at more than one site (see Annex  3 for details). Since mid-2021, seven new construction sites were launched worldwide, including six in China. One construction start took place in India  (Kudankulam-6).

   The 53 reactors listed as under construction by mid-2022 compare poorly with a peak of 234—totaling more than 200  GW—in 1979. However, many (48) of those projects  listed in 1979 were never finished (see  Figure 8). 2005, with 26  units under construction, was the lowest since the early nuclear age in the 1950s.

   Compared to the year before, the total capacity of the 53  units under construction in the world in mid-2022 slightly decreased by just 0.8  GW to 53.3  GW, with an average unit size of 1,005  MW.

   

   Sources: WNISR, with IAEA-PRIS, 2022

   Notes:

   This figure includes construction of two CAP1400 reactors at Rongcheng/Shidaowan, although their construction has not been officially announced (see  China  Focus). At Shidao Bay, the HTR plant under construction since 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. There is no indication of grid connection of the second module (see China  Focus for details).

   Building vs. Vendor Countries

   As of mid-2022, China has by far the most reactors (21 units) under construction in the world. However, China is currently not building anywhere outside the country and has only exported to Pakistan. Russia is in fact largely dominating the international market as a technology supplier with 20  units under construction in the world as of mid-2022 of which only three domestically but 17  in seven countries, including four each in China and India and three in Turkey.29 It is uncertain at this point to what extent these projects will be impacted by the various layers of sanctions imposed on Russia and other consequential geopolitical developments following the invasion of Ukraine.

   Besides Russia’s Rosatom, there are only French and South Korean companies building abroad (see  Table 2 and Figure 9).

2. Table 2– Nuclear Reactors “Under Construction” (as of 1 July 2022)30

   Country	Units (Domestic Design)	Other Vendor	Capacity (MW net)	Construction Start	Grid Connection	Units Behind Schedule
   China	21 (17)	Russia: 4	20 932	2012 – 2022	2022 – 2028	3
   India	8 (4)	Russia: 4	6 028	2004 – 2021	2023 – 2027	6(a)
   Russia	3 (3)	–	2 650	2018 – 2021	2023 – 2026
   South Korea	3 (3)	–	4 020	2013 – 2018	2023 – 2025	3
   Turkey	3 (0)	Russia: 3	3 342	2018 – 2021	2024 – 2026	1
   Bangladesh	2 (0)	Russia: 2	2 160	2017 – 2018	2023 – 2024
   Slovakia	2 (0)	Russia: 2(b)	880	1985	2022 – 2023	2
   UAE	2 (0)	South Korea: 2	2 690	2014 – 2015	2023	2
   U.K.	2 (0)	France: 2	3 260	2018 – 2019	2027 – 2028	2
   U.S.	2 (2)	–	2 234	2013	2023	2
   Argentina	1 (1)	–	25	2014	2027	1
   Belarus	1 (0)	Russia: 1	1 110	2014	2022	1
   France	1 (1)	–	1 630	2007	2023	1
   Iran	1 (0)	Russia: 1	974	1976	2024	1
   Japan	1 (1)	–	1 325	2007	2025  ?	1
   Total	53		53  260	1976 - 2022	2022 – 2028	26
   Total per Vendor Country: Russia: 20 - China: 17 - South Korea: 5 - India: 4 - France: 3 - U.S.: 2 - Argentina: 1 - Japan: 1

   Sources: Various, compiled by WNISR, 2022

   Notes:

   (a) - Of the eight 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. Six is the number of reactors “formally” delayed. See India Focus.

   (b) - The Mochovce Units 3 and 4 are a Russian VVER design being completed by Czech-led consortium.

   This table does not contain suspended or abandoned constructions.

   It includes construction of two CAP1400 reactors at Rongcheng/Shidaowan, although their construction has not been officially announced (see  China Focus). At Shidao Bay, the HTR plant under construction since 2012 has two reactors on the site and is therefore counted as two units as of WNISR2020. Grid connection of the first unit of the twin reactor officially took place on 20 December 2021. There is no indication of grid connection of the second unit.

   

   Sources: WNISR, with IAEA-PRIS, 2022

   Construction Times

   Construction Times of Reactors Currently Under Construction

   A closer look at projects listed as “under construction” as of 1  July  2022 illustrates the level of uncertainty and problems associated with many of these projects, especially given that most builders still assume a five-year construction period:

   • For the 53  reactors being built, an average of 6.8  years has passed since construction start—slightly lower than the mid-2021 average of seven  years— and many remain far from completion.
   • All reactors under construction in at least 10 of the 15  countries have experienced mostly year-long delays. At least half (26) of the building projects are delayed. Most of the units which are nominally being built on-time (yet) were begun within the past three years or have not yet reached projected startup dates, making it difficult to assess whether they are on schedule. Particular uncertainty remains over construction in China because of lack of access to information. While it is unclear what will happen with Russian designed and/or implemented projects in seven other countries, as sanctions have or will likely have an impact on supply chains.
   • Of the 26 reactors clearly documented as behind schedule, at least 14 have reported increased delays and two have reported new delays over the past year.
   • WNISR2020 noted a total of  19  reactors scheduled for startup in 2021, and at the beginning of 2021, 16 were still planned to be connected to the grid but only six of these made it, while the other 10 were delayed at least into 2022.
   • Construction starts of two projects date back 37  years, Mochovce-3 and -4 in Slovakia, and their grid connection has been further delayed, currently to late 2022 and 2023. Bushehr-2 in Iran originally started construction in 1976, over 45  years ago, and resumed construction in 2019 after a 40-year-long suspension. Grid connection is currently scheduled for 2024.
   • Six additional reactors have been listed as “under construction” for a decade or more: the Prototype Fast Breeder Reactor  (PFBR), Kakrapar-4 and Rajasthan-7 &  -8 in India, Shimane-3 in Japan, and Flamanville-3  (FL3) in France. The French and Indian projects have been further delayed this year, and the Japanese reactor does not even have a provisional startup date.

   The actual lead time for nuclear plant projects includes not only the construction itself but also lengthy licensing procedures in most countries, 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 regulations were less stringent. As Figure 10 illustrates, construction times of reactors completed in the 1970s and 1980s were quite homogenous, while in the past two decades they have varied widely.

   The seven  units completed in 2019–2021 in China took on average 6.4  years to build, while the four projects finalized in Russia took a mean 11.4  years (compared to 15  years for the period 2018–2020).

   As Figure 11 shows for the period 2019–2021, the longest construction times for those two countries were for the EPR at Taishan-2 (9.2  years), the first reactor of the two HTR module at Shidao  Bay  1 (9.1  years) and the floating reactors Academic Lomonosov-1 and  -2 (12.1  years).

   The case of the twin “floating” reactors Akademik-Lomonosov is particularly interesting. These are small 30-MW reactors meant to demonstrate a new generation of Small Modular Reactors  (SMRs), smaller, cheaper, and faster to build. However, construction has taken longer than any other reactor that has come on-line over those three years and took about 3.5  times as long as originally projected; a little before construction of the ship began in 2007, Rosatom announced that the plant would begin operating in October  2010.31 But that happened only in December  2019. Not surprisingly, the “nuclear barge” has become more expensive, from an initial estimate of around 6  billion  rubles (US$2007232  million)32 to at least 37  billion rubles as of 2015 (US$2015740  million),33 or close to US$25,000 per installed kilowatt, almost twice as costly as the most expensive Generation  III reactors.34

   

   Sources: WNISR, with IAEA-PRIS, 2022

   The mean time from construction start to grid connection for the six reactors started up in 2021 was 7.1  years, comparable to 2020 (7.2  years), a clear improvement over the 9.9  years in 2019. In the case of the five units connected in the first half of 2022, the duration was nine  years.

   “Over the three years 2019–2021,
   only two of 17 units started up on-time.”

   While mean construction times have been declining recently, over the three years 2019–2021, only two of 17 units started up on-time. Those are Tianwan-4 and  -5 in China, a Russian-designed but mainly Chinese-built VVER-1000 (model V-428M), that the designers claim to belong to Gen  III classification, but few details are known. The two Chinese units Hongyanhe-5 and  Yangjiang-6 were completed with minor delays in 6.2 and 5.5  years respectively. These are ACPR1000 reactors, designed by China General Nuclear Corp.  (CGN) that claims contain at least ten improvements making them a Gen  III design35.

   

   Sources: Compiled by WNISR with IAEA-PRIS, 2022

   Note:

   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.

   The longer-term perspective confirms that short construction times remain the exceptions. Ten countries completed 62  reactors over the decade 2012–2021—of which 37 in China alone—with an average construction time of 9.2  years (see Table 3). That is an improvement of 0.7  years over the mean construction time in the decade 2011–2020.

3. Table 3 – Duration from Construction Start to Grid Connection 2012–2021

   Construction Times of 62 Units Started-up 2012–2021
   Country	Units	Construction Time (in Years)
   		Mean Time	Minimum	Maximum
   China	37	6	4.1	9.2
   Russia	9	17.9	8.1	35.1
   South Korea	5	6.4	4.2	9.6
   India	3	12	10.1	14.2
   Pakistan	3	5.6	5.5	5.6
   UAE	2	8.2	8.1	8.3
   Argentina	1	33.0	33.0
   Belarus	1	7.0	7.0
   U.S.	1	42.8	42.8
   World	62	9.2	4.1	42.8

   Sources: Various, compiled by WNISR, 2022

   Construction Starts and Cancellations

   The number of annual construction starts36 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 12 and Figure 13). That number dropped to five in 2020—including four in China—while building started on ten units in 2021—including six in China. The other four units are implemented by the Russian nuclear industry in India  (2), in Turkey and domestically, and two of the construction starts in China were also by the Russian industry. In other words, of the global total of ten, six reactors were by Russian builders and four by Chinese industry.

   Three reactors got underway in the world in the first half of 2022, all of them in China, two of which are of Russian design. Chinese and Russian government owned or controlled companies launched all of the 18  reactor constructions in the world over the 30-month period from the beginning of 2020 to mid-2022.

   

   Sources: WNISR, with IAEA-PRIS, 2022

   Notes:

   Construction of Bushehr-2, started in 1976, was considered abandoned in earlier versions of this figure. As construction was restarted in 2019, it now appears as “Under Construction”.

   The Chinese project at Shidao Bay-1 is considered as two reactors, and construction starts in 2012 reflect this change.

   Over the decade 2012–2021, construction began on 63  reactors in the world, of which half  (31) in China. Three of these building sites have been abandoned over the period (Baltic-1 in Russia, V.C.  Summer-2 and  -3 in the U.S.). As of mid-2022, 19 of the remaining 60  units have started up, while 41 remain under construction.

   “The two V.C.  Summer units, 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 nuclear power plant projects.”

   Seriously affected by the Fukushima events, China did not start any construction in 2011 and 2014 and began work only on seven 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 and three in the first half of 2022 (see Figure 13). While this increase represents a sign of the restart of commercial reactor building in China, the level continues to remain far 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 2021, 53  reactors with a total capacity of 49.7  GW were operating and 20  units (19.2  GW) were under construction (for details, see  China Focus).

   

   Sources: WNISR, with IAEA-PRIS, 2022

   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, 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 nuclear power plant projects.

   

   Sources: WNISR, with IAEA-PRIS, 2022

   Note: This graph only includes constructions that had officially started with the concreting of the base slab of the reactor building.

   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 14). The United  States alone accounted for 138 of these order  cancellations.37

   Of the 790  reactor constructions launched since 1951, at least 93  units in 19  countries had been abandoned or suspended, as of 1  July  2022. This means that 12  percent—or one in eight—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 new-build over many years, the average age (from grid connection) of operating nuclear power plants has been increasing since 1984, and as of mid-2022 is 31  years, up from 30.9  years in mid-2021 (see  Figure 15).38

   A total of 270  reactors, two-thirds of the world’s operating fleet, have operated for 31  or more years, including 105—more than one in five—for at least 41  years.

   

   Sources: WNISR, with IAEA-PRIS, 2022

   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 is also leading the age pyramid. The average age of reactors in the U.S. passed 40-years in 2020 and reached 41.2  years as of the end of 2021. France’s fleet now exceeds 36  years. Russia inverted the curve starting in 2016 and its average fleet age of 28.4  years as of the end of 2021 remains 1.8  years below the 2015-peak. South  Korea’s reactors at 22.4  years remain almost half as old as the U.S. fleet, and China is the obvious newcomer with an average fleet age of just 8.8  years. (See  Figure 16).

   

   Sources: WNISR, with IAEA-PRIS, 2022

   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.”39

   As of mid-2022,  97 U.S. units had received a 20-year license extension, no further applications were under NRC review. Ten units with renewed licenses were closed early, and two applications for three reactors were withdrawn as Crystal  River was closed; the two Diablo  Canyon units are scheduled to close when their current license expires in 2024–2025, although their closure might be deferred until 2029 and 2030 (see  United States Focus). Three additional applications for five reactors are expected in 2023–2024.40

   So far, the NRC has granted Subsequent Renewed Operating Licenses to six reactors, which permit operation from 60 to 80  years. A further nine reactors have their applications still under review.41

   “Only nine of the 41  units that have been closed in the U.S. had reached 40  years on the grid.”

   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 mainly for economic reasons. In other words, at least a quarter of the 133  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 92  currently operating plants, 47  units have already operated for 41  years and six have been on the grid for 50 years or more; thus, over half of the units with license renewals have entered the lifetime extension period, and that share is growing rapidly with the mid-2022 mean age of the U.S. operational fleet exceeding 41.5  years (see Figure 40 in United States Focus).

   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 37  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 the limit of their initial design. However, the ASN assessments are years behind schedule. For economic reasons, the French state-controlled utility Électricité de France  (EDF) prioritizes lifetime extension to 50  years over large-scale new-build.

   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.

   Recently commissioned reactors and the ones under construction in South  Korea do or will have a 60-year operating license from the start. EDF will certainly also aim for 60-year operating licenses for its Flamanville-3 project and the Hinkley  Point  C units in the U.K.

   In assessing the likelihood of reactors 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 204  units that have already closed (see  Figure 15 and Figure 17). In total, 89 of these units operated for 31  years or more, and, of those 89, 39  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.

   

   Sources: WNISR, with IAEA-PRIS, 2022

   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 2017 and 2021 was 42.2  years (see  Figure 18).

   

   Sources: WNISR, with IAEA-PRIS, 2022

   As a result of the Fukushima nuclear disaster (elsewhere 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 accidents 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. 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, including in Belgium, Switzerland, and Taiwan. Some of the main nuclear countries closed their respective then oldest unit before age  50, including Germany at age  37, South  Korea at 40, Sweden at 46 and the U.S. at 49. France closed its two oldest units in spring  2020 at age  43.

   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 19), assumes a general lifetime of 40  years for worldwide operating reactors—not including reactors in Long-Term Outage  (LTO).

   Forty years corresponds to the design lifetimes of most operating reactors. Some countries have legislation or policy in place—including Belgium, South  Korea (in the course of being changed by the incoming administration)—Taiwan, that limit operating lifetime, for all or part of the fleet, to 40  or 50  years. Recent designs, mostly reactors under construction, have a design lifetime of 60  years (e.g.  APR1400, EPR). For the 115  reactors that have passed the 40-year lifetime as of mid-2022, 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 20) takes into account all already-authorized lifetime extensions and assumes that the respective reactors will operate until the expiration of their license.

   The lifetime projections allow for an evaluation of the number of plants 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 plants and level of capacity, if all units were closed after a lifetime of 40  years or after their licensed lifetime extension.

   Considering all units under construction scheduled to have started up 12  additional reactors (compared to the end of 2021 status) would have to be commissioned or restarted prior to the end of 2022 in order to maintain the status quo of operating units. Without additional startups, or last-minute lifetime extensions as envisaged in Germany and in Belgium, installed nuclear capacity would decrease by 10.6  GW by the end of 2022.

   In the decade to 2030, in addition to the units currently under construction, 161  new reactors (137  GW)—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 (63  startups between 2012 and 2021).

   

   Sources: Various sources, compiled by WNISR, 2022

   Notes pertaining to Figure 19, Figure 20 and Figure 21:

   Those figures include one Japanese reactor (Shimane) and two Chinese 1400  MW-units at Shidao  Bay, for which the startup dates were arbitrarily set to 2025 and 2024, as there are no official dates.

   Restarts or closures amongst the 29  reactors in LTO as of 1  July  2022 are not represented here although at least two Canadian reactors that are in LTO are set to be restarted, and thus later closed as well.

   The figures also take into account current political decisions or legally binding obligations as of end of August  2022 to close reactors prior to 40  years (Germany, South-Korea). These decisions are under discussions in both countries and might be reversed after the editorial deadline of WNISR2022, as it is the case in Belgium, with discussions on a ten-year lifetime extension for two reactors.

   In the case of reactors that have reached 40  years of operation prior to 2022, the 40-year projection also uses the end of their licensed lifetime (including reactors licensed for 80  years in the U.S.).

   In the case of French reactors that have reached 40  years of operation prior to 2022 (startup before 1982), 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 2022 (9  reactors), we use a 10-year extension, although no licensing procedure has been completed for this extension. For all those that have already passed their 3rd  periodic safety review, the scheduled date of their 4th periodic safety review (or 10-year extension for the cases previously mentioned) is used in the PLEX projection, regardless of their startup date.

   The stabilization of the situation by the end of 2022 is only possible because most reactors will likely not close at the end of the year, regardless of their age. As a result, the number of reactors in operation will probably continue to stagnate at best, unless—beyond restarts—lifetime extensions become the rule worldwide. Such generalized lifetime extensions—far beyond 40  years—are clearly the objective of the nuclear power industry, and, especially in the U.S., there are numerous attempts to obtain subsidies for uneconomic nuclear plants in order to keep them on the grid (see  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, Chinese medium-term ambitions appear significantly lower than anticipated in the pre-3/11 era.

   

   Sources: Various sources, compiled by WNISR, 2022

   Notes: see Figure 19.

   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, we have maintained a 40-year lifetime projection, unless a firm earlier or later closure date has been announced. By the end of 2022, the net number of operating reactors and operating capacity would remain almost stable (+ 1  unit / + 0.9  GW).

   In the decade to 2030, the net balance would turn negative as soon as 2024, and an additional 110  new reactors (83.5  GW)—one unit or 0.7  GW per month—would have to start up or restart to replace closures. The PLEX-Projection would still mean, in the coming decade, a need to double the annual building rate of the past decade from six to twelve (see Figure 19, Figure 20 and the cumulated effect in Figure 21).

   However, as has been documented construction starts have not been picking up over the past decade. Between 2012 and 2016, a total of 32  constructions were launched around the world, of which 16 in China and three later abandoned. Between 2017 and 2021, constructions started at 31  units, of which 15 in China, thus an average of six units per year were launched and sustained, significantly less than half than of the building rate needed according to the PLEX Projection over the coming decade just to maintain the current number of operating reactors in the world.

   

   Sources: Various sources, compiled by WNISR, 2022

   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 53 reactors under construction as of 1  July  2022. (See  Figure 19.)

   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.

   Focus Countries

   

   The following chapter offers an in-depth assessment of ten countries: China, Finland, France, Germany, India, Japan, South Korea, Taiwan, United Kingdom (U.K.), and the United States  (U.S.). They represent 30  percent of the nuclear countries, two thirds of the global reactor fleet and four of the world’s five largest nuclear power producers. For other countries’ details, see  Annex 1.

   Unless otherwise noted, data on reactor capacity (as of mid-2022) and nuclear’s share in electricity generation in 2021 are from the International Atomic Energy Agency’s Power Reactor Information System  (IAEA-PRIS) online database.

   Numbers of reactors under construction, operating, in LTO or closed are WNISR assessments based on IAEA-PRIS and industry data. Historical maximum figures indicate the year that the nuclear share in power generation of a given country was the highest since 1986, the year the Chernobyl disaster began.

   See Annex 2 for a general country overview of main indicators.

   China Focus

   

   As of mid-2022, China had 55  operating reactors, including the China Experimental Fast Reactor  (CEFR), with a combined capacity of around 52  GW. Nuclear plants generated 383.2  TWh in 2021, which constitutes 5  percent of the electricity produced in the country, almost the same as in 2020. In absolute terms, total electricity generated represents an increase of 11  percent over the 2020 value, which pales in comparison to increases of 40  percent and 25  percent increases in wind and solar energy generation respectively. Coal increased by about 9  percent.42

   China operates by far the youngest large nuclear fleet in the world, with 41 reactors, almost four in five, having connected to the grid within the past ten years (see Figure 22).

   In March 2022, the National Energy Administration (NEA) issued the “14th Five-year Plan for Modern Energy System”, which called for “the active development of nuclear power in a safe and orderly manner” and set the target of increasing installed nuclear power capacity to 70  GW by 2025.43 The target laid out in the 2021–2025 five-year plan was also 70  GW. That target of 70  GW was first suggested for 2020 by the China Nuclear Energy Association more than a decade ago, in 2010, and there were even targets as large as 114  GW by 2020 that were reported at the time.44

   

   Sources: WNISR, with IAEA-PRIS, 2022

   The relatively low target appears to reflect a continued caution about the growth of nuclear power, which became apparent in the aftermath of the multiple nuclear accidents at Fukushima.45 Indeed, there were concerns about expanding nuclear power too rapidly even prior to those accidents. In 2009, Li  Ganjie, then the director of China’s National Nuclear Safety Administration, warned: “At the current stage, if we are not fully aware of the sector’s over-rapid expansions, it will threaten construction quality and operation safety of nuclear power plants”.46

   In the end, the suggestion of 70  GW by 2020 was not accepted by the Chinese leadership. Instead, the target set for 2020 was to put “58  GW into operation and have another 30  GW under construction”, and in 2016, the chairman of the China Atomic Energy Authority asserted that China was due to meet that target.47 Those targets were not met; which will also be the case with the current target for 70  GW of operational capacity by the end of 2025. The combined net capacity of the operational plants and the ones under construction that are due to be operating before 2026 is only around 61  GW—and that is assuming no further delays. In other words, the goal of 70  GW at the end of 2025 is simply not achievable.

   The NEA’s plan also set a 2025 target of 39 percent for the share of electricity generated from non-fossil fuels, as compared to 32.6  percent in 2021. But much of this increase is expected to come from renewables. In October  2021, China’s Nationally Determined Contribution report  (NDC) submitted to the United Nations Framework Convention on Climate Change  (UNFCCC) set a target of 1,200  GW by 2030 for total installed capacity of wind and solar power, but media reports and expert analyses of projects already being planned suggest that this target could even be met by 2025.48

   As of June 2022, there was a total of 340  GW of solar PV reportedly installed in the country.49 About half of the wind and solar capacity to be connected to the grid by 2025 is expected to be from gigantic clean energy bases.50 Further, the NEA’s March  2022 plan requires “200  GW of coal-fired generation to be retrofitted to enhance flexibility, especially small units below 300  MW, which allows them to be restarted at short notice to back up solar and wind capacity, to resolve intermittency issues”.51 The Chinese government is evidently trying to resolve the widely acknowledged challenge for solar and wind power projects of their outputs being curtailed during periods of high production and/or low demand.52 Curtailment has declined in recent years,53 but there is still concern that it will increase as renewable energy becomes a larger fraction of the supply of electricity.

   The ongoing anticorruption campaign might also have some effect on the pace of growth of nuclear power. In March  2022, Liu Baohua, NEA deputy director, was sentenced to 13  years in prison for taking bribes.54 Since the launch of the anti-corruption campaign, numerous officials—from central to local energy system representatives, from regulatory agencies to large power generation institutions—have been investigated for corruption. According to a listing from October  2020 in Nuclear Intelligence Weekly, there had been at least eleven other indictments of senior NEA officials in the previous eight years.55

   Since the release of WNISR2021, only three units have been connected to the grid: Fuquing-6, Shidao  Bay  1-1 and Honghyane-6. Fuqing-6, a Hualong 1 unit, was connected to the grid in January  2022, a little over six years after construction started in December  2015.56

   The first of two High Temperature Gas Cooled Reactor  (HTGR) units at Shidao  Bay (Shidao  Bay  1-1  and  1-2)—IAEA-PRIS considers these as one plant—was connected to the grid on 20 December 2021.57 As of the time of this writing, there is no public announcement that the second unit has been connected. Further, between January and June  2022, there was no power fed to the grid from this site, according to China Nuclear Energy Industry Association  (CNEIA).58 No information has been published about the reasons for the additional delays in commissioning the second unit and for the shutdown of the first unit in the first half-year of 2022. CNEIA also records no power fed into the grid from Taishan-1 during the same period.

   ‘‘Actually, construction took nearly 109 months, more than twice the expected length.’’

   Construction of the Shidao Bay HTGR reactors started in December  2012 and at that time construction was projected to “take 50  months, with 18  months for building, 18  months for installation and 14  months for pre  commissioning”.59 Actually, construction took nearly 109  months, more than twice the expected length. In addition to the lengthy delay, another problem for these HTGR units is high capital cost. The World Nuclear Association  (WNA) reported a construction cost of US$6,000 per  kW for these units as compared to figures in the range of US$2,600 to US$3,500 per  kW for Hualong-One reactors.60 Further, the costs for fuel fabrication, operations, and maintenance would be thrice the corresponding costs for light water reactors.61

   When construction of Hongyanhe-6 started in 2015, it was scheduled to begin operating in 2020.62 In March  2022, China General Nuclear  (CGN) announced that fuel loading had been completed63 and the reactor was finally connected to the grid on 2  May  2022.64

   As of 1 July 2022, there were 21 nuclear units under construction, including the Xiapu fast reactor units and the second HTGR unit at Shidao Bay  1. The projects that are currently under construction include Fangchenggang-3 since 2015, Fangchenggang-4 since 2016, four reactors (Zhangzhou-1, Taipingling-1, Shidao Bay 2-1 and Shidao Bay 2-2) since 2019; three units (Taipingling-2, Sanaocun-1, Zhangzhou-2) since 2020, and three more (Changjiang-3, Tianwan-7, and Xudabao-3) since the first half of 2021.65

   Since mid-2021, construction has started on six reactors (Changjiang SMR, Changjiang-4, Sanaocun-2, Tianwan-8, Xudabao-4, and Sanmen-3).66 Two of these are reactors supplied by Russia’s Rosatom with construction starting after the commencement of the war on Ukraine. There are no official dates for the construction start of the Xiapu fast reactor units, but construction of the first unit is reported to have started in 2017 and the second unit in 2021.67

   The startup of at least two reactors currently under construction has been significantly delayed. The first of the Fangchenggang units was scheduled to start trial operations in 2020.68 In January  2022, CGN adjusted the expected date of commencement of operation of Fangchenggang-3 to the second half of 2022, and Fangchenggang-4 to the first half of 2024.69 These units were to be the reference for the proposed Bradwell  B project in the U.K.70

   China has ambitions to export nuclear power plants. Chinese officials promote this aim with the justification that it will encourage industrial production, especially of highly sophisticated equipment. In 2016, the president of China National Nuclear Corporation  (CNNC) announced that “China aims to build 30  overseas nuclear power units… by 2030”.71 So far China has only exported nuclear plants to Pakistan. All six units operating in Pakistan are of Chinese design. Various other international projects, including in Romania and the U.K., have so far not proceeded to the stage of construction.

   In February 2022, CNNC signed an agreement to build a Hualong One nuclear plant in Argentina.72 How this project will evolve is uncertain. Argentina has signed many agreements earlier, including one between Nucleoelectrica Argentina SA, Atomic Energy of Canada Ltd, and CNNC in 2007 to construct a CANDU reactor.73 Again, in 2017, Chinese president Xi  Jinping and Argentinean president Mauricio  Macri signed an agreement with China to build a CANDU and a Hualong One reactor.74 Neither of these happened.

   “Solar power generated the equivalent of more than 80  percent of nuclear electricity whereas wind power exceeded nuclear generation by 60  percent.”

   In the case of the latter agreement, the requirement reportedly hinged “entirely on the Chinese side putting up the financing”.75 This time too, the Argentinian government is pushing China to fully finance construction of this plant because it is dealing with high debt levels.76 Whether China can come up with this financing—on top of all the other Belt and Road Initiative construction projects—remains an open question.77

   In the meantime, renewable energy capacity in China continues to grow rapidly. According to the China Electric Power Industry Association, total installed renewable capacity increased by 13.4  percent in the past year, going from 905  GW in 2020 to 1,026  GW in 2021. The largest component of that expansion was in solar capacity, which increased from 253  GW in 2020 to 306  GW in 2021; wind capacity went from 281  GW in 2020 to 328  GW in 2021.78 Wind and solar power injected respectively 656  TWh and 327  TWh to the grid in 2021; solar power generated the equivalent of more than 80  percent of nuclear electricity whereas wind power exceeded nuclear generation by 60  percent.79

   Finland Focus

   

   Four nuclear reactors supplied 22.7  TWh of electricity in Finland, close to the peak 22.9  TWh in 2019. The nuclear share represented 32.8  percent in 2021, a drop of 1.1  percentage points over 2020, compared to a peak of 38.4  percent in 1986.

   Finland’s fifth reactor, the 1.6  GW EPR at Olkiluoto (OL3)—which had been under construction since August  2005 and was originally scheduled to begin operations in 2009—was finally connected to the grid on 12  March  2022.80 Credit-rating agencies welcomed the development and raised TVO’s rating based on then scheduled commercial operation by July  2022.81

   Following the pattern of countless technical problems and delays during the construction phase, the commissioning stage of OL3 continues to be hampered by “unexpected” events like the untimely triggering of the boron pumps in April  2022 and “foreign material issues observed in the turbine’s steam reheater” in May  2022. Therefore, according to TVO “regular electricity production is to start in December  2022, instead of the previously announced start in September  2022”.82 In mid-2020, the schedule was still for commercial operation to begin by 31  May  2021,83 but progressively delayed to July, then September, then December  2022. Even after first grid connection, technical issues keep impacting the startup schedule.

   Finland has adopted different nuclear technologies and suppliers, as two of its operating reactors are modified VVER-V213 built by Russian contractors at Loviisa, while two are AAIII, BWR-2500 built by Asea Brown Boveri  (ABB) at Olkiluoto. The OL3 EPR contractor is AREVA (-Siemens). After the technical bankruptcy and dismantling of AREVA  Group, the French government kept AREVA  S.A. to deal with the liabilities of the project.

   The average age of the first four operating reactors is 43.3 years. In January  2017, operator TVO  (Teollisuuden Voima Oyj) filed an application for a 20-year license extension for Olkiluoto-1 and  -2 (OL1, OL2), which were connected to the grid in 1978 and 1980 respectively.84 On 20  September  2018, the Cabinet approved the lifetime extension for both units to operate until 2038.85

   In March 2022, Fortum, owner-operator of the Loviisa nuclear power plant, filed a license renewal application with the Finnish government aiming at a permission to operate the two units until the end of 2050.86 Current licenses had already been extended in 2007 and expire in 2027 and 2030 respectively.87 As Loviisa-1 was first connected to the grid in 1977 and Loviisa-2 followed in 1980 that would mean 73- and 70-year operating lifetimes respectively. Fortum estimates that the application review process will take about one year.

   Fennovoima’s Hanhikivi Project Cancelled

   In 2007, the group Fennovoima was set up as a non-profit cooperative of power companies and industry.88 In March 2014, Russian state nuclear operator Rosatom, through subsidiary company RAOS Voima  Oy, completed the purchase of 34  percent of the Finnish company Fennovoima for an undisclosed price,89 and then in April  2014 a “binding decision to construct” Hanhikivi-1, a 1,200  MW AES-2006 reactor, was announced.90

   Following repeated delays, on 28  April  2021, Fennovoima submitted an updated application to the Finnish regulator STUK (Säteilyturvakeskus) for a construction license with work to start in 2023, and commercial operation by 2029.91 Construction of Hanhikivi-1 was then ten years behind the original schedule.92 Estimated costs for the project had increased from €6.5-7  billion (US$7.7–8.3  billion) to €7–7.5  billion (US$8.3–8.8  billion).93

   In November 2021, the Finnish Ministry of Defense included a quite premonitory request into a security risk analysis of the Hanhikivi Project that “should include a clear look at, for example, how any new sanctions on Russia would affect the project and how they would be treated. Account should also be taken of the Rosatom Group’s links with the Russian defense industrial complex and related measures to pursue Russia’s security policy goals.”94

   Three months later, Russia invaded Ukraine, which dramatically changed the situation of the Hanhikivi project. Four days after the invasion started, Fennovoima declared that “for the time being, we continue executing our project and carefully follow the developments of the situation”,95 and on 15  March  2022 added that, while the nuclear sector has not been explicitly included, “the current decided sanctions are expected to impact the Hanhikivi  1 project. Fennovoima considers the situation to be challenging.”96

   The Finnish city of Vantaa was the first Fennovoima shareholder to publicly state, on 28  March  2022, that its municipal energy company, Vantaan Energia, would have to withdraw from the Hanhikivi project, saying the situation in Ukraine “makes it unlikely a license would be granted”.97

   On 4  April  2022—one month after Russian forces attacked and then occupied the Zaporizhzhia nuclear plant in Ukraine—Fennovoima reiterated the statement that “for the time being, we continue executing our project and carefully follow the developments of the situation”.98 One week later, Rosatom’s subsidiary RAOS  Project told Reuters: “Rosatom and RAOS Project continue fulfilling their obligations under signed agreements and contracts relating to the Hanhikivi 1 project”.99

   On 2  May  2022, Fennovoima announced that the contract of plant delivery and cooperation with RAOS  Project on Hanhikivi-1 was terminated “with immediate effect”.100 The reasons indicated in a press statement were

   …RAOS Project’s significant delays and inability to deliver the project. There have been significant and growing delays during the last years. The war in Ukraine has worsened the risks for the project. RAOS has been unable to mitigate any of the risks.101

   Rosatom immediately replied that the decision to cancel the contract “was taken without any detailed consultation with the project’s shareholders, the largest of which is RAOS Voima” and that “the reasons behind this decision are completely inexplicable to us.”102 On 6  May  2022, Rosatom issued a further statement saying that “the arguments presented by our Finnish partners for the termination contradict the actual status of the project and Fennovoima’s earlier statements noting the progress and prospects for its successful completion”. Rosatom concluded that “the decision of the Finnish partners to terminate the Hanhikivi-1 NPP project is non-market and politically motivated” and thus “we have no other choice but to defend ourselves and demand compensation for this unlawful termination”.103

   On 24  May 2022, Fennovoima has officially withdrawn the Hanhikivi-1 license application.104

   In 2018, it was reported that Fennovoima would invest €400–500  million (US$2018494–618  million) into the project before the construction even started.105 When announcing the contract cancellation, Fennovoima’s Board Chairman, Esa  Harmala, told reporters the consortium had already spent €600-700  million (US$2022600–700  million) on the project.106

   The contract cancellation will no doubt lead to a lengthy legal battle between stakeholders.

   The Olkiluoto-3 (OL3) Saga

   In December 2003, Finland became the first country in Western Europe to order a new nuclear reactor since 1988. AREVA  NP, then a joint venture owned 66  percent by AREVA and 34  percent by Siemens, was contracted to build the European Pressurized Reactor  (EPR) at OL3 under a fixed-price, turnkey contract with the utility TVO. Siemens quit the consortium in March  2011 and announced in September  2011 that it was abandoning the nuclear sector entirely.107 After the 2015 technical bankruptcy of the AREVA  Group, in which the cost overruns of Olkiluoto had played a large part, the majority shareholder, the French Government, decided to integrate the reactor-building division under “new-old name” Framatome into a subsidiary majority-owned by state utility EDF.

   “OL3 construction started in August  2005, with operations planned from 2009. However, that date—and other dates—passed.”

   However, EDF made it clear that it would not take over the billions of euros’ liabilities linked to the costly Finnish AREVA adventure.108 Thus, it was decided that the financial liability for OL3 and associated risks stay with AREVA  S.A. after the sale of AREVA  NP and the creation of a new company AREVA Holding, now named Orano, that will focus on nuclear fuel and waste management services, very similar to the old COGEMA. In July  2017, the French Government confirmed that it had completed its €2  billion (US$20182.3  billion) capital increase,109 most of which was to cover some of the costs to AREVA of the OL3 investment.

   The OL3 project was financed essentially on the balance sheets of the Finland’s leading firms and heavy energy users as well as several municipalities under a unique arrangement that makes them liable for the plant’s indefinite capital costs for an indefinite period, whether or not they get the electricity—a capex “take-or-pay contract”—in addition to the additional billions incurred by AREVA under the fixed price contract.

   OL3 construction started in August  2005, with operations planned from 2009. However, that date—and other dates—passed.

   From the beginning, the OL3 project was plagued with countless management and quality-control issues. Not only did it prove difficult to carry out concreting and welding to technical specifications, but the use of sub-contractors and workers from over 50  nationalities made communication and oversight extremely complex (see previous WNISR editions).

   After further multiple delays, TVO announced in June 2018 that grid connection was planned for May  2019 and “regular electricity generation” in September  2019.110 In April  2019, fuel loading was pushed further to August  2019. TVO’s plans for grid connection in October  2019 and electricity generation by January  2020111 were considered by WNISR2019 as highly optimistic

   In July 2019, TVO announced that it had once again delayed operations for OL3 by six months.112 The startup date was moved to July  2020 by nuclear plant supplier the AREVA-Siemens consortium. TVO announced that nuclear fuel was scheduled to be loaded into the reactor in January  2020 and the first connection to the grid was to be in April  2020. By November  2019, the revised schedule for OL3 start had slipped a further six weeks, according to TVO.113 The delays were said to be due to final verification of the mechanical, electrical and Instrumentation and Control  (I&C) systems.

   In December 2019, the AREVA-Siemens Consortium informed TVO114 that OL3 would be connected to the grid in November  2020 with regular electricity generation from March  2021.115 Nuclear fuel loading was planned for June  2020. The delays were said to be due to “slow progress of system tests and shortcomings in spare-part deliveries”.116 Among other things, in the tests of auxiliary diesel generators some faulty components were found.117

   On 8  April  2020, TVO announced that it had applied to the regulator STUK, for approval for fuel loading.118 It was expected to take two months. At the same time, TVO revealed that “a significant amount of measures [were] taken to prevent the spreading of the coronavirus epidemic (COVID-19) in order to minimize the effects of pandemic risk to the project. The coronavirus pandemic may have significantly added uncertainty to the progress of the project.”119 As a consequence, fuel loading would not take place in June  2020 as planned, and “it is possible that the regular electricity production will be delayed respectively. AREVA-Siemens consortium will update the schedule for OL3  EPR unit as soon as spreading and effects of the coronavirus pandemic are known.”120

   As reported by WNISR2019 (see WNISR2019 Finland Focus), TVO and AREVA-Siemens signed a settlement agreement in March  2018, which states that TVO would receive compensation of €450  million (US$2018549  million) from the supplier consortium. The settlement further includes a penalty mechanism, under which the supplier consortium pays additional penalties to TVO in case of further delays beyond 2019. However, these are capped at €400  million (US$458 million), which were reached in June  2021. With delays beyond June  2021, the agreement does not cover the financial impact on TVO. It was reported in April  2020, that AREVA was making arrangements to secure funding until the end of the project (including the guarantee period).121

   In March 2021, fuel was finally loaded into the OL3 reactor, with grid connection announced in mid-May  2021 for October  2021.122 By the end of July  2021, startup had already been pushed back by another month to November  2021, “due to turbine overhaul”.123

   On 17  May  2021, TVO announced that it had reached a consensus settlement agreement with the Areva−Siemens consortium.124 Negotiations had been underway since summer 2020 on the terms of the OL3 EPR project-completion. Critical to the goal was agreement for an additional €600  million (US$7362021  million) to be made available from the AREVA companies’ trust mechanism as of the beginning of January  2021. Other key issues agreed included that both parties are to cover their own costs from July  2021 until end of February  2022, and that in case the consortium companies do not complete the OL3 EPR project until the end of February  2022, they would pay additional compensation for delays, depending on the date of completion. The deadline was missed once again. Further financial arrangements have not been communicated.

   France Focus

   

   Introduction

   As documented in WNISR2021, 2020 was considered “particularly difficult for the French nuclear sector”, but 2022 is likely to be significantly worse. While nuclear production increased over the previous year, the discovery in December 2021 of cracks in emergency core cooling systems led to the shutdown of the four largest (1,450  MW) and most recent French reactors. The event represented an unexpected loss of close to 6  GW of capacity in the middle of the winter when consumption peaks in France, more than in any other European country, due to about a third of the buildings using direct-resistance electric space heating. Subsequently, it turned out that certain 1300-MW reactors—there are 20  such units—are also showing similar symptoms and, as of mid-2022, 12  reactors are shut down for an unknown period of time due to the problem. To what extent the issue also concerns the 900  MW reactors—32  units—is yet to be seen.

   Inspection techniques providing reliable results are a challenge in itself. Inspections take time and it took until the end of July 2022 for the Nuclear Safety Authority  (ASN) to judge EDF’s inspection strategy “appropriate in the light of the knowledge acquired concerning the phenomenon and the corresponding safety issues”.125 If defaults are detected, it takes time to fabricate replacement parts, and it takes time to do the replacement work. High profile, experienced nuclear welders are rare—there are many more simultaneous challenges for these specialists on the French nuclear fleet, including the construction site of the EPR at Flamanville—and there are significant radiation doses involved in the work that could quickly lead to regulatory exposure limits. As there have been already cases with several cracked piping pieces need to be replaced per reactor, inspection and repair will take time. EDF intends to inspect the entire fleet of 56  reactors only by 2025.

   Following the discovery of the corrosion issue, on 13  January  2022, EDF published a downwards revised forecast for nuclear generation, and the French government announced the same day that it would force EDF to provide its competitors 20  percent more power, at fixed price, than expected—120  TWh instead of 100  TWh—to limit the effect of sky-rocketing market prices for the consumer… and to keep potential voters happy prior to the April  2022 Presidential and June  2022 National Assembly elections. These measures were intended to limit the price increase, especially for companies and communities where regulated electricity rates (capped at 4 percent VAT) are not applied. However, rates will have to catch up in 2023.

   The day following EDF’s announcement of lower production expectations and the government-decided consumer subsidy, the company’s shares plunged by 15  percent, and on 17  January 2022, credit-rating agency Standard  &  Poor’s put EDF on credit watch negative, on the basis that they considered the combined effect of these developments could cut EDF’s 2022 result by €10–13  billion (US$202211.4–14.8  billion).126

   This latest technical issue affecting the French nuclear fleet adds to a series of excessive outages for maintenance, repair, and backfitting cumulating in half or more of the reactors being down most of the time in the first half of the year. In May and June  2022, availability never exceeded half of the installed nuclear capacity and dropped as low as one third. The worst is yet to come when electric space heating pushes up consumption in winter. “The current low production of the French nuclear fleet could prove to be a disaster for France”, a commentator wrote in the economic daily Les  Echos under the headline “Power Cuts: Inform the French!”127

   All of these new problems for an already strained industry did not prevent the French President making a landmark speech on 10  February 2022 hailing a “French nuclear renaissance”. While current legislation stipulates the closure of a dozen reactors until 2035 and the reduction of the nuclear share in the power mix to 50  percent, the President wishes that “six EPR2 be built and that we launch the studies for the construction of eight additional EPR2”.128 For now, the EPR2 does not even exist on the drawing board, no detailed design is available yet. The government administration estimated in October  2021 in an 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 have in the past and do currently—it could take until 2043 to commission the first EPR2, the project review states.129

   The government had asked EDF to “prepare a comprehensive file with the nuclear industry by mid-2021 relating to a programme of renewal of nuclear facilities in France”. EDF has “started to prepare economic and industrial proposals based on the EPR2 technology”.130 However, EDF clearly stated in its annual report 2021 that “No investment decision has yet been taken, and the programme will require appropriate regulation and funding arrangements.”131

   Meanwhile, some estimates put EDF’s expected net debt as high as €65  billion  (US$67.9  billion) at the end of 2022.132 Trade union officials let it be known that the company “might not make it through the year”.133 In early July  2022, the government announced it would fully re-nationalize EDF (it currently holds 84  percent). Following the avalanche of disastrous news over the past few years, EDF’s shares had plunged below €8  (US$8), less than one tenth of the peak in 2007, picked up a bit due to the nationalization announcement and remained just below the advertised takeover offer of €12  (US$12) per share. However, analysts and commentators were quick in arguing that the nationalization would not solve EDF’s problems. As the economic daily Les  Echos put it:

   What it takes to save EDF is a transformation from top to bottom to increase flexibility and efficiency. However, for the past forty years, the State shareholder never demonstrated it was able to transform mammoths into gazelles.134

   After Worst Performance in Decades, Worse is Yet to Come

   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 and for two units in LTO within the period 2015–2017 (see  Figure  23).

   

   Sources: WNISR with IAEA-PRIS, 2022

   No new reactor has started up since Civaux-2 was connected to the French grid in 1999. The first and only PWR closed prior to Fessenheim was the 300  MW Chooz-A reactor, which was retired in 1991. The other closures were eight first generation natural-uranium gas-graphite reactors, two fast breeder reactors and a small prototype heavy water reactor (see  Figure 24).

   In 2021, the 56 operating reactors135 produced 360.7 TWh, a 7.5  percent increase over the previous year, but still below the level of 2019 and the sixth year in a row that generation remained below 400  TWh. In 2005, nuclear generation peaked at 431.2  TWh. 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 25).

   

   Sources: WNISR, with IAEA-PRIS, 2022

   Notes:

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

   

   Sources: RTE, 2000–2022, EDF 2022

   In 2021, nuclear plants provided 69  percent (+1.9  percentage points) of the country’s electricity following the exceptional plunge in 2020, however remaining below the 2019 level. According to RTE, the nuclear share peaked in 2005 at 78.3  percent. The outlook for 2022 is grim. After several downward revisions, as of mid-2022, EDF estimates of the annual production range at 280–300  TWh, a figure not seen since 1990 (see Figure 25 and Figure 26.)

   

   Sources: RTE, 2000–2022, EDF 2022

   Monthly production has continued to deteriorate in 2022 with a lower output in every single month of the first half of the year than in any year over the past decade (see Figure 27).

   Electricity represented 24.5  percent of final energy in France in 2021. As nuclear plants provided 69  percent of electricity, as in 2020, according to provisional numbers, nuclear plants covered 17  percent of final energy in France in 2021. The largest share being covered by fossil fuels with oil at 42  percent and natural gas at 20  percent, while renewables contributed only 11  percent.136

   

   Source: RTE, “Données Mensuelles” and EDF “Nuclear Generation”, 2021–2022

   Nuclear Unavailability Review 2021

   In 2021, there were 5,810  reactor-days, (down 655 days or 10  percent from the 6,465 reactor-days in 2020), an average of 104 days per reactor, when reactors in France were not producing any power, not including load following or other operational situations with reduced capacity but above-zero. The number is still almost 8  percent higher than the average 96  days per reactor compared to the pre-COVID situation of 2019. All 56  reactors were subject to outages ranging 9–272  days (Figure 29 and see  Figure 30).

4. Table 4 – Total Unavailability at French Nuclear Reactors 2019–2021 (in reactor-days)

   	Declared Type of Unavailability
   	“Planned”	Forced	Total	Average per Reactor
   2019	5272.9	315.5	5588.3	96.3
   2020	6179.1	286.2	6465.3	115.4
   2021	5638.6	172.1	5810.8	103.75

   Sources: RTE and EDF REMIT Data, 2019–2022

   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 unavailability analysis for the year 2021 on Figure 28 further shows:

   • On 338 days (92  percent of the year), at least 10  units and up to 23 were down during the same day.
   • On 109 days (30  percent of the year), 19 or more units were shut down for at least part of the day.
   • At least seven reactors were down (zero capacity) simultaneously at any day of the year.
   • At least 20 reactors were offline simultaneously during the equivalent of 32.5 days.

Sources: compiled by WNISR, with RTE and EDF REMIT Data, 2021–2022

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.

According to EDF’s classification of “planned” and “forced” unavailabilities, in 2021,

• 16 reactors did not experience any “forced” outage,
• at seven units “forced” outages lasted less than one day,
• at 30 their cumulated duration represented between one and ten days,
• and only three reactors did fall in the range between 11 and 15.5  days of “forced” outage over the year (see  Figure 29).

Sources: compiled by WNISR, with RTE and EDF REMIT Data, 2021–2022

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”.

WNISR analysis shows a different picture. Of 240 full outages in 2021, 161 were declared “planned” and 79 “forced”. In the case of “forced” outages, a generic duration of one day is first declared in most cases (75  percent) and is then readjusted. The additional duration of “forced” outages represented less than 100  days. For “planned” outages, additional unplanned unavailability represented 1,238 days that EDF nevertheless labeled as “planned”. In fact, almost 25  percent of the full-outage durations were unplanned.

Of 240 full outages, 86 experienced a prolongation exceeding 1  day and up to 156 days (Chooz-2) in 2021137; the cumulated prolongation over the year was over 1,500  days. On the other side, 18  outages were shorter than planned by at least one day; the cumulated reduction over the year was 171  days. (These cases are likely due to outage re-scheduling rather than net savings of outage days.) As a result, the net additional unplanned unavailability added up to 1,330  days, an increase of 30  percent beyond the expected outage durations (see  Figure 30).

Sources: compiled by WNISR, with RTE and EDF REMIT Data, 2021–2022.

Note: This figure represents the cumulated outage duration per reactor as planned at the beginning of the outages and the real durations during the same year (cumulation of planned and forced unavailabilities). In the case of reactors that were shut down in 2020 and planned to restart before 1  January  2021, the entire outage duration in year 2021 is considered outage extension. Extensions into 2022 are not considered.

The categories “Extension” and “Not implemented” represent the cumulation of balances between all planned and real outage durations per reactor. These numbers do not consider cancelled or rescheduled outages that were moved into 2022.

The cumulated outage analysis over the three years 2019–2021 reveals the following (see  Figure 31):

• Three reactors were down half of the time or more (Flamanville-1 and -2, Dampierre-1);
• 23 reactors were generating zero power over 30  percent of the time, that is 108  days and more per year on average.

Sources: compiled by WNISR, with RTE and EDF REMIT Data, 2019–2022

Lifetime Extensions – Fact Before License

By mid-2022, the average age of the 56 nuclear power reactors exceeds 37  years (see  Figure 32). Lifetime extension beyond 40  years—50  operating units are now over 31  years old of which 18 over 41  years—requires significant additional upgrading. Also, relicensing is subject to public inquiries reactor by reactor.

EDF will likely seek lifetime extension beyond the 4th Decennial Safety Review  (VD4) for most, if not all, of its remaining reactors. This is (yet) in line with the Government’s pluriannual energy plan, which does not envisage any further reactor closures until 2023 and only a limited number in the following years. But President Macron in his February  2022 programmatic speech made it clear that the government has no intention anymore of closing reactors and 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”.138

The first reactor to undergo the VD4 was Tricastin-1 in 2019. Bugey-2 and  -4 were scheduled in 2020, and Tricastin-2, Dampierre-1, Bugey-5 and Gravelines-1 in 2021… until the COVID-19 pandemic further disrupted the safety review schedule.

While the President of the Nuclear Safety Authority  (ASN) judged the VD4-premiere on Tricastin-1 “satisfactory”, he questioned whether EDF’s engineering resources were sufficient to carry out similar extensive reviews simultaneously at several sites.139 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 extended by 25  days. Including further, unrelated unavailabilities, the reactor was in full outage during two thirds of that year (232  days).

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. However, as illustrated, many factors could lead to significantly longer outages. EDF, in fact, 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 VD4.140

On 23  February  2021, the ASN issued detailed generic requirements for plant life extension.141 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.142

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, e.g.  many of the post-Fukushima measures have not yet been implemented eleven years after the events. 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 2039.143

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 an example, and it is the most recent operating 900  MW reactor. 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, particularly in the winter 2022–2023.

Sources: WNISR, with IAEA-PRIS, 2022

The public inquiry for the first unit to undergo relicensing, Tricastin-1—first connected to the grid on 31  May  1980—took place in early 2022. Over 1,800  citizens submitted comments. The Inquiry Committee highlighted in its conclusions formulated numerous complaints the lack or inadequacy of documentation, the absence of a planning overview for the backfitting work to be carried out and the limitation of the invitation to participate to the seven municipalities within a 5-km radius from the plant, rather than the 76  towns within the 20  km radius that is the basis for emergency planning. The Committee report also criticizes that while the public understood the inquiry to be about the decision to extend the lifetime of the reactor, the subject of inquiry is a catalogue of technical modifications proposed by EDF as a result of ASN’s requests. None of the Committee members were technically qualified to understand and judge the technicalities involved. The report adds: “Since ASN itself has decided on the provisions even before the public inquiry, the Inquiry Committee wonders how the public’s contribution, the conclusions of the Inquiry Committee and the opinion of the communities concerned will be taken into account...” 144 Remarkably, a majority of the members voted nevertheless in favor of the modifications proposed by EDF.

Embattled Clientele, Financial Trouble, Volatile Market

Operating costs have increased substantially over the past few years (see also previous WNISR editions). The Court of Accounts has calculated the operating costs for the year 2019 at €43.8/MWh (US$201949/MWh) when using an “accounting” methodology and €64.8/MWh  (US$201972.6/MWh) when applying an “economic” approach (taking into account past investments) as chosen by the Court. Lifetime extension would cost “at least €201535  /MWh [€202239/MWh or US$202240/MWh] based on EDF figures”.145

Outages that systematically exceed planned timeframes are particularly costly. EDF’s net financial debt increased by €8  billion  (US$20199  billion) in 2019, grew by another €1.2  billion (US$20201.5  billion) in 2020, and a further €0.7  billion (US$20210.8  billion)—to a total of €43  billion (US$202148.7  billion)—as of the end of 2021.146

EDF has been losing 100,000–200,000 clients per month for several years. As of the end of 2021, EDF’s 51 national competitors—in addition, there are over 100  public local utilities—had captured 36  percent of non-residential customers and 31  percent of the residential clients, representing 44  percent of the national demand. In spite of the huge market price increases, EDF lost an additional 100,000  residential clients and 18,000  non-residential customers in the fourth Quarter 2021.147 On 1  January  2021, EDF lost 300,000  non-residential customers in one go when the regulated tariffs for small commercial users were abolished.148

However, as the sky-rocketing price increases continued into 2022, some consumers returned to EDF’s regulated tariffs that profited from the government-imposed price control mechanism. EDF claims an increase of about half a million clients between September  2021 and May  2022.149 The drawback is that during low nuclear production and excessively high prices on the market, this forces EDF to “buy volumes [of power] at a price that is higher than we [EDF] resell it to the clients at the regulated tariff”, an EDF executive director stated.150

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”.151

In December  2007, EDF started construction on 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. These problems never stopped. In April  2018, it was discovered that the main welds in the secondary steam system did not conform with the technical specifications; so by the end of May  2018 EDF stated that repair work might again cause “a delay of several months to the start-up of the Flamanville  3 European Pressurized Water Reactor  (EPR) reactor.”152

In October 2019, EDF had stated that fuel loading would be delayed to “late 2022” and construction costs re-evaluated at €12.42015  billion (US$201513.9  billion), an increase of €1.52015  billion (US$20151.7) over the previous estimate.153 In addition to the overnight construction costs, as of December  2019, EDF indicated more than €4.2  billion (US$20194.6  billion) was needed for various cost items, including €3  billion (US$20193.3  billion) of financial costs.

By 1  July  2022, the latest provisional date for the startup of the reactor, these additional costs could reach €20156.7  billion (US$20157.4  billion). The latest construction cost estimate given by EDF of €201512.4  billion (US$201513.9  billion) would represent about two thirds of the total thus estimated by the French Court of Accounts at €201519.1  billion (US$202219  billion).154

In 2020, on the basis of the updated cost estimates, the Court states that FL-3 electricity could possibly be generated at €2015110–120/MWh (US$2015123–134/MWh).

All of these numbers do not take into account the COVID-19 effect, and already in July  2020, EDF warned that the several weeks long construction interruption at the Flamanville EPR “could result in further delays and additional costs”.155

In January 2022, EDF estimated the overnight costs at €201512.7  billion (US$201514.2  billion).156

Known technical issues cumulate with new ones. ASN notes in its 2021 Review:

Considerable works and examinations still remain before commissioning of the reactor. This in particular concerns the design and reliability of the primary system valves, repairs to the main secondary system welds, with anomalies on three nozzles of the main primary system and post-weld heat treatment of the nuclear pressure equipment, the performance of the filtration system on a containment internal water tank, and the various anomalies detected on the cores of the Taishan EPR reactors, including the fuel clad ruptures observed in 2021.157

Especially the issue that struck the Taishan EPRs and kept Unit 1 off the grid for over one year—it was eventually restarted in mid-August 2022—has consequences on FL3. EDF has proposed to refabricate 64  of the 241  fuel assemblies that have already been produced for FL3. According to EDF’s plan, certain assembly components would undergo thermal treatment prior to use, others would be replaced by and by on all fuel assemblies. The plan has yet to be assessed by the Institute for Radiation Protection and Nuclear Safety (IRSN) and to be approved by ASN.158

EDF assures that the issue “does not question the design of the EPR”.159

Germany Focus

Introduction

Germany decided immediately after 3/11 to close eight of the oldest160 of its then 17  operating reactors and to progressively phase out the remaining nine by the end of 2022, effectively reactivating a “consensus agreement” negotiated a decade earlier (see Table 5 for the phaseout schedule). This choice was implemented by a conservative, pro-business, and, until the Fukushima disaster, very pro-nuclear Government, led by physicist Chancellor Angela  Merkel. With no political party dissenting, it looked like virtually irreversible under any political constellation. On 6  June  2011, the German Bundestag passed a seven-part energy transition legislation almost by consensus and it came into force on 6  August  2011 (see earlier WNISR editions for details).

A decade later, in September 2021, legislative elections saw the Social Democrats  (SPD) become the strongest political party in Germany. But even in a coalition with the Green Party they would not have had a parliamentary majority, so after complex negotiations, an unprecedented “traffic light” coalition-government was formed by adding the Liberal Democratic Party FDP  (yellow) to the SPD  (red) and Greens.

One year into the legislative period, on 5  September 2022, Robert Habeck, Minister for Economy and Climate Protection and Vice-Chancellor of Germany, presented the results of a second stress test of the electricity system’s resilience for the winter 2022–2023. He announced, he will recommend to the government to transfer two of the three remaining operating nuclear reactors into “reserve status” as of the end of 2022. He made it very clear what it means:

This also means that all three of the nuclear power plants currently still on the grid in Germany will be taken off the grid as planned at the end of 2022. We are sticking to the nuclear phase-out stipulated in the Atomic Energy Act. New fuel elements will not be used, and the deployment reserve will be terminated in mid-April  2023. Nuclear power is and continues to be a high-risk technology, and the highly radioactive waste will be a problem for many future generations. You can’t play around with nuclear power. 161

What happened? Why would the consensus-driven nuclear-phaseout decision even be questioned? Sky-rocketing energy prices in late 2021, the war in Ukraine, and high German dependency on Russian fossil fuel imports (gas, oil, and coal) provided an unexpected opportunity for a few remaining pro-nuclear voices in the country to receive considerable attention. In fact, the discourse of the “German isolated phaseout decision in a world going all nuclear” had entered the main media already in the past few years—the same handful of individuals could publish their pro-nuclear lobbying pieces in top German media like Der  Spiegel, Die Zeit, Focus, and the likes—some prominent journalists took it on, and a few conservative politicians started questioning the phaseout legislation.

The war in Ukraine triggered an astounding public controversy that hardly assessed options based on factual understanding of their respective implications but often consisted of a fact-free opinion debate. Are you for or against lifetime expansions? Never mind legal aspects, technical feasibility, costs, and potential safety implications. A whole series of opinion polls have shown comfortable majorities in favor of stretching the operation of the three remaining reactors by a few months or even up to five years. The public perception linked continued operation of the reactors with the hope for more independence from Russian gas.162 A mirage, as the latest stress test illustrated, since less than 1  percent of gas burnt for power could potentially be saved.

An Unexpected Debate Over Potential Lifetime Extensions

On 7  March  2022, three days after the Russian army attacked and then occupied the Zaporizhzhia nuclear power plant, the German Government issued a 5-page joint statement of the Ministries of Environment and Economy assessing a potential restart of the three reactors that were closed at the end of 2021 and the potential lifetime extension of the remaining three operating reactors beyond the legal closure date of end of 2022:163

• The restart of the three units closed end of 2021 is “out of the question” notably due to the expired operating license.
• The lifetime extension of the still operating units would not lead to additional power generation in the winter 2022/2023, as there is no new fuel available before fall 2023 at the earliest.164
• A lifetime extension of the currently still operating three units beyond the end of 2022 would require an in-depth safety assessment of each of the reactors last carried out in 2009. The outcome and potential backfitting and upgrading work needed cannot be reliably predicted.
• A lifetime extension could not be economically justified for 2–3 years and would not make sense under 3–5  years considering the safety related issues and the need to re-train staff. The two ministries consider that in that timeframe there are other options.
• From a constitutional rights perspective, a lifetime extension would require a comprehensive, new risk-benefit assessment by the legislator. “Against this background, the expected lawsuits against a possible lifetime extension would definitely have promising chances of success.”
• The operators have signaled that a lifetime extension would essentially mean the takeover of legal and economic risks by the state. As the two ministries consider that compromising on safety is not an option, lifetime extension could mean lengthy backfitting programs in the period 2022–2024.
• In conclusion, the two ministries “cannot recommend a lifetime extension of the three still operating nuclear power plants”.

Four days after the government statement and two weeks after Russia launched its all-out war against Ukraine the parliamentary group of the far-right AfD (Alternative für Deutschland/Alternative for Germany) tabled a proposal for a resolution in which the German Bundestag would “call on the Federal Government to implement, together with the Länder Governments a lifetime extension of the nuclear power plants” and “immediately give nuclear power plant operators unambiguous and binding assurances that the nuclear power plants may be operated without restriction until their technically reasonable end of life.”165 The proposal was rejected by all of the parliamentary committees and, on 7  July  2022, received a unanimous rejection by all parliamentary groups from the far left to the Christian democrats. The vote ended 581 to 67, whereas only AfD members and one independent voted for the proposal.

Since then, some remarkable developments occurred, including the following:

• A legal analysis commissioned by Greenpeace concluded on 22  July 2022 that any form of operation of the remaining reactors beyond the end of the year would violate constitutional law, necessitate significant backfitting, and require cross-border consultations under EU-Environmental Impact Assessment legislation and ESPOO Convention.166
• On 26 July  2022, the smallest government coalition partner FDP called for a lifetime extension of all three reactors to 2024, arguing: “This is the period when we face energy shortages. That is why we must be prepared for it.”167

  “Former Environment Minister, Jürgen Trittin stated: ‘If one seriously wanted to change the nuclear law, it will not work without a party congress’”

• On 28  July 2022, five key SPD parliamentarians on energy and climate issues, led by the parliamentary group’s Vice-President Matthias  Miersch, sent a 4-page letter to party members pointing to a comprehensive list of issues highlighting problems around the potential lifetime extension, like the “challenges in times of gas shortages are in the industry and the provision of heat – not in the power sector”; while less suitable than gas plants, coal plants are more suitable to make up for shortages than nuclear plants, as they are more flexible; under regular circumstances, the three nuclear plants would have had to undergo a comprehensive decennial safety inspection in 2019, which they were exempted from considering the anticipated closure in 2022—that safety review would be “mandatory”, could last several years and entail “significant investment needs”; the operators do not want to bear the legal, economic, and safety risks, that would have to be covered by the state.168
• On 29  July  2022, Green MP and former Environment Minister, Jürgen Trittin stated: “If one seriously wanted to change the nuclear law, it will not work without a party congress”.169 Early September  2022, a circulating draft motion for the regular Green Party congress scheduled for October  2022 is calling on the federal party executive board, the parliamentary group, and the federal government “to stick to the 31  December  2022 phaseout date for the last three nuclear power plants in Germany.”170

Between mid-July and early September  2022, the four grid operators in Germany carried out a second stress test on security of supply and stability of the grid for the winter 2022/2023 under significantly more stringent assumptions. The hour-by-hour analysis included the potential contributions or needs of neighboring countries. A sensitivity analysis found the greatest potential impact with the performance of the French nuclear fleet and the water levels of rivers in Germany (in particular for the shipment capacity of coal).

The French Government has assured the German Government, “orally and in writing”, so said Minister Habeck on 5  September  2022, that 50  GW of the installed total of 61  GW of French nuclear capacity would be operational in the winter. Between mid-August and mid-September  2022 (at the time of writing), the available nuclear capacity in France never reached even half of the winter target level and the country continuously depended on power imports, most of it from Germany. Thus, the French assurances seem to be based on highly optimistic assumptions, and the German grid operators have judged it necessary to model scenarios with a French nuclear capacity limited to 45  GW (in Scenario  ++) and 40  GW (in Scenario  +++) respectively.171 The most severe scenario combines the limited nuclear capacity with the assumption of unavailability of half of the reserve capacity (mainly coal) and half of the gas plants in southern Germany.172

The continued generation of the remaining 4  GW of nuclear power would ease capacity constraints and improve grid security to a limited extent. In the median Scenario  ++, capacity needs would be narrowly covered but grid security would only lower redispatch needs (power imports) by 0.5  GW, from 5.1  GW to 4.6  GW.

Under the most severe assumptions in Scenario  +++, capacity would not be covered for a cumulated 3–12  hours (not continuous) in total over the winter, with 7–8  GW and the supply of 17–53  GWh missing. For Europe—Germany has transmission links to 11  European countries—the extreme case would lead to a shortage in a cumulated 91  hours (3.8  days) with a peak of 18–19  GW and 682  GWh short of demand (Germany included).173

According to assumptions under the stress test, the three reactors could generate with their current cores a cumulated total of about 5  TWh beyond year-end, that corresponds to about 52 days if operated at nominal capacity. That appears a lot considering a few hours of load constraints under the most severe assumptions, and not enough to make a major difference over the entire winter. And, of course, considering the legal, technical, safety-related, and political hurdles, there is no guarantee that they would actually generate power.

Minister Habeck concluded from the stress test results that “it remains highly unlikely that we will face a crisis or an extreme scenario”, but due to the cumulation of circumstances, “given all these risks, we cannot rely on our neighbouring countries having enough power stations available to help stabilise our power grid at short notice in the event of grid congestion.”174 Therefore, the ministry decided to propose the creation of a new reserve capacity, limited in time, in the form of the two southern nuclear plants Isar-2 and Neckarwestheim. The two reactors shall “remain available until mid-April 2023 so that they can, if necessary, make an additional contribution to the power grid in southern Germany this winter.”175 It remains to be seen, how Green Party members will appreciate the proposal, and whether the proposal proves practicable.

Certain other countermeasures recommended by the grid operators are already in preparation, including additional production in biogas plants and the increase of transmission capacity and effectiveness. The ministry clarifies that the two nuclear units shall be “deployed only when it seems likely that the other instruments will be insufficient to avert a supply crisis.” The extension beyond mid-April  2023 or the reactivation in the winter 2023/2024 “is not possible due to the safety status of the nuclear power plants and the fundamental considerations about the risks of nuclear power.”176

The idea is to monitor European capacity availability throughout the winter and, should it appear in November or early December  2022 that a severe shortage could appear in January  2023—e.g.  due to lower French nuclear capacity than expected—the two southern reactors would keep operating until their fuel is exhausted. Otherwise, the units would be shut down at year-end as stipulated under the current legislation and restarted only should a crisis situation occur later in the winter. This would not be a stop-and-go kind of operation, but once restarted, the reactors would keep operating until fuel exhaustion. Germany has been a net exporter to France for many years, especially in winter.

Meanwhile, the French government, faced with an unprecedented unavailability level of its own nuclear power fleet (see  France Focus), has called on Germany, in the name of mutual solidarity, to extend the operation of the three remaining reactors “for a few months”, while assuring to upgrade the gas links to Germany in return.177

The organization of two units as “reserve” power plants will not be easy. There is no precedent, and there is no available protocol as for other reserve power plants. What does it mean for staff availability, for continuous inspection and maintenance, insurances, civil liability, etc.?

Following the publication of the stress test results and the conclusions of the Ministry of Economy and Climate Protection, coalition partner FDP reiterated the call for a lifetime expansion at least until 2024. The party leader of the Christian Democrats, Friedrich  Merz, has called the potential closure of the three reactors at year end “completely absurd”.178

Nuclear Power vs. Renewables and Fossil Fuels

Germany’s nuclear fleet generated 65.4  TWh net in 2021, a 7.4  percent increase after a 14  percent decline in 2020, and only a fraction of the peak generation of 162.4  TWh in 2001. Nuclear plants provided 11.9  percent (+0.6  percentage points) of Germany’s electricity generation, compared to the historic maximum of 35.6  percent in 1999, according to data from AGEB.179

Renewables generated 234  TWh (gross), a significant 7-percent-decline over the previous year, mainly due to a particularly weak wind year with onshore generation dropping by close to 15  percent and offshore wind by almost 11  percent. Consequently, the share of renewables dropped below 40  percent again to 39.7  percent of gross national electricity generation. Nevertheless, wind power remains ahead of nuclear power which it has out generated since 2017.180

Figure 33 summarizes the main developments of the German power system between 2010—the last year prior to the post-3/11 closure of the eight oldest nuclear reactors—and 2021.

While the increase in renewables (+128.5  TWh) and the decline in consumption (-47.5  TWh) still overcompensate the decline in fossil fuel (-100.5  TWh) and nuclear generation (-71.5  TWh), all indicators are in retreat compared to 2020.

Sources: WNISR based on AG Energiebilanzen (AGEB), 2022

Within the fossil-fuel generating segment:

• Lignite peaked in 2013 and then declined—especially in 2019–2020—before increasing again by 20.2  percent in 2021. However, lignite generation remained below the 2019-level and 25  percent below the 2010 level.
• Hard coal also peaked in 2013 then dropped to 64  percent below the 2010-level. While it has seen, at 27.7  percent, the strongest increase in 2021 of any power generation technology, it also remains below the 2019 numbers.
• Natural gas fluctuated since 2010 and peaked in 2020 at 2.6  percent above the 2010-level before dropping by 5.3  percent in 2021.

1. Table 5 – Legal Closure Dates for German Nuclear Reactors 2011–2022

   Reactor Name (Type, Net Capacity)	Owner/Operator	First Grid Connection	End of License (latest closure date)
   Biblis-A (PWR, 1167  MW) Biblis-B (PWR, 1240  MW) Brunsbüttel (BWR, 771  MW) Isar-1 (BWR, 878  MW) Krümmel (BWR, 1346 MW) Neckarwestheim-1 (PWR, 785  MW) Philippsburg-1 (BWR, 890  MW) Unterweser (BWR, 1345  MW)	RWE RWE KKW Brunsbüttel(a) PreussenElektra KKW Krümmel(b) EnBW EnBW PreussenElektra	1974 1976 1976 1977 1983 1976 1979 1978	6  August  2011
   Grafenrheinfeld (PWR, 1275  MW)	PreussenElektra	1981	31  December  2015 (closed 27  June  2015)
   Gundremmingen-B (BWR, 1284  MW)	KKW Gundremmingen(c)	1984	31  December  2017
   Philippsburg-2 (PWR, 1402  MW)	EnBW	1984	31  December  2019
   Brokdorf (PWR, 1410  MW) Grohnde (PWR, 1360  MW) Gundremmingen-C (BWR, 1288  MW)	PreussenElektra/Vattenfall(d) PreussenElektra KKW Gundremmingen	1986 1984 1984	31  December  2021
   Isar-2 (PWR, 1410  MW) Emsland (PWR, 1329  MW) Neckarwestheim-2 (PWR, 1310  MW)	PreussenElektra KKW Lippe-Ems(e) EnBW	1988 1988 1989	31  December  2022

   Sources: German Atomic Energy Act/Atomgesetz, 31  July  2011; Atomforum Kernenergie, May  2011; WNISR with IAEA-PRIS, 2022181

   Notes:

   Krümmel and Brunsbüttel were officially closed in 2011 but had not been providing electricity to the grid since 2009 and 2007 respectively

   PWR: Pressurized Water Reactor; BWR: Boiling Water Reactor; KKW: Nuclear Power Plant  (Kernkraftwerk); RWE: Rheinisch-Westfälisches Elektrizitätswerk Power AG; EnBW: Energie  Baden-Württemberg  AG.

   (a) - Vattenfall 66.67%, E.ON 33.33%

   (b) - Vattenfall 50%, E.ON 50%.

   (c) - RWE 75%, E.ON 25%.

   (d) - E.ON 80%, Vattenfall 20%.

   (e) - RWE 87.5%, E.ON 12.5%.

   The provisional half-year results for 2022 show significant changes in the power generation (gross) compared to the same period in the previous year:182

   • Nuclear generation dropped (due the closure of three reactors at year-end) by half and represented only 5.6  percent of national production.
   • Natural gas-based production declined by a further 11.7  percent and covered 14.6  percent (-2.3  percentage points).
   • The share of lignite plants is up by 1.7 percentage points to reach 19.1  percent.
   • Hard coal burning represented 10.2  percent of production, up 2  percentage points.
   • Renewables generated 14  percent more power and gained 4.6  percentage points to contribute 46.4  percent of electricity generation.

   The geopolitical situation provided a strong incentive for the expansion of renewables. But while solar capacity expanded by 3.6  GW in the first half-year 2022—about as much as in the record years 2010–2012—land-based wind energy additions have been modest at 0.9  GW and no offshore capacity was added yet.183

   India Focus

   

   India has 19  operational nuclear power reactors, with a total net generating capacity of 6.3  GW. Even though it is listed as operational by the Nuclear Power Corporation of India  (NPCIL) and placed since July 2022 “in LTS” in the International Atomic Energy Agency’s  (IAEA) Power Reactor Information System (PRIS), the Rajasthan-1 reactor is considered by WNISR to be permanently closed because it has not generated power since 2004.184 Three units fall under the LTO category: Tarapur-1, Tarapur-2, and Madras-1, as these have not generated any electricity in 2021 and in the first half of 2022.

   “The latest reactor to be connected to the grid, Kakrapar-3, has been performing erratically.”

   Eight more reactors, with a combined capacity of 6.0  GW, are under construction. These include four VVER-1000s at Kudankulam, the last of which had first-pour of structural concrete in December  2021. There are also three Pressurized Heavy Water Reactors (PHWR)—including one at Kakrapar (under construction since November  2010) and two at Rajasthan (since July and September  2011)—and a Prototype Fast Breeder Reactor  (PFBR) that has been under construction since October 2004.

   According to the IAEA, nuclear power contributed 39.8  TWh net of electricity in 2021, marginally less than 40.4  TWh in 2020. This represents a share of 3.2  percent of total power generation, compared to 3.3  percent in 2020.185

   The latest reactor to be connected to the grid, Kakrapar-3, has been performing erratically. In November  2021, the NPCIL petitioned the Central Electricity Regulatory Commission to delay the start of commercial operation and requested that the reactor continue to inject “infirm power” into the grid until 9  July  2022.186 As of July  2022, the NPCIL website had not reported any electricity generation from Kakrapar-3. One report suggests that this performance is due to ventilation and cooling problems.187

   Strong Push for Renewables

   BP 2022 statistical review reports 43.9  TWh gross of nuclear electricity in 2021, with a corresponding figure of 171.9  TWh for non-hydro renewables, with wind contributing 68.1  TWh and solar energy contributing 68.3  TWh.188 The figures for 2020 are 44.6  TWh (nuclear energy), 152.0  TWh (non-hydro renewables), 60.4  TWh (wind energy), and 58.7  TWh (solar energy). Thus, nuclear energy has come down slightly since 2020, whereas both wind and solar have grown and are contributing about 150  percent of nuclear power each. (See  Figure 62).

   According to the International Renewable Energy Agency  (IRENA), installed capacity of all renewable energy sources has gone up from 60.5  GW in 2012 to 147.1  GW in 2021.189 Of this, wind and solar energy contribute 40  GW and 49.7  GW respectively; the latter maintains the lead it established over wind energy in 2020.

   Ongoing Construction Experiencing Delays and Cost Overruns

   Of the eight reactor projects under construction, all are delayed or likely to be delayed. In March  2022, the Indian government announced that the “project completion schedule” for the four reactors under construction at Kudankulam are “likely to be impacted” because “the components and equipments to be imported from Ukraine and Russia may be delayed due to the logistical and ocean freight problems” arising from the war on Ukraine.190 An official update from July  2022 reports the anticipated date of commissioning for Kudankulam-3 and  -4 as November  2023, 36  months after the original date of November  2020.191 The November  2023 date apparently represents the commissioning of the Kudankulam-4 unit, as according to the NPCIL website, Unit  3 will be commissioned in March  2023.192 However, already in July  2021, Nuclear Intelligence Weekly reported that “Units  3 and  4 were targeted for commissioning in March and November  2023, but will now be completed in September  2024 and March  2025”.193

   The three PHWRs under construction are also delayed. Unit 4 of Kakrapar was to be commissioned in 2015, while the two Rajasthan units were to be commissioned in late 2016. The above-mentioned official update from July  2022 reports anticipated dates of commissioning of June  2023 for Kakrapar-4 and December  2023 for Rajasthan-7 and Rajasthan-8.194 In April  2022, the Central Electricity Regulatory Commission approved a petition from NPCIL that anticipates Rajasthan-7 being synchronized with the grid only by June  2023.195 According to a power ministry memo from May  2022, completion of Kakrapar-4 appears to have been pushed back to March  2024.196 At the time of writing this, the NPCIL website only says “under review” for the expected dates of commercial operation for Kakrapar-3 and  -4 and Rajasthan-7 and  -8 projects.197

   Finally, as has been the case for some years now, the PFBR is still the most delayed project. The latest “anticipated” date for commissioning the PFBR has been pushed back from October  2022, as reported in the last WNISR, to September  2024.198 When construction started in 2004, the anticipation completion date was September  2010, and that has been pushed back little by little.199

   The projected cost of the PFBR has also risen, from the initially anticipated Rs.34.9  billion200  to Rs.75  billion as of July  2022.201 The Kakrapar project, where Unit  3 has already been commissioned, is now projected to cost Rs.192.2  billion, up from Rs.114.6  billion; the Rajasthan project is now expected to cost Rs.170.8  billion, up from Rs.123.2  billion. Kudankulam-3 and  -4 are still projected to cost Rs.398.5  billion.

   Construction Plans and Reality

   For nearly a decade now, there has been talk about a large number of new PHWRs. Back in 2014, soon after the national elections, the Indian government’s spokesperson announced in the parliament that a number of reactors were to be launched by NPCIL. The wave of construction was to start in 2015 and included two 700  MW PHWRs each in Gorakhpur in Haryana state (GHAVP  1  &  2), Chutka in Madhya Pradhesh state (CMAPP  1  &  2), Mahi Banswara in Rajasthan state (Mahi Banswara  1  &  2), and Kaiga in Karnataka state (Kaiga  5  &  6).202 The envisioned dates for “first pour of concrete” and “completion” were June  2015 and September  2020/March  2021 (for the two Gorakhpur units); June  2015 and December  2020/June  2021 (for the two Chutka units); June  2016 and December  2021/June  2022 (for the two Mahi  Banswara units); and December  2016 and June  2022/December  2022 (for the two Kaiga units). None of those projects started construction by these planned dates.

   Instead, in May 2017, the union cabinet approved the construction of ten more 700  MW PHWRs, at an estimated cost of 1.05 trillion Rupees, and the news was promoted widely by NPCIL as a “mega impetus for nuclear power”.203 In 2018, the list included the units mentioned earlier, but also two additional units at Gorakhpur (GHAVP  3  &  4) and Mahi Banswara (Mahi  Banswara  3  &  4).204 In other words, by that time, 12 new 700  MW units were promised.

   It has been more than five years since that announcement and construction is yet to begin on any of these. The latest update is from March  2022, when Department of Atomic Energy officials reportedly told the science and technology committee of the Indian Parliament that “first concrete for Kaiga units  5 and  6 is expected in 2023, followed by Gorakhpur Haryana Anu Vidyut Praiyonjan units  3 and  4 and Mahi Banswara Rajasthan Atomic Power Projects units 1-4 in 2024 and Chutka Madhya Pradesh units  1 and  2 in 2025”.205

   The status of the first two units at Gorakhpur is ambiguous. The government has repeatedly listed these as “projects under construction”, with the latest such announcement being made in the Indian Parliament on 31  March  2022.206 According to that announcement, GHAVP-1  &  -2 is expected to be complete in 2028. However, there is no evidence that the project’s concrete pour for the base slab of the reactor building has taken place. In March  2022, the Deccan  Herald newspaper reported that “NPCIL… didn’t answer questions on why the construction of…GHAVP-1 and  -2—the first two 700  MW units at Haryana—remained stalled”.207

   The other major element in India’s nuclear plans, ever since the U.S.-India nuclear deal was negotiated between 2005 and 2008, has been to import reactors from the U.S. and France. The 2014-announcement in parliament mentioned above also included envisioned dates for “first pour of concrete” and “completion” for imported reactors: October  2015 and April  2021/April 2022 (for two 1650  MW EPR units from France to be built at Jaitapur in Maharashtra); June  2016 and October  2021/October  2022 (for two 1500  MW ESBWR [Economic Simplified Boiling Water Reactor] units from GE-Hitachi to be built in Kovvada in Andhra Pradesh), and June  2016 and December  2020/December  2021 (for two 1100  MW AP  1000 units from Westinghouse to be built in Chhaya Mithi Virdi in Gujarat).208 However, no project has gone forward. In February  2022, when the government was asked in parliament about any additional capacity as a result of the nuclear deal, it simply stated “discussion[s] to arrive at project proposals (…) are in progress”.209

   Among the foreign vendors, only EDF appears to be making some progress, albeit slow, on a contract. In May  2022, EDF announced that it hopes to seal a deal “in the coming months”.210 But such announcements have been made before. In 2018, EDF reportedly submitted a techno-commercial proposal and there were media reports that construction was to commence “as soon as possible”.211 Two years earlier, in 2016, it was reported that an agreement was “due by year-end”.212 Given EDF’s major cost-escalation experiences with EPR projects in Europe, it is unlikely that they would be able to make an attractive enough offer to offset the major economic disadvantages associated with EPRs in Jaitapur.213

   The other two vendors—Westinghouse and GE-Hitachi—seem to be balking at the idea that they might be held liable for damages in the event of an accident. In September  2021, India’s Foreign Secretary confirmed that talks with Westinghouse are continuing but admitted that some issues, including liability for accidents, are yet to be addressed.214 GE-Hitachi has flatly refused to sell reactors to India because of its concern about liability.215

   In fact, the problem has less to do with the amount vendors would be liable for, which is but a small fraction of the cost of these reactors; rather, these vendors seem to be opposing the principle that they might be asked to compensate victims in the event that their supposedly safe reactors do actually undergo a severe accident.216 Unless India’s parliament undoes the liability provisions, which is unlikely, the possibility of importing reactors from U.S. vendors appears remote.

   None of this is new for India’s nuclear program. Its history has been full of overly ambitious announcements that have never materialized, despite ample financial and political support from parties across the spectrum.217

   Japan Focus

   

   Overview

   In Financial Year 2021 (April 2021–March 2022), the number of “operable” nuclear reactors in Japan remained stable at only ten with a capacity of just under 10  GWe. The average capacity factor has improved from 15.5  percent in FY  2020 to 21.1  percent in FY  2021. As a result, nuclear power generation increased from 38.8  TWh to 67.8  TWh, and its share in total power generation doubled from 3.9  percent to 7.9  percent. The respective numbers for the calendar years are a growth from 43.1  TWh representing a share 5.1  percent in 2020 to 61.3  TWh and 7.2  percent in 2021. (See Figure 34).

   

   Sources: WNISR with IAEA-PRIS, 2022

   As of 25  July  2022, only seven of the ten operable reactors (Takahama-3, Ohi-3  &  -4, Ikata-3, Genkai-4, Sendai-1  &  -2) were actually operating. No new operating license was issued during the past year. A total of 33  units (33.1  GWe) are still officially in “commercial operation” status, out of which 25  units (24.8  GWe) have applied for an operating license, with 17  approved so far, of which 10 have restarted at some point.218

   Eleven years after the Fukushima disaster began, reactors now operating are all PWRs although the Nuclear Regulation Authority  (NRA) confirmed that five BWRs (Kashiwazaki  Kariwa-6 and  -7, Tokai-2, Onagawa-2, and Shimane-2) were meeting the new regulatory requirements set in 2013. Tokyo Electric Power Co.’s  (TEPCO) Kashiwazaki Kariwa units were the first BWRs which received approval from NRA on 27  December  2017. However, due to the lack of approval from Niigata Prefecture and a nuclear security violation in 2021, it is not known when the reactors will restart operating.219 Japan Atomic Power Co’s  (JAPCO) Tokai-2 was the first BWR to get lifetime-extension approval from NRA on 7  November  2018. Actual restart operation has been postponed until 2024 or later because of ongoing work on additional safety measures including the installation of a Specialized Safety Facility  (SFF) against terrorist attacks. Onagawa-2 received approval from NRA on 26  February  2020 but work on additional safety measures will not be completed until November  2023 with power generation thought to resume in February  2024.220 Chugoku Electric Power Co’s Shimane-2 received approval from NRA on 15  September  2021 but negotiations with local governments continued until 2  June  2022 when the Governor of Shimane Prefecture, Tatsuya  Maruyama, agreed to the restart of the unit. It is now expected that Shimane-2 will be reconnected to the grid sometime in 2023.221

   Kansai Electric Power Co (KEPCO) has the largest number of reactors (seven in total, all PWRs) but only three of them (Takahama-3, Ohi-3  and  -4) are currently operating (as of July  2022). Takahama-3 was shut down on 1  March  2022 for periodic inspections when damaged steam generator tubes were identified, and restart of operation was postponed. It was reported that Takahama-3 finally started operation on 24  July  2022, after damages were repaired.222 For both Ohi-3  and  -4, the deadline for completion of the SSF against terrorist attacks is 24  August  2022. They received the construction permit for SSFs in August  2021, but while Ohi-4 will likely meet the deadline, it is not the case for Ohi-3. Therefore, it is expected that Ohi-3 will need to be shut down after 24  August  2022 and restart 18  December  2022.223 Although there was an unprecedented court decision not to start operation of Ohi-3 and  -4 in December  2020,224 Kansai Electric Power immediately appealed the upper court and thus they were allowed to operate the reactors at least until the final ruling is made.225

   Shikoku Electric Power’s Ikata-3 restarted operation on 2  December  2021, after an outage of close to two years. The unit had been taken offline in December  2019 to undergo refueling and maintenance, when it met with a series of incidents in January 2020, the first involving control rods during spent fuel removal, another one a brief loss of power.226 In January  2021, Hiroshima High Court decided not to allow the restart of Ikata-3, but later overturned its ruling in March  2021227 and then denied the injunction appeal on 4  November  2021 (see legal cases section). Ikata-3 did not restart immediately, however, due to delays in SSF construction and a safety violation incident (an emergency operator illegally left his position without permission). The SSF was finally completed in October  2021, and the reactor was allowed to restart on 6  December  2021, resuming commercial operation on 24  January  2022.228

   

   Sources: Various, compiled by WNISR, 2022

   Kyushu Electric Power Co’s Genkai-3 was shut down in January 2022, and the operator will not meet the deadline of SSF construction of 24  August  2022. The unit is expected to restart in January  2023. Genkai-4 was shut down on 30  April  2022 for regular inspection and restarted on 13  July  2022.229 But again due to delays in construction of SSF whose deadline is 13  September  2022, it will be taken off the grid again then. It is currently expected to restart in February 2023.230 Sendai-1 and  -2 were shut down for inspection in October  2021 and 13  June  2022 respectively. Unit  1 restarted on 20  December  2021, Unit  2 on 13  June  2022 and both remain online as of July  2022.231 Both units, 39 and 37  years old respectively, are preparing for license extension beyond 40  years.

   No additional reactors have been declared for permanent closure during the past year,232 thus the total remains unchanged at 27  reactors (21 reactors after the Fukushima accident, including the ten at Fukushima Daiichi  &  Daini). (See Figure 35 and Table 6).

   Legal Cases Against the Restart of Existing Reactors

   Like the year 2020–2021, the year since mid-2021 witnessed significant rulings from courts across Japan that underscore the continuing uncertainties for future reactor operation, as well as highlighting some of the underlying safety issues that remain unresolved. The following cases do not include the important decisions on the Fukushima disaster that are discussed in the Fukushima Status Report.

   “The plant does not have adequate protection against a tsunami.”

   The court decision made by the Sapporo District Court on Hokkaido Electric Power Co.’s Tomari nuclear plant on 31  May  2022, was probably the most important one made in the past year. It is a somewhat unusual case as the safety licensing process is still underway, and typically legal challenges are launched against licensing decisions made by the NRA. The case was filed in November  2011 by over 1,000 plaintiffs  against Hokkaido Electric Power  Co. The Sapporo District Court ruled that the utility company should not resume operation of all three reactors at its Tomari nuclear plant in Hokkaido but rejected the request to decommission the plant. The reactors were all shut down for regular inspections by May  2012, and the utility was applying for a license to restart the units by meeting the new regulatory requirements made by the NRA. The presiding judge Tetsuya  Taniguchi said that the power company had “not provided evidence of the safety of spent nuclear fuel stored at the plant and the plant does not have adequate protection against a tsunami”, ruling that 44 of the plaintiffs who live within a 30-km radius would be seriously affected by a severe accident “and have their human rights hindered”. The Hokkaido utility said that it will appeal the case.233

   Two other cases resulted in injunctions against operating nuclear power plants being rejected. On 4  November  2021, the Hiroshima district court ruled against injunctions on the Ikata nuclear power plant.234 The court ruled that the evidence provided by the plaintiffs over the risk of an accident caused by potential earthquakes were not sufficient. The only unit that has not been permanently shut down is Unit  3, which resumed commercial operation in January  2022. On 10  March  2022, the Nagoya regional court ruled against plaintiffs requesting an injunction against Kansai Electric Power Co’s  (KEPCO) Takahama nuclear plant.235 On 9  March  2016, the Otsu district court had issued an injunction against the operation of Takahama-3 and  -4, but the Osaka Hight Court lifted the injunction on 28  March  2017.236 (see dedicated section in WNISR2021).

   The Kashiwazaki Kariwa Safety/Security Affair

   A serious breach of nuclear security regulations occurred in 2020 at Kashiwazaki  Kariwa plant in Niigata Prefecture. The unauthorized entry by employees into the central control room and inadequate management of security related equipment which detect intrusion of outsiders resulted in NRA’s decision to prohibit TEPCO to load fresh nuclear fuel at the plant in April  2021.237 (See detailed account in WNISR2021.) On 27  April  2022, NRA published its interim report on the Kashiwazaki  Kariwa security issue in which they investigated enhanced nuclear security measures taken by TEPCO and made a series of recommendations to be implemented by the operator.238

   On 25  July  2022, an independent Expert Commission on the Assessment of Nuclear Security submitted its first report to TEPCO.239 The Commission was appointed by TEPCO to evaluate nuclear security measures at their facilities in December  2021. This is one of the measures which TEPCO promised to take in its own assessment report submitted to NRA on 22  September  2021.240 The report concluded that improvement of security measures is steadily progressing, but it noted that in May  2021 employees received an expired site access badge. Isao Itabashi, director of the Research Center for Public Policy Investigation Committee and the chair of the Expert Commission, said, “The improvement is progressing, but there are many points to be strengthened. It is necessary to continue the investigation until the culture of nuclear security is rooted company-wide.” The Commission is expected to continue its investigation and make reports and recommendations semi-annually.241

   Reactor Closures and Spent Fuel Management

   No additional reactors were formally declared for decommissioning in the year to 7  July  2022. The 11  commercial Japanese reactors now confirmed to be decommissioned—not including the Monju Fast Breeder Reactor  (FBR) or the ten Fukushima reactors—had a total generating capacity of 6.4  GW, representing about 15  percent of Japan’s operating nuclear capacity as of March  2011.242 Together with the ten Fukushima units, the total rises to 21  reactors and 15.2  GW or just under 35  percent of nuclear capacity prior to 3/11 that has now been permanently removed from operations (see  Figure 35 and Table 6).

   Regarding spent fuel from research reactors—such as Fugen, a 165  MWe Advanced Thermal Reactor or ATR, that first reached criticality in 1978 and was closed in 2003, and Monju, a 280  MWe  FBR, that first reached criticality in 1994, was connected to the grid in August  1995 and produced its last electricity in December  1995 but was officially closed only in 2017—Japan’s basic policy is still the reprocessing of all spent fuels from those reactors. Although, there are no specific plans to use the separated plutonium.

   By 22  April  2022, all spent fuel from Monju had been moved to a temporary storage tank filled with liquid sodium and transfer to a pool storage cooled with water was scheduled to start “after June”. Japan Atomic Energy Agency  (JAEA), which manages decommissioning work of Monju, plans to complete the spent fuel transfer by the end of the year, start the extraction of the liquid sodium in 2023, and then, eventually, ship all spent fuels to France for reprocessing. Shipment is expected to be completed in 2037.243

2. Table 6 – Official Reactor Closures Post-3/11 in Japan (as of 1  July  2022)

   Operator	Reactor	Capacity MW	Startup Year	Closure Announcement(a) dd/mm/yy	Official Closure Date(b) dd/mm/yy	Last Production	Age(c)
   TEPCO	Fukushima Daiichi-1 (BWR)	439	1970	-	19/04/12	2011	40
   	Fukushima Daiichi-2 (BWR)	760	1973	-	19/04/12	2011	37
   	Fukushima Daiichi-3 (BWR)	760	1974	-	19/04/12	2011	36
   	Fukushima Daiichi-4 (BWR)	760	1978	-	19/04/12	2011	33
   	Fukushima Daiichi-5 (BWR)	760	1977	19/12/13	31/01/14	2011	34
   	Fukushima Daiichi-6 (BWR)	1  067	1979	19/12/13	31/01/14	2011	32
   	Fukushima Daini-1 (BWR)	1  067	1981	31/07/19	30/09/19	2011	30
   	Fukushima Daini-2 (BWR)	1  067	1983	31/07/19	30/09/19	2011	28
   	Fukushima Daini-3 (BWR)	1  067	1984	31/07/19	30/09/19	2011	26
   	Fukushima Daini-4 (BWR)	1  067	1986	31/07/19	30/09/19	2011	24
   KEPCO	Mihama-1 (PWR)	320	1970	17/03/15	27/04/15	2010	40
   	Mihama-2 (PWR)	470	1972	17/03/15	27/04/15	2011	40
   	Ohi-1 (PWR)	1  120	1977	22/12/17	01/03/18	2011	34
   	Ohi-2 (PWR)	1  120	1978	22/12/17	01/03/18	2011	33
   KYUSHU	Genkai-1 (PWR)	529	1975	18/03/15	27/04/15	2011	37
   	Genkai-2 (PWR)	529	1980	13/02/19	13/02/13	2011	31
   SHIKOKU	Ikata-1 (PWR)	538	1977	25/03/16	10/05/16	2011	35
   	Ikata- 2 (PWR)	538	1981	27/03/18(d)	27/03/18	2012	30
   JAEA	Monju (FBR)	246	1995	12/2016(e)	05/12/17	LTS(f) since 1995	-
   JAPC	Tsuruga -1 (BWR)	340	1969	17/03/15	27/04/15	2011	41
   CHUGOKU	Shimane-1 (PWR)	439	1974	18/03/15	30/04/15	2010	37
   TOHOKU	Onagawa-1 (BWR)	498	1983	25/10/18	21/12/18(g)	2011	27
   TOTAL: 22 Reactors /15.5 Gwe

   Sources: JAIF, Japan Nuclear Safety Institute, compiled by WNISR, 2011–2022

   Notes

   BWR:  Boiling Water Reactor; PWR:  Pressurized Water Reactor; FBR:  Fast Breeder Reactor; LTS:  Long-Term Shutdown.

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

   (a)  –  Unless otherwise specified, all announcement dates from Japan Nuclear Safety Institute, “Licensing status for the Japanese nuclear facilities”,  26  February  2020, see  http://www.genanshin.jp/english/facility/map/, accessed 27  July  2020.

   (b)  –  Unless otherwise specified, all closure dates from individual reactors’ page via JAIF, “NPPs in Japan”, Japan Atomic Industrial Forum,
   see  http://www.jaif.or.jp/en/npps-in-japan/, as of 27  July  2020.

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

   (d) –  WNN, “Shikoku decides to retire Ikata 2”, 27  April  2018,
   see  http://www.world-nuclear-news.org/C-Shikoku-decides-to-retire-Ikata-2-2703184.html, accessed 22  July  2018.

   (e)  –  The Mainichi, “Japan decides to scrap trouble-plagued Monju prototype reactor”, 21  December  2016,
   see  http://mainichi.jp/english/articles/20161221/p2g/00m/0dm/050000c, accessed 21  December  2016.

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

   (g) – Date from IAEA-PRIS. (No official closure date in according to JAIF).

   On 24  June  2022, it was reported that JAEA had negotiated a contract with French nuclear fuel company Orano for the transport and reprocessing of all spent fuel (731 fuel assemblies) from Fugen. JAEA originally gave a contract to Orano in November  2018 to carry out preparatory work for shipment of the Fugen spent fuel to France. Under the new contract, which is reported to be worth €250  million (US$2022268  million), Orano will also be in charge of MOX fabrication and the reuse of separated Japanese plutonium in French reactors for power generation. Therefore, separated plutonium from reprocessing will not return to Japan, while wastes generated from reprocessing will be shipped back. This is the first such contract in which separated plutonium, which officially is considered an important energy resource in Japan, will not be returned to Japan. It is likely that JAEA will pay Orano for keeping the plutonium as the material usually has a zero-book-value and a negative market value.

   Orano is also responsible for design and fabrication of transport casks, and the execution of shipments, which are scheduled to take place between 2023 and 2026.244

   As of mid-2022, the Japanese nuclear fleet of 33  units, including 23  in LTO, had reached a mean age of 31.4  years, with 17  units over 31  years (see  Figure 36).

   

   Sources: WNISR with IAEA-PRIS, 2022

   Energy Policy and the Role of Nuclear Energy

   Japan’s latest Strategic Energy Plan (SEP), also called the Basic Energy Plan, was published in October  2021.245 The biggest difference from the previous Strategic Energy Plan published in July  2018246 is the introduction of a new policy goal of “carbon neutrality by 2050”. It naturally emphasizes the importance of renewable energy sources, but utilization of nuclear power is included as an option to achieve the goal. However, the basic policy of “reducing its dependence on nuclear power as much as possible” remains unchanged, and there is no explicit mentioning of building new nuclear power plants.

   Here are some important quotes concerning nuclear targets from the Strategic Energy Plan of 2021:247

   We will address maximum introduction of renewable energy as major power sources on the top priority….and necessary amount of nuclear power will be continuously utilized on the major premise of ensuring safety and public trust. (...)

   Restart of operation with safety as top priority: launch of restart acceleration task force; bringing human resources and knowledges together; and maintaining and improving technological capability.

   Measures for spent nuclear fuel: promotion of construction/utilization of interim storage facilities and dry storage facilities, etc. to increase storage capacity; and technology development for reducing the volume and harmfulness of radioactive waste.

   Nuclear fuel cycle: makes efforts towards the completion and operation of Rokkasho Reprocessing Plant by public and private partnership obtaining understanding of relevant municipalities involved and international society; and further promotion of plutonium-thermal (MOX [Mixed Oxide] fueled) power generation.

   (...) development of fast reactor will be steadily promoted by utilizing international cooperation;248 small modular reactor [SMR] technology will be demonstrated through international cooperation, and component technologies related to hydrogen production at high temperature gas-cooled reactor will be established, as well as R&D [Research and Development] of nuclear fusion will be promoted through international collaboration as ITER Project, etc.

   The targeted share of nuclear power by 2030 remains the same as in the previous plan, that is 20–22  percent of total power generation, while the target for the renewable energy share has been increased to 36–38  percent compared with 22–24  percent in the previous plan. The target shares for various fossil fuels were lowered compared to the previous plan: for LNG from 27  percent to 20  percent, and for coal from 26  percent to 19  percent.249

   Impact of Ukraine Crisis on Nuclear Power Debate

   The impact of the Ukraine crisis on the debate about energy and nuclear policy in Japan has been quite significant. Japan has a significant reliance on LNG, including about 9  percent from Russia (in 2021).250

   Russian attacks against civilian nuclear facilities, including Chernobyl and Zaporizhzhia nuclear power plants, raised serious safety and security concerns over Japanese nuclear facilities. On 8  March  2022, the Governor of Fukui  Prefecture, which hosts 15  reactors, met with Defense Minister Nobuo  Kishi and asked for tighter defense over nuclear facilities in the prefecture requesting to deploy the Self-Defense Forces in the region where a large number of nuclear plants are located.251

   On 30  March  2022, the National Governors’ Association issued an emergency request to the government which includes the following points:252

   • The government should deter such military attack and invasion of other countries’ territories through diplomatic channels;
   • order nuclear utilities to shut down all nuclear reactors when such military attacks are imminent; and
   • in case missile attacks against nuclear power plants are imminent, take all necessary measures, including missile defense by Self-Defense Forces.

   Other pre-eminent policy issues are higher electricity prices as well as possible power shortages in Japan. Due to higher fossil fuel prices, even prior to the price rises caused by the Ukrainian crisis, Japan’s spot power price rose to more than double the five-year average. According to the Japan Electricity Power Exchange, the average wholesale day-ahead price was JP¥15.47/kWh (US$0.11/kWh) on 18  April  2022, up 26  percent over the previous week.253

   On 22  March  2022, METI and TEPCO warned of a possible power outage in the areas serviced by TEPCO and Tohoku Electric Power Co, potentially affecting around 2–3  million households, as some power plants remained offline following a powerful earthquake in the Tohoku area and lower than expected power savings. Later, METI reported nevertheless that significant decline in power consumption helped to avoid a power outage.254 On 26  June  2022, METI again warned that the power supply situation would be very tight in the area of Tokyo, asking for energy conservation by citizens and industry.255 And on 30  June  2022, the Government still maintained power shortage advisory for the fourth straight day as severe summer heat conditions continued.256

   Although it is not clear that restarting nuclear power would help the tight energy situation better than other options, public opinion gradually shifted in favor of restarting idled nuclear power plants. According to Jiji  Press polling released on 21 July  2022, 48.4  percent of the 2,000 respondents were in favor of restarting reactors whose safety has been confirmed while 27.9  percent of respondents were opposed to restarts.257 The shift was documented in further surveys carried out by media outlets since the beginning of the war in Ukraine, as in March  2022, Nikkei reported that more than half of respondents supported a restart of the reactors  (53  percent), and in June Mainichi Shimbun found that 47  percent of respondents were in favor of a restart and 30  percent opposed it, in early 2018 the same survey showed only 32  percent in favor and 48  percent against.258

   Given this background, Prime Minister Kishida announced on 14  July  2022, that he had asked METI to have up to nine nuclear reactors operational this winter.259 Although METI has no legal power to push NRA to accelerate the licensing process, some see this as a sign of the Japanese government’s commitment to counter power shortage as well as to regain the role of nuclear power in carbon neutrality policy. On August 24, 2022, Prime Minister Kishida, in his speech at the GX (Green Transformation) Council, stated that the government should consider building a new generation of nuclear reactor.260 Although this has been interpreted as a “new phase” of Japan’s nuclear energy policy, PM Kishida confirmed again at the press conference on 31  August  2022, that the policy of “reducing dependence on nuclear power as much as possible” remained unchanged.261

   Prospects for Nuclear Power

   Given the tight power supply situations and higher electricity prices, the argument for the restart of existing reactors may have some positive impacts on public opinion, at least in short term. Due to the declining economic competitiveness of nuclear power, longer term prospects for nuclear power are still highly uncertain. Carbon neutrality policy may encourage nuclear power further, but the unfavorable environment surrounding nuclear power will not change dramatically.

   In addition, many difficult issues facing the nuclear industry stem from the legacy of the Fukushima disaster. Notably, decommissioning of the Fukushima reactors and compensation issues are the most important matters that will not be resolved for a long time. Furthermore, spent fuel and waste disposal issues remain unsolved. A brighter future for nuclear power in Japan is not on the horizon.

   South Korea Focus

   

   The Republic of Korea (South Korea) operates 24 reactors and has three reactors under construction. Hanbit-4 is in Long-Term Outage  (LTO) because it has been shut down since May 2017 mainly due to 140  voids found in concrete containment walls and corrosion on containment liner plates.

   President Yoon Suk-yeol, who took the office in May 2022, scrapped the nuclear phaseout policy by the previous Moon Jae-in administration (2017–2022). In August  2022, the incoming Yoon administration disclosed the first draft of the “Basic Plan for Long-term Electricity Supply and Demand” (BPE) which aims to increase the share of nuclear in power generation at the expense of slowing down the increase of renewables.

   South Korea’s nuclear fleet, owned by Korea Hydro & Nuclear Power (KHNP), is located at the Hanbit, Hanul, Kori and Wolsong sites. The average number of reactors per site in South  Korea is the highest in the world. Kori with seven  reactors at the site and 7,489  MW is the world’s largest nuclear power plant.

   According to the Korean Statistical Information Service (KOSIS), nuclear power provided 158  TWh (gross) in 2021, slightly less than the 160  TWh in 2020, providing 27.5  percent of the electricity, versus 29  percent in 2020.262 (See Table 7).

   South Korea Abandons Nuclear Phaseout Policy

   As mentioned in the South Korea Focus in WNISR2021, the future of South Korean energy policy, especially regarding the role of nuclear power generation for the coming years, was likely to be determined by the outcome of the March  2022 presidential election.

   The newly elected President, Yoon Suk-yeol, from the conservative People Power Party (PPP) said during the electoral campaign that he would make South Korea the strongest nuclear power country. Even before he became President, Yoon had been very critical of the nuclear phaseout policy implemented by President  Moon. In fact, it was one of the reasons why he resigned as Prosecutor General appointed by President  Moon and became a politician.

   The nuclear power policy has been one of the major issues of political confrontation between the liberal Democratic Party of Korea  (DPK) and the conservative People Power Party  (PPP) since 2017 when President Moon Jae-in was elected with a pledge to phase out nuclear power.

   The establishment of the nuclear phaseout policy in 2017 was supported by the majority of the population. After the Fukushima accident in 2011, a series of events occurred in South  Korea pushed political leaders to support the phaseout of nuclear power. Such events include the complete station blackout of the Kori-1 reactor in 2012,263 a series of nuclear corruption scandals over safety in 2012 and 2013, local referendum victories against new nuclear projects in Samcheok and Yeongdeok in 2014 and 2015 respectively.264 The alarming Gyeongju earthquake not far from nuclear power plants in 2016 also raised a serious concern about the safety of nuclear reactors in South Korea.265 (See previous WNISR editions for additional information on these events.)

   Therefore, it was not surprising that four out of the five major candidates — Moon  Jae-in, Yoo  Seung-min, Ahn  Cheol-soo and Sim  Sang-jung — in the 2017 presidential election all agreed on no more nuclear power plant construction. However, the positions of the major candidates on nuclear power in the 2022 election changed.

   The Justice Party’s candidate, Sim, was unchanged, with a clear aim to reach a nuclear phaseout by 2040. The ruling Democratic Party of Korea’s candidate, Lee  Jae-myung, promised to continue Moon’s long-term nuclear phaseout policy. The People’s Party’s candidate, Ahn  Cheol-soo, changed from his nuclear phaseout position in 2017 and promised to discard the policy. Lastly, the People Power Party’s candidate, Yoon, pledged to scrap the nuclear phaseout strategy.

   President Moon’s nuclear phaseout policy consisted of continuing the reactors already under construction but not building new ones and guaranteeing defined lifetimes of existing nuclear reactors. The nuclear reactors (APR1400) under construction in South Korea usually get operational licenses for 60  years from the start.

   Therefore, under Moon’s policy, even if it was called a nuclear “phaseout” policy, the total installed nuclear capacity was increased in Moon’s term and the complete phaseout was scheduled to be seen in 2085 when Shin-Kori  6, currently under construction, is to reach the end of its 60-year lifetime. Compared to other nations, for instance, Germany, which aims to phase out nuclear by 2022, and Taiwan, which plans to phase it out by 2025, the Korean phaseout plan was very slow and more like a “program limitation” policy.

   Even if South Korea had continued Moon’s phaseout policy, nuclear power would still have played a role towards the goal of carbon neutrality by 2050, because the total nuclear installed capacity then would have been 11,400 megawatts with nine operating reactors.

   Moon’s nuclear phaseout policy was reflected in several administrative plans, but it was not legislated. Therefore, the policy was easily overturned following the regime change after the 2022 presidential election.

   As President Yoon led the investigation on the earlier-than-scheduled closure of Wolsong-1 when he was the head of the Prosecutor’s Office, the prosecution under the Yoon administration continues the investigation on Wolsong 1. For instance, on 19 August 2022, the Presidential Archives were raided by prosecutors who investigate possible illegalities in the Moon administration’s decision in 2019 to close an aging nuclear reactor ahead of its legal expiration date.

   The Yoon administration aims to extend the lifetime of the existing reactors. Under current regulations, KHNP needs to submit a Periodic Safety Review within two to five years prior to the operating license expiration to apply for a lifetime extension. The current administration plans to modify these conditions and increase the application lead time to five to ten years to facilitate lifetime extensions under the current legislative period. If such an amendment is implemented, the number of reactors which the Yoon administration can extend within its term (2022–2027) increases from 10 to 18  reactors, among which six  reactors whose lifetime would be extended for a second time.266

   The Yoon administration also aims to start to build at least two more reactors, Shin-Hanul-3 and  -4. These two reactors are expected to be completed in 2032 and 2033 respectively.267 If the construction was completed prior to the closure of the first reactors, Hanul would become the world’s largest and densest nuclear power plant, with a 11,500  MW capacity and ten reactors located at one site. For comparison, the total installed capacity of Europe’s largest nuclear power plant, Zaporizhzhia site in Ukraine, is 5,700  MW with six reactors.

   It is not clear yet whether the new government will also revive the plan of building six  reactors at Samcheok and Yeongdeok which was cancelled by the preceding administration.

   A recent public survey shows that President Yoon’s overall job approval rating around his 100  days in office was 32.9  percent and when it comes to Yoon’s discarding of South  Korea’s nuclear phaseout policy, 47.5  percent of the respondents favored the option “the nuclear phaseout policy needs to continue”, 37.8  percent answered “the nuclear phaseout policy needs to be scrapped”, and the remaining 14.7  percent chose “don’t know”.268

   The Ministry of Industry, Trade and Energy (MOTIE) under the Yoon  administration unveiled the draft of the 10th Basic Plan for Long-term Electricity Supply and Demand (BPE, 2022–2036) in August  2022.269 The plan increases the share of nuclear in the future electricity mix, aiming for 33  percent by 2030, compared to 24  percent under the plans of the Moon administration. (See Table  8). With the increase of nuclear power in the draft plan, the share of fossil fuels (coal and LNG) barely changes, while the share of new and renewable energy  (NRE) decreases significantly, a surprising strategic orientation in these times of climate emergency.

   In June  2022, President  Yoon and his administration already pledged KRW1,000  billion (US$725  million) in investments for the industry by 2025.270 The current administration also means to allocate KRW400  billion (US$2022309  million) for the development of SMRs.271

3. Table 7 – 2021 Electricity Mix in South Korea

   	Nuclear	Coal	LNG	NRE	Other	Total
   Production (TWh)	158.0	198.0	168.3	43.1	9.4	576.7
   Share of Electricty	27.4%	34.3%	29.2%	7.5%	1.6%	100%

   Source: KOSIS (KOrean Statistical Information Service), 2022

4. Table 8 – Projections of 2030 Electricity Mix in South Korea according to Different Plans

   Plan	Production  / Share of Electricity	Nuclear	Coal	LNG	NRE(a)	Zero Carbon(b)	Other	Total
   9th BPE (2020) Moon Administration	TWh	146.4	175.1	136.6	121.7	-	6.0	585.8
   	Share	25.0%	29.9%	23.3%	20.8%	-	1.0%	100%
   New NDC (2021) under Moon Admin.	TWh	146.4	133.2	119.5	185.2	22.1	6.0	612.4
   	Share	23.9%	21.8%	19.5%	30.2%	3.6	1.0%	100%
   10th BPE(c) (2022) Yoon Administration	TWh	201.7	130.3	128.2	132.3	13.9	8.6	615.0
   	Share	32.8%	21.2%	20.9%	21.5%	2.3%	1.3%	100%

   Sources: MOTIE 2020272, CNC 2021273, MOTIE 2022274

   Notes:

   BPE=Basic Plan for Long-term Electricity Supply and Demand; NDC=Nationally Determined Contributions (under the Paris Agreement)

   (a) - New and Renewable Energy (NRE). New energy in South Korea includes IGCC and fuel cell

   (b) - Zero carbon sources include hydrogen and ammonia

   (c) - Based on the first draft disclosed on 30 August 2022 by the MOTIE and scheduled to be finalized by the end of 2022.

   Even though South Korea has the lowest renewables share in the electricity mix amongst OECD member countries,275 the Yoon administration intends to still lower the ambitions on renewables and increase the share of nuclear with over 40  percent of electricity still coming from fossil fuels in 2030.

   At the completion ceremony of the first nuclear reactor in Korea, Kori-1, in 1978, President Park  Chung-hee said that since Korea had become one of the nuclear power countries, it was also time to “put more effort into developing new energies such as solar, wind and geothermal”. More than 40  years have passed since 1978.

   Reactor Construction

   All three reactors under construction—Shin-Hanul-2 and Shin-Kori-5 and  -6—are APR-1400 design. Construction of Shin-Hanul-2 launched in June  2013 has been nearly completed, but startup dates have been pushed back several times. More recently, Unit  2 was expected to enter commercial operation in May  2022,276 which did not happen and is now expected in 2023.277 Ongoing issues at Unit  1 cast further uncertainty on the operation timeline at Unit  2.

   The Nuclear Safety and Security Commission (NSSC) conditionally approved issuance of an operating license for Shin-Hanul-1 on 9  July  2021, almost 10 years after the issuance of the construction license in December  2011. It took the NSSC 79  months to come to a decision following KHNP’s application in December  2014, a record as the longest licensing procedure in the history of Korean nuclear regulation. The delay of the issuance of operating license for Shin-Hanul-1 was mainly due to safety concerns including passive autocatalytic recombiner  (PAR) destined to remove hydrogen from the reactor containment in certain accident scenarios, and possible aircraft risk issues. Therefore, the approval was made with four specific technical conditions attached.278

   Shin-Hanul-1 reached first criticality on 22 May 2022 and first grid connection on 9  June  2022. However, these were done before KHNP successfully completed the PAR test and submitted their final report to the regulator. In fact, NSSC changed the conditions of the operating license of Shin-Hanul-1 on 11  August  2022. As of early September 2022, it is uncertain whether Shin-Hanul-1 will start commercial operation in 2022 and the outcome of various reviews will also affect the issuance of an operating license for Shin-Hanul-2.

   Two other reactors, Shin Kori-5 and -6, have been under construction since April  2017 and September  2018 respectively and were planned to be completed in March  2023 and June  2024 respectively.279 However, in March  2021, KHNP applied for an extension of the construction license, with a completion schedule for Shin  Kori-5 now extended one additional year until 31  March  2024, and for Shin  Kori-6, nine months later to 31  March  2025.280

   Permanent Closure

   There have been only two reactors, Kori-1 and Wolsong-1, closed in Korea. Ten additional reactors totaling 8,450  MW will reach the end of their operating license before 2030. These reactors are Kori-2 to be closed in 2023, Kori-3 in 2024, Kori-4 and Hanbit-1 in 2025, Hanbit-2 and Wolsong-2 in 2026, Hanul-1 and Wolsong-3 in 2027, Hanul-2 in 2028 and finally Wolsong-4 in 2029. The Yoon administration will likely try to extend the operating license of all of these reactors starting with Kori-2 in 2022. Opposition to the government plans starts organizing, and a local civil society group in Busan where Kori-2 is located organized a press conference on 25 August 2022, claiming a shutdown of Kori-2 at the expiry of its current license.281 It is possible that the lifetime extensions will not go through as easily as the new administration hopes, considering safety concerns and economic implications, as well as lack of public acceptance.

   Radiation Leakage at Wolsong NPP

   On 10 January 2021, a Korean media exposed that groundwater near storage tanks of the Wolsong  nuclear plant contained levels of tritium exceeding legal limits. According to a report written in 2020 by Korea Hydro  &  Nuclear Power (KHNP), tritium was discovered in groundwater near the storage tanks for spent fuel rods. The report said that the amounts found in the water in 2020 were as high as 13.2  times the safety standard.282 In response to public concern on the leakage, NSSC formed a civil investigation team for the scientific assessment of the tritium issue at the Wolsong  plant.

   Greenpeace East Asia Seoul Office and Ulsan Federation for Environmental Movements (KFEM Ulsan) on 7  March  2022 announced a criminal complaint against KHNP for environmental damage to the site of the Wolsong  nuclear power plant and requested a public-interest audit on NSSC, KINS and KHNP, claiming that the long-term leakage of radioactive substances would represent a serious scandal that saw numerous safety management failures cumulate.283

   On 4 May 2022, the civil investigation team published the “Progress of the second-phase investigation on the tritium at the Wolsong NPP and future plans”,284 a follow-up of the “Progress of the first-phase investigation and future plan” presented on 10  September  2021.285

   The report contained a staggering admission:

   In April  2019, tritium of the maximum concentration of 713,000  Bq/L was detected in the stagnant water in the manhole of the turbine gallery of the Wolsong Unit  3, and tritium of 28,200  Bq/L, in the observation well, WS-2, in May  2019.

   The indicated tritium contamination values represent 19 and 475 times the limit of 1,500  Bq per liter set by the Japanese authorities prior to the planned discharge of contaminated water generated by the Fukushima disaster (see Fukushima Status Report).

   Taiwan Focus

   

   Taiwan has three operating reactors at Kuosheng (Guosheng) and Maanshan, all owned by the Taiwan Power Company (Taipower), the state-owned utility monopoly. The latest reactor to close was the BWR Kuosheng-1 (or Guosheng), on 1  July  2021.286 Accordingly, in 2021, nuclear generation dropped by 11.6  percent to 26.8  TWh, compared to 30.3  TWh in 2020, contributing 10.8  percent to the country’s electricity production in 2021, compared to 12.7  percent the previous year. Nuclear generation reached its maximum share of 41  percent in 1988.

   Following the January  2020 re-election of President Tsai  Ing-wen of the Democratic Progressive Party  (DPP), the nuclear-phaseout and energy-transition policy enacted in the first term, remains the official strategy.287

   During the previous term, citizens voted in a 2018-referendum to remove the amendment to the Electricity Act which made the 2025-phaseout deadline legally binding. The paragraph was withdrawn, but the government’s commitment to the policy remains intact, thus Kuosheng-1 was the third Taiwanese reactor to be closed under the current government’s nuclear phaseout plan and another milestone in the island’s energy transition.

   The opposition Chinese Nationalist Party  (KMT) continues to reject President  Tsai’s energy policy, calling for a life extension of existing reactors and the construction of new plants, and points to renewed international interest in nuclear power and to the technology’s inclusion in the EU’s sustainability taxonomy.288 Pro-nuclear lobbying experienced a major setback in December  2021, when a referendum rejected a proposal to resume construction of two reactors at the Lungmen Nuclear Power Plant.289 The vote was significant as it showed the population’s support for current government policy but, whatever the outcome, it would have remained rather symbolic. Considering the dire state of the Lungmen project, it is indeed unlikely that a favorable outcome would have translated into policy changes or any concrete action ultimately leading to operation of the plant (see The Lungmen Saga.)

   As part of an ongoing reform, the government announced in May  2022 that it was working on replacing the current regulator, the Atomic Energy Commission  (AEC), with an independent nuclear regulator, the Nuclear Safety Commission. The new commission will be tasked to oversee and implement waste management, which will be a major challenge in the coming decades due to the scheduled closure of the remaining nuclear fleet by 2025 and ensuing decommissioning activities.290 The authority was to be set up about a decade ago,291 and an organizational act was passed in early  2013 as part of restructuring ministerial affiliations292, yet, as of July  2022, the AEC was still exercising regulatory oversight in Taiwan.

   Reactor Closures

   As reported in previous editions, Taipower announced the closure of Chinshan-1 on 5  December  2018, while Chinshan-2 has remained shut down from June  2017 but was officially closed on 15  July  2019, when its 40-year operating license expired.

   On 1 July 2021, Taipower announced that due to a lack of spent fuel storage capacity, Kuosheng Unit  1 had been permanently shut down, which was six months earlier than planned.293 The closure of Kuosheng-1 was originally scheduled for 27  December  2021 when its operating license expired. Nuclear fuel was 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 allow it to extend operations until higher-consumption month of June 2021.294

   The reactor, which is located on the northern coast of Taiwan, approximately 22  km northeast of Taipei  City, was a 985  MW BWR/6 unit supplied by General Electric  (GE) and was connected to the grid on 21  May  1981. In its last full year of operation in 2020, it generated 7.4  TWh of electricity and about 4  TWh over the six months it operated in 2021.295

   Local opposition in Taiwan prevented the construction of additional spent fuel dry storage capacity and is one reason for the early closure of Kuosheng-1. Taipower undertook the installation of high-density spent fuel storage racks  (HDFSRs) in the early 1990’s at Kuosheng and retrofitting work for even higher density in 2005.296 In April–June  2017, racks initially intended for Lungmen-2 were installed to expand capacity for two 18-months cycles.297

   Kuosheng-2 is planned for closure on 15 March 2023, and Maanshan’s two PWRs on 26  July  2024 and 17  May  2025 respectively. In line with the official policy and current regulation, the application for the closure of the Maanshan plant was submitted in July  2021.298

   The Lungmen Saga

   A referendum was to be held on 28  August  2021 that included an attempt at overturning the current nuclear phaseout policy, by asking voters to approve the construction restart of two ABWRs at the Lungmen Nuclear Power Plant. Due to the COVID-19 pandemic, the vote was postponed to December  2021 and resulted in the rejection of the proposal by a 5.7  percent margin (47.2  percent in favor, 52.8  percent against).299

   According to the AEC, as of the end of March 2014, Lungmen-1 was 97.7  percent complete,300 while Lungmen-2 was 91  percent complete. The plant was by then estimated to have cost NT$300  billion  (US$20149.9  billion).301 After multiple delays, rising costs, and large-scale public and political opposition, including through local referendums, on 28  April  2014, then Premier Jiang  Yi-huah announced that Lungmen-1 will be mothballed after the completion of safety checks while work on Unit  2 at the site was also to be stopped. In December  2014, it was announced that the project was put on hold for three years.302 It never resumed.

   There was little prospect that the units would ever operate even with a different referendum outcome, considering that resumption would have required Taiwan’s legislature and AEC approval, which was not going to happen given the current government was reelected with the promise to end nuclear power generation by 2025. Taipower has long considered a completion of the project “neither feasible nor desirable”.303

   Beyond industrial or political will, a plethora of obstacles compromised the realism of such undertaking. First, new licensing processes and a new environmental impact assessment would have been necessary as the initial construction permit expired at the end of 2020, this would have required additional geological surveys since a seismic fault running two  kilometers beneath both reactors was identified in 2014.304

   Even if the seismic fault was proven inactive, numerous further technical challenges would still have to be overcome. As Taipower explained in February 2019 that it would not be able to simply replace major components installed nearly 20  years ago, including instrumentation and control, as well as full-scale renegotiation with the main supplier General Electric  (GE).305 Taipower stated at the time that it could take at least 6–7  years to complete construction if all of these obstacles were to be overcome, that is without accounting for the negotiation process with GE whose original project team no longer exists.306 In 2021, the AEC Chairman cited a “10  years or more” timeline until grid connection of both units.307

   Moreover, in November  2021, the government revealed previously confidential documentation from 2015 showing the extent of unresolved safety-relevant technical issues that would impact the project should it be relaunched. The documents were unearthed during an investigation launched in summer  2019 by the government’s supervisory and auditory branch, the Control Yuan, into the rationale behind two settlement payments issued by Taipower to GE. 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 the request of GE over cessation of payment by Taipower. A second ruling by ICC resulted in a settlement agreement between the two companies, amounting to a third of the US$66  million that GE was demanding (which Taipower said it agreed to in order to minimize compensation payment and avoid further legal fees).

   Compliance with safety specifications had long been subject to contradicting assertions, including from the former-Minister of Economic Affairs, Chang Chia-chu, who declared in 2014, that Unit  1 was cleared for hot-testing based on a task-force report he commissioned. The result of this “confidence-building” exercise initiated by GE and a nuclear engineer from Bechtel (who later became a prominent critic of the project) did not involve AEC findings yet was used by the Minister to legitimize the process citing it as evidence and was still used prior to the December  2021 referendum. One of the Commissioners stated at the launch of the investigation in 2019, that sanctions could be considered either against Taipower executives or individual ministry officials, depending “on the evidence”.308

   The probe scrutinized counterclaims filed by Taipower with the International Court of Arbitration in 2015, alleging a “wide range of system design shortcomings and noncompliance with specifications of its [GE’s] ...ABWR.”309 GE was cleared at the time by blaming the suspension of the project for its shortcomings—an explanation the company maintains to this day. Nevertheless, documents revealed by the inquiry showed that 23 out of the 43  counterclaims remained unresolved—including some relating to emergency core cooling, and radiation monitoring—casting further doubt on costs and delay until hypothetical operation of the facility.310 Further findings revealed that out of 187  preoperational system-function test-reports at Lungmen-1, the AEC only approved 155, leaving 32  unresolved. Evidently, the regulator had not cleared the unit for operation. No sanctions have been announced, but the summary conclusions of the investigation state that Minister Chang’s July  2014-claims had “no legal standing” yet “created the mistaken understanding among a part of society that the report meant that the nuclear power plant was safe.”311

   While the opposition labeled the findings “irrelevant” repeating past declarations that Lungmen-1 had been cleared for testing, voters were more affected by the revelations. A 2019-poll illustrated the impact of cost and delays on public opinion by revealing that a majority of the population supported the project at the time, but support fell from 54  percent to just 44  percent, while opposition rose from 33  percent to 42  percent, once individual respondents were presented with estimates that placed costs of resuming construction at NT$50  billion (US$20221.7  billion) over five years.312 According to some polls, a slight majority of voters were favorable to the project until November  2021.313

   WNISR took the units off the construction listing in 2014, where they remain as of 1  July  2021. The IAEA kept listing the Lungmen reactors as under construction at least until June  2019,314 however, as of 2022 they were no longer listed.315

   Energy and Climate Policy

   Historical public opposition to nuclear power in Taiwan dramatically escalated during and in the months following the beginning of the Fukushima Daiichi disaster which has been a principal driver of the nation’s ambitious plans for a renewable energy transition. The “New Energy Policy Vision”, announced by the administration in summer 2016, aims at establishing “a low carbon, sustainable, stable, high-quality and economically efficient energy system” through an energy transition and energy industry reform.316 On 12  January  2017, the Electricity Act Amendment completed and passed its third reading in the legislature, setting in place Taiwan’s energy transition, including the nuclear phaseout.317 The law also gives priority to distributed renewable energy generation by which its generators will be given preferential rates, and small generators will be exempt from having to prepare operating reserves.

   The closure of Kuosheng-1 in July  2021 prior to summer peak electricity demand has led some to question the merits of the government’s energy policy;318 however, a Taipower official stated that the loss of the reactor would not impact power supply margins as the company had “anticipated the shutdown for several months and Taipower has controlled for this”, through the commissioning of a new 500-MW combined cycle gas turbine  (CCGT) and 500  MW of new solar PV installations.319 There were nevertheless reports about blackouts in August  2021 but the exact causes remain unclear.320

   President Tsai in October 2020 called for Taiwan to become a leading center of green energy in the Asia-Pacific region.321 The island’s potential for offshore wind is very high, and in 2021, the Global Wind Energy Council estimated Taiwan’s offshore wind technical potential to be as high as 494  GW. 322 Between 2021 and 2025, Taiwan aims to add 5.7  GW of offshore wind capacity to the grid. In 2020, the government’s position was that an additional 10  GW of offshore wind will be added to the grid between 2026–2035.323 In May  2021, this was increased to 15  GW, thus corresponding to the deployment of 1.5  GW per year over the decade.324

   However, in the shorter term, after stagnating in 2020, offshore wind capacity grew by only 109  MW in 2021, reaching 237  MW, and bringing total installed wind capacity to just 1  GW325 delivering 2.2  TWh (gross) over the year.326 Three wind farms with a combined capacity of 1  GW are to come online in 2022.327

   Meanwhile, Solar  PV deployment has proven more effective, 1.9  GW were installed in 2021 bringing the total to 7.7  GW (compared to 0.1  GW in 2011), 328 and according to BP, these provided about 7.9  TWh, a 30.4  percent increase from 6.1  TWh in 2020. Current targets for 2025 place solar capacity at 20  GW and combined renewable energy capacity at 25  percent of the power mix.329 In 2021, non-hydro renewables provided a combined 2.4  percent of primary energy consumption and 4.2  percent of generated electricity, corresponding to 12.1  TWh, compared to 10.4  TWh in 2020 and 3.4  TWh in 2012. Taiwan was ranked thirtieth in the Renewable Energy Country Attractiveness Index  2021.330

   Despite being blocked from joining the Paris Agreement and COP negotiations, the Taiwanese Government, in April  2021, unilaterally pledged to achieve Net-Zero by 2050 and announced drafting regulations to that end as well as the accelerated implementation of existing targets.331

   As of 2021, the island remains heavily dependent on energy imports—with over 97  percent of imported primary energy that year332—and is the ninth biggest fossil fuel consumer per capita in the world, according to S&P Global calculations. In 2021, coal still dominated electricity generation with a 44  percent contribution, followed by a 37  percent share from natural gas.333 The government’s strategy—summarized by MOEA as “Promote Green Energy, Increase Nature Gas, Reduce Coal-fired, Achieve Nuclear-free”—would see natural gas consumption increase substantially, and provide 50  percent of gross electricity production by 2025.334 Such reliance on gas requires a very stable supply, which in the light of unfolding geopolitical changes is a high risk strategy.

   In March 2022, Taiwan’s National Development Council unveiled its “Pathway to Net-Zero Emissions in 2050”, an updated strategy to pursue the transition more aggressively through a wide range of measures. The strategy is based on a NT$900 billion (US$30.2 billion) budget to 2030, of which NT$210.7 billion (~US$7.1 billion) are allocated to “renewables and hydrogen”, and a further NT$207.8 billion (~US$7 billion) are to be invested in “grid and energy storage”. The plan provides for 40 GW of combined wind and solar capacity by 2030, and by 2050, renewables are to represent 60–70 percent of the country’s energy mix, representing an installed capacity of 40–80 GW in solar and 40–55 GW of offshore wind alone335.

   The reform of the electricity market is continuing with the second stage during 2019–2025 to include grid unbundling, the restructuring of Taipower into a holding company with two entities: a power generation corporation and a transmission and distribution corporation; and the separation of the accounting system for these planned within two years and complete separation within six to nine years336.

   United Kingdom Focus

   

   As of mid-2022, the United Kingdom operated 11  reactors, following the closure of the two reactors at Hunterston in November  2021 and January  2022, and two units at Dungeness  closed in June  2021. In total, 34  nuclear reactors have been closed in the U.K., the second largest number of any country behind the U.S. This includes all 26  Magnox reactors, two fast breeders, one small unit at Sellafield and five Advanced Gas Reactors  (AGRs).

   

   Source: WNISR with IAEA-PRIS and EDF Energy, 2022

   Type of Reactors:

   AGR:  Advanced Gas Reactors; FBR:  Fast Breeder Reactor; PWR:  Pressurized Water Reactor; SGHWR:  Steam Generating Heavy Water Reactor

   In 2021, nuclear plants generated 42  TWh, on the decline for the sixth year in a row, representing 14.8  percent of electricity, down from a maximum share of 26.9  percent in 1997.

   The electricity mix in the U.K. has changed rapidly over the past decades as can be seen in Figure 38. The most significant trend has been the rapid increase in the use of renewable energy—from 2.5  percent at the turn of the century to 39.6  percent in 2021—the rapid demise in the use of coal—from 39.2  percent in 2012 to 2.1  percent one decade later—and the relatively more gradual decline in the generation of electricity from nuclear power. The closure of all the Magnox reactors and now the often-extended outages and closure of some of the AGRs has resulted in nuclear generation decreasing from 64  TWh in 2017 to 42  TWh in 2021.

   

   Source: U.K. Government, DUKES 2022337

   While Great Britain—including England, Scotland, and Wales, but not Northern Ireland—has left the EU  Internal Energy Market as a consequence of Brexit, electricity trade continues with EU member states. In fact, electricity trade is increasing as new interconectors become operational. In 2021, a new connection was made with Norway, the North Sea Link, a 1.4  GW ~720  km cable338, which follows on the back of new interconnectors to France in 2020 and to Belgium in 2019. In total, there are now seven cables with a total capacity of 7.4  GW,339 and while these allow power to flow both ways, the British market is increasingly a net importer: 24  TWh in 2021 compared to 19  TWh in 2018,340 although this may change in 2022, due to the low production in France (see France Focus).

   EDF  Energy, a wholly owned subsidiary of French state-controlled utility EDF, is the majority owner of the company Lake Acquisitions that owns the operating nuclear reactors. Centrica has a minority share (20  percent) in Lake Acquisitions. Centrica reported an adjusted operating loss in nuclear operations of £38  million  (US$202151.3  million) in 2021, up from £17  million (US$202023  million) in 2020, and compared to a profit of £19  million (US$201925  million) in 2019, as unplanned outages resulted in having to buy power from the market to fulfill hedge341, electricity sold in advance.342 Given the higher power prices in 2022, EDF Energy may make significant profits this year, although the early closure of a number of reactors may dampen these.

   Closure of the Advanced Gas-cooled Reactors  (AGRs)

   For several years EDF has tried to coax additional operation out of its aging AGR fleet through extensive maintenance and backfitting during extended outages.

   Managing reactors as they age—the U.K. fleet age exceeds 37  years now (see Figure 39) is a constant problem for any technology design, and the AGRs are no exception. In recent years, issues with the core’s graphite moderator bricks have raised concerns. Keyway Root Cracks  (KWRC) were unexpectedly found at the Hunterston  B reactors in 2016. This can lead to the degradation of the keying system, a vital component which houses the fuel, the control rods, and the coolant  (CO₂). Their cracking or distortion could impact the insertion of the control rods or the flow of the coolant. There are also issues of erosion of the graphite, and a number of the AGRs are close to the erosion limits that the Office for Nuclear Regulation  (ONR) has set. ONR has said “most of the AGRs will have their life limited by the progression of cracking”, as replacing the graphite bricks is impossible.343

   “The situation had dramatically changed with EDF officially closing Dungeness  B-1 and  -2 in June  2021, Hunterston  B in January  2022.”

   Beside the small unit at Windscale, 14  AGRs were built (see Figure 37) operating at seven stations and despite increasing concerns all reactors were said to be in service at the start of 2021 although Hunterston  B and Hinkley  Point  B had generated little electricity in the previous two years, and Dungeness  B none since 2018. Until mid-2021, 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 dramatically changed with EDF officially closing Dungeness  B-1 and  -2 in June  2021, Hunterston  B in January  2022, and with Hinkley  Point  B scheduled for closure in July  2022. Furthermore, Hartlepool and Heysham  A are due to close in 2024 and even the closure of the last two units (Torness and Heysham  B), previously due in 2030, was brought forward to 2028.344 (See Table 9)

5.   Table 9 – Status of U.K. EDF AGR Nuclear Reactor Fleet (as of 1  July  2022)

   Reactor	Net Capacity (MW)	Grid Connection	Closure/ Expected Closure
   Dungeness B-1 Dungeness B-2	545 545	03/04/1983 29/12/1985	Closed Last power in 2018
   Hartlepool A-1 Hartlepool A-2	590 595	01/08/1983 31/10/1984	March 2024
   Heysham A-1 Heysham A-2	485 575	09/07/1983 11/10/1984	March 2024
   Heysham B-1 Heysham B-2	620 620	12/07/1988 11/11/1988	March  2028 March  2028
   Hinkley Point B-1 Hinkley Point B-2	485 480	30/10/1976 05/02/1976	July 2022
   Hunterston B-1 Hunterston B-2	490 495	06/02/1976 31/03/1977	Closed 2021 Closed January  2022
   Torness-1 Torness-2	595 605	25/05/1988 03/02/1989	March  2028 March  2028

   Sources: EDF Energy, 2022

   The decommissioning cost estimates for the AGRs have continued to rise and according to the Parliament’s Public Accounts Committee, costs “have almost doubled since March 2004, estimated at £23.5  billion [US$202132.7  billion]  in March  2021, and there remains a significant risk that the costs could rise further”. Furthermore, despite having already provided £10.7  billion [US$202213  billion] (from a total value of the funds of £14.8 billion [US$202120.3  billion]), the Government was committed to “top up the Fund with taxpayers’ money, providing an injection of capital of £5.1  billion  [US$20206.9] in 2020–21 with a further £5.6  billion [US$20227  billion]  expected in 2021–22”.345

   

   Sources: WNISR, with IAEA-PRIS, 2022

   Pathways to Net Zero

   The U.K. has set one of the most ambitious greenhouse gas emissions targets in the world, committing to a 68  percent reduction from 1990 levels by 2030 and 78  percent by 2035346 compared to a 50  percent reduction achieved in 2020.347 The U.K. Government has also committed to a zero-emission power sector by 2035.348

   “Renewables are cheaper than alternative forms of power generation in the UK and can be deployed at scale to meet increased electricity demand in 2050.”

   In June 2019, the Parliament set in law a commitment to reach net zero carbon emissions by 2050 and as part of this process six select committees jointly agreed to establish a citizens’ assembly on climate change and how the Net Zero Target could be met. Special attention was to be given to the findings of the citizens’ assembly as “it is unique: a body whose composition mirrors that of the U.K. population.”349

   The citizens’ assembly found

   • three main disadvantages to nuclear: “its cost, safety, and issues around waste storage and decommissioning”.
   • Support for nuclear power was second lowest to the use of fossil fuels with Carbon Capture and Storage  (CCS), with 34  percent of the assembly agreeing or strongly agreeing that it should be part of how the U.K. generates electricity, compared to 78  percent for onshore wind, 95  percent for offshore wind and 81  percent for solar.350

   The Climate Change Committee, an independent body established to advise the Government on meeting its climate commitments has produced a report in 2019 on how the U.K. can meet its Net Zero commitments. Three out of five of the Committee’s energy scenarios featured just 5  GW of nuclear capacity by 2050, equating to completing Hinkley  Point  C and life-extending Sizewell  B for 2035–2055. The remaining two scenarios featured 10  GW of nuclear capacity. The Committee concluded:351

   Renewables are cheaper than alternative forms of power generation in the UK and can be deployed at scale to meet increased electricity demand in 2050 - we therefore consider deep decarbonisation of electricity to be a Core measure. (...)

   Reducing emissions towards net-zero will require continued deployment of renewables and possibly nuclear power and other low-carbon sources such as carbon capture and storage and hydrogen, along with avoiding emissions by improving energy efficiency or reducing demand. [Emphasis added.]

   The Committee is clearly recognizing the economic and deployment advantages of renewables over nuclear power as the country moves toward a zero emissions economy.

   In November 2020, the U.K. Government published a Ten-Point Plan for a Green Industrial Revolution, which included a specific point on, “Delivering New and Advanced Nuclear Power”.352 This put forward milestones for the sector, including:

   • 2021: Launch of Phase 2 of U.K. SMR design development;
   • Mid 2020s: Hinkley Point C  (HPC) comes online;
   • Early 2030s: First SMRs and Advanced Modular Reactor (AMR) demonstrator deployed in the U.K.

   Then in December 2020, the Government published a long-awaited Energy White Paper. In this they stated that their aim was to “bring at least one largescale 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”.353 In an accompanying press statement the Government said it would begin negotiations with EDF on Sizewell  C.354 However, the approval has a requirement for a “value-for-money” hurdle to be passed, which given the current economics of nuclear vs. renewables is likely to be difficult. Then U.K. minister for Investment Lord Gerry Grimstone told the Financial Times at the time “If you read the energy white paper before Christmas it’s by no means certain that this country is going to be building large nuclear power stations”.355

   The U.K. has failed in the area of energy efficiency, which is all the more surprising as it is the one measure that can rapidly and cheaply address energy security, climate change, and affordability simultaneously. Domestic buildings are the largest user of natural gas and account for 20  percent of greenhouse gas emissions, however, inadequate progress has been made on energy efficiency.

   In January 2021, the U.K. Government proposed that all new homes be “zero carbon ready” by 2025, meaning they should emit 75–80  percent less carbon than those built to the current standards introduced in 2013. But this is just the latest target for new buildings, and when part of the EU, the U.K. Government signed up, through the Energy Performance of Buildings Directive, required all new buildings to be “Nearly Zero Energy” by 31  December  2020,356 and before that in 2006 the Government announced that by 2016 all new homes would be “net energy buildings”.357 In 2007, energy analyst Walt  Patterson published an article for Chatham House which highlighted the importance of energy efficiency, specially for foreign policy, which stated:

   Forget fighting wars to protect oil and gas supplies, worry less about unsavoury leaders who extract a price for access to these precious products. Instead, order some loft insulation for homes, offices and especially government buildings.358

   If this advice had been followed, the U.K. would likely today be in a very different place, one with affordable household heating and far greater energy independence. That is true, of course, not only for the U.K.

   Security of Supply

   As with many other countries, especially those in Europe, the invasion of Ukraine by Russia in February  2022 and the subsequent spike in energy prices led the Government to announce that it would review its energy policy and particularly around energy security. However, the U.K. is in a markedly different position to the Member States of the EU, in that it is not highly dependent on Russia for its fuel, that, in 2021, supplied just 4  percent of the natural gas consumed, 9  percent of its oil, and 27  percent of its coal.359 This is a result of domestic production, although this is decreasing, and in the case of gas of the far greater use gas from Norway and the Netherlands and of Liquified Natural Gas  (LNG), as well as increasing renewable energy deployment.

   In April  2022, the Government published its revised strategy360 which was met with howls of derision from many interested parties.361 As well as the failure to prioritize demand side measures, given the policy’s stated purpose to increase supply diversity away from dependency on Russian fuels, it is remarkable that the policy has chosen to ignore measures that can be introduced most rapidly. The document does not set any further target for onshore wind and goes further saying that it “will not introduce wholesale changes to current planning regulations for onshore wind”, the very regime that slowed its deployment. Then on solar, while it looks more promising on the surface, as it says “we expect a five-fold increase [in capacity] by 2035”, there is little indication of how such an increase would be achieved. The ruling party, the Conservatives, given their support mainly in rural areas, are particularly sensitive to local planning concerns and have therefore used the policy to shore up their chances of re-election.

   Offshore wind does get more direct encouragement by setting a specific target of 50  GW by 2030—including 5  GW of new floating wind—up from 14  GW. The Government proposes to support this by reducing the planning and development time by 50  percent. However, the Government chose to highlight its ‘big bet’ on nuclear power as the cornerstone of the new policy, with then Prime Minister, Boris  Johnson saying “we’re embracing the safe, clean, affordable new generation of nuclear reactors, taking the UK back to pre-eminence in a field where we once led the world”.362

   Furthermore, the Government said in April  2022 that “A new government body, Great British Nuclear, will be set up immediately to bring forward new projects, backed by substantial funding,” and it would “launch the £120  million [US$2021161.5  million] Future Nuclear Enabling Fund this month”.363 The nuclear fund had previously been announced in the spending review of October  2021364 and was ultimately launched in May  2022.365 To the great deception of the industry, there was no new commitment of government funding. “I was expecting this to be bad, but not as bad as it was”, one industry source told Nuclear Intelligence Weekly.366

   The main details of the “new” plan367 were:

   • To increase the deployment of nuclear power of up to 24 GW of capacity by 2050.
   • To take a project to the final investment decision in this parliament, by 2024 (Sizewell  C), which has already been announced.
   • Two further projects, including SMRs, in the next Parliament (scheduled for between January 2025–2029).

   Four nuclear projects in total by 2030:

   • Initiate the selection process in 2023 for further U.K. projects, with the intention that Government will enter negotiations with the most credible projects to enable a potential government award of support as soon as possible, including (but not limited to) the Wylfa site. However, as with existing policy, “any projects would be subject to a value for money assessment, all relevant approvals and future spending reviews”.
   • In contrast to other onshore technologies, the Government has said it will “work with the regulators to understand the potential for any streamlining or removing of duplication from the consenting and licensing of new nuclear power stations”.
   • The Government will “develop an overall siting strategy for the long term” targeted at eight designated nuclear sites: Hinkley, Sizewell, Heysham, Hartlepool, Bradwell, Wylfa, Oldbury, and Moorside.

     Nuclear Newbuild

   As noted, the U.K. has one power plant with two reactors under construction at Hinkley  Point  C and one project with two units awaiting a final investment decision at Sizewell  C. Both projects use the EPR design. Formally the development of a new reactor at Bradwell, continues, based on the Hualong  One design, although geopolitical concerns are likely to slow or cancel the project due to engagement of Chinese partners.

   More definitive action was taken by the Government in 2022, and in its spending review of 2021, it was announced that £1.7  billion (US$20212.29  billion) were being made available “to enable a final investment decision for a large-scale nuclear project in this Parliament” and that “the government remains in active negotiations with EDF over the Sizewell C project.” In addition, the Government was making available £385  million (US$2021518  million) towards advanced nuclear R&D; and £120  million (US$2021161.5  million) for a new Future Nuclear Enabling Fund to address barriers to entry.368

   Hinkley Point C

   EDF Energy was given planning permission to build two reactors at Hinkley  Point in April  2013. In October  2015, EDF and the U.K. Government369 announced updates to the October  2013 provisional agreement of commercial terms of the deal for the £16  billion (US$19.5  billion) overnight cost of construction of Hinkley  Point  C  (HPC).370 The estimated cost of construction has since risen at the following times:

   • In 2017, it stood at £201519.6  billion (US$201525.3  billion), up from the £201518.1  billion (US$201523.2  billion)— EDF said at the time that the £1.5  billion (US$1.9  billion) increase results mainly “from a better understanding of the design adapted to the requirements of the British regulators, the volume and sequencing of work on site and the gradual implementation of supplier contracts.”371
   • In November  2019, EDF announced a further increase in costs due to “challenging ground conditions”, “revised action plan targets” and “extra costs needed to implement the completed functional design”, with the new completion cost (in 2015 values) now being estimated between £21.5  billion (US$26.6  billion) and £22.5  billion (US$27.9  billion). Furthermore, it was stated that the risk of delay had increased and that such a delay would increase costs by £0.7  billion (US$0.9  billion) over and above these estimates, so the upper end of the range was £23.2  billion (US$28.8  billion).372 EDF stated that “management of the project remains mobilised to begin generating power from Unit  1 at the end of 2025”, which does not appear to be a clear statement of confidence in the then current schedule.373
   • In its annual financial statement, published 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$201532.6–34.1  billion), a rise of £0.5  billion (US$0.7  billion).374
   • Less than three months later, in May  2022, EDF then announced that cost estimates had further risen by £20153  billion (US$20154.4  billion), to between £201525–26  billion  (US$201537–38.5  billion) and that its startup would be delayed by an additional year to June  2027.375

   The critical points of the HPC deal were a Contract for Difference  (CfD), effectively a guaranteed real electricity price for 35  years, which, depending on the number of units ultimately built, would be £201289.50–92.50/MWh (US$2022133.7–139.8/MWh), with annual increases linked to the Retail Price Index.376 In early 2020, EDF broke down the £92.50/MWh (US$2022133.7/MWh) strike price saying that £19.5  (US$202223.7) would go toward operating and maintenance costs, and only £11 (US$202213.4) to standard construction costs, excluding financing. The remaining £62 (US$202275.4) covers risk, with £26  (US$202231.6) for financing costs for typical regulated asset without construction risk and £36  (US$202243.8) to cover first-of-a-kind construction risk.377

   There was an expectation that construction would be primarily funded by debt (borrowing) backed by U.K.  sovereign loan guarantees, expected to be up to about £17  billion (US$26.9  billion), but the loan guarantees were never taken up.378 EDF announced in October  2015 its intention to sell non-core assets worth up to €10  billion (US$11.4  billion) over five years to help finance HPC and other capital-intensive projects.379

   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 has impacted upon the amount EDF has to pay. Since 2013, the cost of EDF’s expected share of the project has gone up by about 150  percent380 and significantly contributed to its large debt load.381 The HPC cost overruns were part of credit-rating agency Standard & Poor’s (S&P) rationale to downgrade EDF’s rating in June  2020382 and, after a further downgrade in February 2022383, the placement on credit-watch negative in May 2022384. In the same rating actions, S&P downgraded EDF’s U.K. subsidiary EDF Energy to BB, deep in speculative territory (“junk”) and put it as well on credit-watch negative for potential further downgrade. These developments will further increase the cost of EDF’s debt service.

   The administration of Prime Minister Theresa  May finally approved and signed binding contracts for the HPC project in September  2016, with the Government retaining a ‘special share’, that would give it a veto right over changes to ownership, including preventing EDF from selling down to less than 50  percent, if national security concerns arose.385 The U.S.  Government continued to have security concerns and in October  2018 Assistant Secretary of State, Christopher Ashley  Ford, warned the U.K. explicitly against partnering with CGN, saying that Washington had “evidence that the business was engaged in taking civilian technology and converting it to military uses”.386 Reportedly, U.S. diplomats have been “celebrating the UK’s effort to push a Chinese company out of a sensitive nuclear power project” in the fall of 2021.387 The comment refers to the Bradwell project where CGN was planning to build its own design (see hereunder).

   A New Funding Model for Nuclear?

   In March 2022, the U.K. Parliament finally adopted a Nuclear Energy (Financing) Act, which introduces a new funding model to facilitate the construction of new nuclear via a Regulated Asset Base  (RAB),388 after over two years of consultation, review and adoption process. There are at least 3 key differences between RAB and Contract for Difference  (CfD) models. One is consumers paying finance costs, another is that the owners would be institutional investors such as pension funds, sovereign wealth funds etc and the third is the price is not fixed because unlike CfD, the owners do not assume the risk of cost escalation and time overrun. If a project is taken forward under this model the project developer could charge consumers upfront for the construction, which would be broken down into different phases during the build process. Furthermore, consumers would pay the finance charges so borrowing would be effectively interest free to the owners in the construction phase.

   In 2019, EDF claimed that all households would have to pay only about £6  (US$7.5) per year additionally for them to build the proposed reactors at Sizewell  C.389 In  May  2022, the BEIS  Secretary of State, Kwasi  Kwarteng told householders to prepare for a “small rise” in their energy bills.390

   It is noteworthy that in the Impact Assessment produced by the U.K. civil service to support the legislation it was noted that on average the construction cost is

   20% higher than expected at the point of FID [Final Investment Decision] based on data from nth of a kind nuclear power plants built in Europe; and

   100% higher than expected at the point of FID based on data from all nuclear power plants built after 1990. 391

   It is further noted that at the FID for Hinkley  Point  C it was estimated to have a construction cost (excluding financing cost) of £20216,400/kW  (US$20218,646.4), but the governments model is assuming construction costs of £20217,700–13,000/kW  (US$202110,363–17,496/kW).392

   Charging upfront reduces the overall construction costs as it avoids the need to include interest during the construction phase, thus cutting the amount of compounded debt to be serviced and paid off during the life of the asset, which could be key for nuclear projects as financing represents a significant share of the overall project costs. Furthermore, by breaking the construction into different phases, it is expected that this would increase certainty and therefore further reduce the cost of finance. EDF argues that the aim would be to reduce the weighted average cost of capital  (WACC) from the 9.2  percent on HPC to around
   5.5–6  percent.393 However, as a 2019-assessment by the National Infrastructure Commission concludes:

   it would be inappropriate to compare the price achieved under a CfD model, into which the developer has priced the risks of cost and time overruns, with a price achieved under a RAB model made on the basis that the project will be built on time and on budget.394

   Furthermore, the consumer protection association, Citizens Advice stated in their response to the consultation that:

   While there are credible reasons to believe that a RAB model would reduce the cost of capital associated with bringing forward new nuclear power stations, these are outweighed by the risk of highly material increases in the volume of capital that consumers will need to finance.395

   A key selling point for the Government was a hope that funding would not have to come from the Treasury—and therefore remains off the Government’s balance sheet. However, in October  2020 Energy Minister Kwasi  Kwarteng reportedly told an event at the Conservative Party conference that the Treasury now believes that a nuclear RAB would be considered as a U.K.  Government balance sheet debt, given the support it is given.396

   Other U.K. New-Build Projects

   Sizewell C

   EDF and CGN are also preparing to launch the development of a follow-on to HPC, the Sizewell  C project. Chinese investment would be limited to 20  percent, leaving EDF with 80  percent. The budget—about £500 million  (US$2022607)—to get to FID is nearly spent and CGN is not obliged to pay more and the signals from the EDF Reference Document are that it is either unwilling or won’t be allowed to spend more. The 80/20 split covers only the stage up to final investment decision. There is no agreement to invest beyond that stage.397 Given the apparent problems EDF is having financing HPC, this makes the Sizewell project even more difficult. Despite this, a public engagement process has been ongoing, and EDF was expected to submit a planning application, a so called “development consent order” in February  2020, but concerns by statuary agencies about the readiness of the application followed by the pandemic and the Government’s control measures led it being delayed until May  2020.398 On 24  June  2020, the Planning Inspectorate, accepted the application and consequently the next stage of the planning process could begin.399 However, in October  2020, EDF announced it intended to make changes to the application, leading to further delay.400 The final decision on whether to grant a development consent order to build Sizewell-C was given by the Government in July  2022401.

   “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.”

   EDF is hoping that it can sequence the construction of Sizewell C with the completion of HPC, so that workers can move from one project to another. But given the earliest conceivable preliminary construction works start date of Sizewell  C in 2024, this seems impossible. EDF is optimistic that it can reduce construction costs, with their estimate in 2020 put at £18  billion (US$202022  billion).402 However, they are also hoping that the financing costs of Sizewell-C can be reduced 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”, they could “peel away” the strike-price by £36/MWh (US$44.5/MWh),403 as a result of EDF’s “base  case” for Sizewell  C’s cost being £20  billion (US$24.8  billion), with 60  percent financed by loans.404 In its planning documents, EDF confirmed construction costs of £20  billion (US$24.8  billion), despite previously suggesting that costs would be 20  percent lower than HPC thus limited to £18  billion (US$22.3  billion).405

   In March 2021 EDF’s financial report for 2020 said a Final Investment Decision (FID) was likely to be made in mid-2022, but used cautious language on the whole about the project, stating:

   EDF aims to ensure that risk sharing with the U.K. government in the as-yet un-validated regulatory and financing scheme will make it possible to find third party investors during the FID and avoid consolidating the project (including the economic debt calculation adopted by rating agencies). To date, it is not clear whether the Group will reach this target.

   It went on to say:

   EDF’s ability to make a 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.406

   In January 2022, the Government reiterated its intention to see a FID on “at least one” large scale nuclear project in this Parliament—which is set to run until May  2024. The Government has also pledged £100 million [US$135  million] for EDF to “help bring [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, “should the project not ultimately be successful”.407

   In June  2022, the U.K. Government bought an option to take a 20  percent share in Sizewell C, should the project reach a final investment decision, in the apparent intention to ease the ousting of Chinese investors.408

   In the same week that the U.K. Government announced that Sizewell C had been granted development consent, it was announced by the French Government that it would fully renationalize EDF (see France Focus) which is likely to affect the timing and potentially the scope of the FID, which is currently expected in 2023.

   Bradwell

   EDF is allowing CGN to use the Bradwell site it had bought as back-up, if either the Hinkley  Point or Sizewell sites proved not to be viable. CGN plans to build with its own technology, the Hualong  One (or HPR-1000) at this site, with EDF taking a 33.5  percent stake,409 up to the point of getting the Generic Design Assessment  (GDA), going forward the plant will need a new consortium. In January  2017, the U.K.  Government requested that the regulator begin the GDA of the HPR-1000  reactor,410 and by February  2020 the ONR had completed Step  3 of the GDA.411 The final step and the issuing of a Design Acceptance Confirmation  (DAC) from Office for Nuclear Regulation  (ONR) and a Statement of Design Acceptability  (SoDA) from the Environment Agency was made on 7  February  2022.412 In December  2020, the U.K.’s gas and electricity markets regulator, Ofgem, granted an electricity generating license to the Bradwell Power Generation Company Ltd.413

   In August 2019, the United States blacklisted CGN for allegedly stealing the country’s nuclear technology for “military uses” and added the state-owned Chinese firm and its three subsidiaries to its “entity list”. The move makes it virtually impossible for American companies to supply or cooperate with the company without specific permissions.414 This and the increasing breakdown in the relationship between China, the U.S. and to some extent Europe, may well impact on the development of Bradwell as will the current economic climate and the likelihood of a global recession. In particular for the U.K., there is ongoing and growing concern over the situation in Hong  Kong. Consequently, it has been suggested that as nuclear power plants “are part of the U.K.’s strategic national infrastructure, and China is no longer a friend to be trusted with such levers of power” it is impossible to envisage the Government approving the Bradwell station.415 Furthermore, there is increased attention on the Bradwell project with the cancellation of negotiations about future nuclear projects in the Czech Republic and Romania in 2020 due to security concerns with China.416

   Various media in the U.K. reported at the end of July 2021 that the Government was investigating how to block CGN from operating future power plants in the U.K.. This would ban them from engagement in either Sizewell  C or Bradwell. The Chinese Government responded by saying that “The British should earnestly provide an open, fair and non-discriminatory business environment for Chinese companies. China and the U.K. are important trade and investment partners for each other.”417

   Other sites have been proposed and developed to various degrees over the years. This includes Moorside in Cumbria, being developed at some point by Toshiba-Westinghouse, as well as Wylfa Newydd on Anglesey and Oldbury on Severn in South Gloucestershire, owned by Hitachi-GE. However, as of mid-2022, work had been suspended on all of these sites.

   Sort of Small Modular Reactors

   In November  2020, to support the development of a potential next generation of reactors the Government proposed to provide up to £385  million (~US$500  million) in an Advanced Nuclear Fund for the next generation of nuclear technology, with up to £215  million  (US$2020278  million) going to Rolls-Royce’s SMR program.418 Rolls-Royce is in the final stages of completing its feasibility study and is hoping that its technology will complete the Generic Design Assessment  (GDA) process with U.K. regulators around September 2024 and deliver first power in about 2030.419 As noted in the SMR Chapter, in November  2021, Rolls Royce announced that it had received £210  million (US$281  million) in government funding and £195  million (US$261  million) in private funds and then an additional £85  million (US$112  million) from the Qatar Investment Authority.

   The reactor is said to be able to be used for power, hydrogen production and for the manufacturing of jet fuel, and its multipurpose will enable a larger number of reactors to be installed.420 Rolls-Royce are confident about the price of the units and suggest that the nth-of-a-kind reactor (after five have been built) will be in the order of £1.8  billion (US$2.2  billion) (capex) for 470  MW units and £40–60/MWh (US$48-73/MWh) over 60  years.421 In evidence submitted in 2017, Rolls-Royce told the House of Lords, that 7  GW would “be of sufficient scale to provide a commercial return on investment from a UK-developed SMR, but it would not be sufficient to create a long-term, sustainable business for UK plc.” The House of Lords concluded: “Therefore, any SMR manufacturer would have to look to export markets to make a return on their investment.”422

   The capital cost estimate is a heroic assumption equating to £4,000/kW (US$4,858/kW) compared to what EDF estimates for the cost of Sizewell  C of £5,600/kW  (US$6,802/kW) and the current cost of Hinkley  Point  C of £8,100/kW  (US$9,838/kW). It is fair to say that if there was any confidence that the SMRs would be delivered at the cost quoted that Sizewell  C and any similar sized reactors would be abandoned.

   Technically speaking, the Rolls-Royce design is not an SMR. These are in a 30–300  MW range, according to a definition used by the IAEA and most national and international organizations (see  Chapter on SMRs).

   Conclusion

   While nuclear power has become one of the cornerstones of the U.K. Government’s future energy security policy, it seems unlikely—despite the various proposed measures—that there will be an acceleration of the development of nuclear power over the next decade. Furthermore, given the Government’s commitment to have a zero-carbon power sector by 2035, before significant new nuclear capacity can come on-line, the likelihood of additional nuclear, beyond Hinkley Point  C and possibly Sizewell  C in the late 2030s and beyond seems remote, despite the rhetoric of the new Government led by Liz  Truss.

   While the political support for nuclear power seems high, especially in light of heightened concerns over energy security, this cannot overcome the material and economic state of the sector. During the past year, the implications of the aging problems at the AGRs have become clearer, with reactors closed and others to cease operation shortly, while the taxpayer is having to pay billions more for ever increasing decommissioning costs. Furthermore, in 2022 the estimated costs of the completion of Hinkley  Point  C, have risen by at least a further £20153  billion (US$20154.45  billion) to around £201526  billion (US$201538.5  billion) and startup put back at least a year to 2026 or later for the first reactor. The power purchase price for the reactors was set in 2013 at £92.5/MWh  (US$2022133.7/MWh) when EDF claimed the construction cost would be £201214  billion  (US$202217  billion). The cost estimate has nearly doubled since then but the nuclear feed-in tariff did not increase, so it is difficult to see how Hinkley  Point  C could be anything but a major loss-maker for EDF.

   United States Focus

   

   Overview

   With 92 commercial reactors operating as of 1 July 2022, the U.S. continues to possess by far the largest nuclear fleet in the world. One reactor was closed in the year since WNISR2021. Palisades-1 in the state of Michigan was closed on 20  May  2022, after 50 years of operation.423 The retirement was announced in 2018 to coincide with the expiration of a lucrative power purchase contract between Energy Nuclear and the original owner of Palisades-1, utility corporation Consumers Energy. On 1  September  2022, California enacted legislation to finance a 5-year extension of the Diablo Canyon-1 and  -2 reactors, to 2029 and 2030 (see the section Securing Subsidies to Prevent Closures).424

   “Projected construction costs continued to increase over the last 12  months, and start-up dates were again pushed back. As of June  2022, Vogtle’s cost had increased to at least US$30.34  billion.”

   The U.S. reactor fleet provided 778.2  TWh in 2021425, a drop of 1.5  percent over 2020. According to IAEA-PRIS, nuclear plants provided 19.6  percent of the nation’s electricity in 2021—18.9  percent according to the U.S. Department of Energy’s  (DOE) Energy Information Administration (EIA)—down from 19.7  percent in 2020 and approaching 4  percentage points below the highest nuclear share of 22.5  percent, reached in 1995. Counting non-commercial rooftop solar PV generation (which increased 18  percent year-over-year), nuclear energy’s share of total electricity generation was 18.7  percent in 2021.426

   With only one new reactor started up in 26 years, the U.S. fleet continues to age, and with a mid-2022 average of 41.6  years, it is amongst the oldest in the world: 47  units have operated for 41 and more years (of which six for more than 51  years) and all but three for 31 and more years (see Figure 40).

   

   Sources: WNISR, with IAEA-PRIS, 2022

   Construction continued on the one new nuclear plant in the U.S., the twin AP-1000s at Plant Vogtle Units  3 and  4, in the state of Georgia. Projected construction costs continued to increase over the last 12  months, and start-up dates were again pushed back. As of June  2022, Vogtle’s cost had increased to at least US$30.34  billion,427 according to Associated Press calculations.428 That figure does not include US$3.68  billion in costs that Westinghouse refunded to the co-owners in 2017,429 putting the total cost of the project over US$34  billion—2.4  times the US$14  billion projected cost at the start of construction in 2013. The most recent cost increases and construction delays are due largely to quality assurance problems in the installation of electrical cabling throughout the plant,430 as well as administrative errors in failing to complete over 26,000  inspection records.431 On 3  August  2022, the U.S. Nuclear Regulatory Commission  (NRC) authorized the loading of fuel in Unit  3, with a planned startup date in the first quarter of 2023. Georgia Power estimates the startup of Unit  4 before the end of 2023.

   Large New Subsidies for Nuclear Power

   Since the publication of WNISR2021, the U.S. Congress has enacted two major pieces of infrastructure and energy finance legislation: the Infrastructure Investment and Jobs Act (IIJA),432 with US$1.2  trillion in proposed spending433; and the Inflation Reduction Act (IRA),434 with US$437  billion available.435 Each law includes significant new spending to promote nuclear energy—existing reactors, new reactors, and enrichment infrastructure. IIJA creates a US$6  billion Civil Nuclear Credits program to support uneconomic reactors at imminent risk of closure, as well as US$3.2  billion to support new reactor demonstration projects. IRA includes five measures that provide subsidies and financing for existing and new reactors:

   • Production tax credits for existing reactors;436
   • Clean energy production and investment tax credits for new energy sources, including new reactors;
   • US$40  billion in loan guarantees for new clean energy projects, including new reactors;
   • US$250  billion in loan guarantees for existing energy infrastructure (Energy Infrastructure Reinvestment Financing), for which existing reactors are likely to be eligible; and
   • US$700 million for High-Assay Low-Enriched Uranium (HALEU).

   The total amount of spending for nuclear energy under these measures is not yet determined but is certainly the largest direct federal investment in commercial nuclear energy in decades. Congress’s Joint Committee on Taxation’s  (JTC) latest estimate of the bill’s budget impacts projects the production tax credits for existing reactors to cost US$30  billion over the nine years of the program (from 2024 through 2032).437

   The Energy Policy Act of 2005 (EPACT 2005) was the previous law authorizing large amounts of federal funding for commercial nuclear energy,438 which directed DOE to provide loan guarantees for new reactors,439 up to US$6  billion in production tax credits, US$2  billion in grants to compensate for delays in reactor licensing, and US$1.25  billion for a Next Generation Nuclear Plant Project. The JTC provided no breakdown by energy source/technology of the other tax credits and loan guarantees for which commercial reactors are eligible, but the Nuclear Production Credits alone likely match or exceed the value of all EPACT  2005 spending on commercial reactors.

   “There’s a deepening understanding within the [Biden] administration that it needs nuclear to meet its zero-emission goals”

   As one insider noted to Reuters news agency in 2021, “There’s a deepening understanding within the [Biden] administration that it needs nuclear to meet its zero-emission goals.”440 With no prospects of major nuclear plant construction in the coming years,441 the legislative efforts have focused on providing subsidies to prevent further reactor closures. It is unclear to what extent the funding allocated in the IIJA and the IRA will successfully prolong the operation of otherwise uneconomical reactors through direct subsidies and lowering the industry’s risk exposure to financing large maintenance projects (e.g.  steam generator replacements). However, the much larger federal investments in existing reactors than in new construction suggest the U.S.  industry is focused on treading water rather than on breaking ground in the next decade.

   In addition to the trends of closures and subsidies among existing reactors, there is a trend of corporate restructuring in the merchant nuclear sector over the past three years. Three utility holding companies that controlled approximately one-third of operating reactors a decade ago have divested their nuclear power plants. Entergy has closed or sold off its six merchant reactors since 2014.442 With the closure and sale of Palisades-1 to Holtec for decommissioning, it has completed its exit from the merchant nuclear generation business. It still owns and operates five reactors through its regulated utility subsidiaries in Arkansas, Louisiana, and Mississippi. In 2020, FirstEnergy sold off its four nuclear reactors443 and two coal power plants to Energy Harbor through the bankruptcy settlement of its merchant generation subsidiary, FirstEnergy Solutions.444

   In February 2022, Exelon, by far the largest nuclear generator in the U.S., completed the spin-off of Constellation Energy Corp., with its holdings in 23 reactors and other merchant generation and power marketing ventures. In 2021, as the spin-off was being executed, Exelon also completed the acquisition of EDF’s 50  percent stake in the corporations’ joint venture Constellation Energy Nuclear Group, which owned five reactors. Following the spin-off, Constellation CEO Joe  Dominguez stated that the corporation’s growth strategy includes acquiring more merchant reactors “from other companies looking to exit the competitive power business.”445 In 2020, Public Service Enterprise Group  (PSEG) announced that it would divest its generation assets except its nuclear holdings,446 which include interests in four reactors it co-owns with Constellation, as well as the Hope  Creek reactor in New  Jersey. Following enactment of the IRA, analysts have already speculated that PSEG may strike a deal to transfer its ownership of the reactors to Constellation and fully exit the merchant generation business.447 PSEG has also repurposed a site adjacent to its Salem-1 and  -2 and Hope  Creek reactors for which it received an early site permit in 2016448 for an unspecified small modular reactor project. The site is now being developed to serve as a logistics facility for construction of offshore wind installations.449

   The trend signals that utility holding companies believe regulated distribution utility operations will be the primary profit centers of their businesses going forward, and that owning and operating nuclear reactors in wholesale power markets is no longer in the interests of their shareholders, even with billions of dollars in state and federal subsidies.

   During the past few years, utilities have both succeeded and failed in their ongoing efforts to secure state financial support for operating nuclear plants, with the balance being in the industry’s favor. As of July  2022, 18  reactors in the U.S. were receiving or are eligible for subsidies as a result of state legislation such as Zero Emission Credits  (ZEC) or equivalent: Nine Mile Point-1 and  -2, FitzPatrick, and Ginna in New  York; Braidwood-1 and  -2, Byron-1 and  -2, Clinton, Dresden-2 and  -3, and Quad Cities-1 and  -2 in Illinois; Salem-1 and  -2 and Hope Creek in New  Jersey; and Millstone-2 and  -3 in Connecticut. ZEC subsidies in Ohio for Davis  Besse and Perry were rescinded in 2021450 before any of the funds had been disbursed. As a result of the federal corruption investigation into FirstEnergy’s contributions of US$61  million to state legislators and political action committees to pass House Bill  6  (HB6) in 2019, the legislature repealed the nuclear subsidies in the bill (see previous WNISR editions).

   Extended Reactor Licenses

   As of 1  July  2022, 84 of the 92 operating U.S. units had already received 20-year Initial License Renewals, which permits reactor operation beyond 40 and up to 60  years. Since December  2019, the Nuclear Regulatory Commission  (NRC) did not issue any additional 20-year license renewals. Four reactors are currently listed as intending to apply for license extension in the period 2022–2024.451 Under the Atomic Energy Act  (AEA) of 1954, as amended, and NRC regulations, the NRC issues initial operating licenses for commercial power reactors for 40 years. NRC regulations permit license renewals that extend the initial 40-year license for up to 20 additional years per renewal.

   In July  2017, the NRC published a final document describing “aging management programs” that allow the NRC to grant nuclear power plants operating licenses for up to 80  years, which the NRC has designated “Subsequent License Renewal.”452 As of 4  May  2021, the NRC had granted Subsequent Renewed Operating Licenses to six reactors,453 which would permit operation from 60 to 80  years. Applications for a further nine reactors are under review.454

   However, in February 2022, the NRC issued an unprecedented order effectively suspending the approvals it had granted for four reactors,455 and holding approvals of the other applications in abeyance, while it develops a new environmental assessment for license renewals authorizing operation from 60 to 80  years. Intervenors in the reviews of the Turkey Point and Peach Bottom applications alleged to the NRC that it had violated its own regulations and the National Environmental Policy Act  (NEPA) in approving them on the basis of an inapplicable Generic Environmental Impact Statement  (GEIS). Initially, in a ruling issued on 12  November  2020, the NRC upheld its decision granting the licenses stating that it was correct to rely on NRC’s Generic Environmental Impact Statement for license renewal.456 However, two of the NRC Commissioners dissented from the decision, arguing this interpretation violates the NRC’s obligations under the NEPA.457 As a result of the expiration of two Commissioners’ terms in 2021, the dissenting commissioners then held the majority of two to one, and determined to avoid legal challenges in the courts and suspend the previous approvals.

   When the NRC promulgated its rules for review of initial 20-year license renewals in 1996, NRC fulfilled its NEPA obligations by publishing a GEIS458 (updated in 2013459), covering a broad array of environmental impacts that the NRC deemed common to all initial license renewals. When applying for initial license renewal, the licensee needs only to provide a Supplemental Environmental Impact Statement, addressing impacts that are site-specific to the reactor/s in question. In doing so, the NRC issued a regulation authorizing licensees to use the GEIS for initial license renewals to operate for up to 60  years. At the Commissioners’ direction, the NRC is in the process of updating the GEIS to cover operation from 60 to 80  years. It must also amend its regulations to authorize the use of the updated GEIS in subsequent license renewal applications.460

   While not guaranteeing reactors’ continued operation, multiple applications are expected over the coming years for subsequent license renewals. Duke Energy Corporation has said it plans to seek license extensions for all 11 of its reactors.461 The federal legislation providing extended financial support for reactor operations are likely to encourage additional applications for 80-year operational licenses.

   Reactor Closures

   The retirement of Palisades-1 in May  2022 marks the completion of Entergy’s planned exit from the merchant generation business, preceded by the retirements of Vermont Yankee-1 (2014), Pilgrim-1 (2018), Indian Point-2 (2020), and Indian Point-3 (2021), as well as the 2016 divestiture of FitzPatrick-1 to Exelon. The final shutdown of Palisades-1 was preceded by a proposal initiated by Michigan Governor Gretchen Witmer to apply a federal subsidy under the Civil Nuclear Credit program created by federal infrastructure legislation enacted in December 2021 toward attracting a new owner who would extend the Palisades-1. The proposal failed to garner interest, particularly as Entergy had already entered into a contract to transfer ownership of Palisades-1 and its decommissioning trust fund  (DTF) to Holtec International. Entergy has transferred all of its retired reactors to consortia specializing in decommissioning: Holtec and Northstar.

   The average age of the six reactors closed in the U.S. over the four-year period 2018–2021 (none was closed in 2017) was 46.5  years (see  Figure 41), which remains far below their licensed lifetimes of 60  years.

   

   Sources: WNISR with IAEA-PRIS, 2022

   Securing Subsidies to Prevent Closures

   As WNISR has reported in recent years, utilities have been lobbying for state legislation and contracts that would provide significant financial support for the operation of their uneconomic reactors (see WNISR2018 Annex 4). A total of 23  reactors were scheduled for early retirement between 2009 and 2025, of which 13 have already been closed, eight had their closure delayed following subsidy programs, and two at Diablo Canyon remain in question (see  Figure 42).

   The enactment of two major pieces of legislation making federal financing and subsidies available to currently operating nuclear power reactors has disrupted projections for the pace of retirements. The Infrastructure Investment and Jobs Act (November  2021) authorized the issuance of Civil Nuclear Credits to unprofitable reactors, to be administered by the Department of Energy  (DOE) through a five-year, US$6  billion federal grant program.462 Implementation of the program prompted the governors of California and Michigan to request that DOE apply the grants toward preempting the planned retirements of Palisades-1 and Diablo Canyon-1 and  -2. Entergy Nuclear, the owner of Palisades-1, did not embrace Governor Witmer’s proposal and retired the reactor as planned.

   Governor Gavin Newsom’s proposal for Diablo Canyon took a different course. Driven by California’s seasonal electricity reliability challenges,463 Newsom’s proposal garnered political support and convinced Diablo Canyon’s owner, Pacific Gas & Electric (PG&E), to consider breaking an innovative multi-stakeholder agreement to retire the reactors when their federal operating licenses expire in 2024 and 2025. The proposal prompted DOE to amend in June  2022464 the program guidance it had recently issued in April  2022,465 under which Diablo Canyon likely would not have been eligible. In order to further accommodate the state’s policymaking process, DOE twice extended the deadline for PG&E to apply: first, from 19  May to 5  July 2022 and then again to 6  September 2022.466

   On 1 September 2022, the California legislature passed a bill proposed by Governor Gavin Newsom to extend Diablo Canyon’s operations and make US$1.4  billion in loans available to PG&E to pursue 5-year extensions of the reactors’ federal operating licenses, as well as deferred maintenance and other expenditures. The state funding is contingent on both Diablo Canyon’s eligibility for Civil Nuclear Credits, as well as future determinations by the California Public Utilities Commission on the prudency of Diablo Canyon’s cost to consumers and whether the reactors are needed to ensure transmission system reliability.467

   The decision may delay the most deliberate and planned nuclear power-plant retirements in the U.S. In 2016, PG&E entered into a settlement with four environmental organizations and two labor unions. Under the agreement, PG&E would withdraw its license renewal application at NRC, close the reactors when their operating licenses expire in 2024 and 2025, make investments in renewables and energy efficiency to ensure it meets California’s renewable energy and emissions goals, provide salary bonuses, training, and job opportunities for Diablo Canyon workers, and make stable property tax payments to local municipalities through 2025. The California Public Utilities Commission  (CPUC) approved the proposal in 2018, after the California Legislature enacted a law expressly giving it the authority to implement the additional payments to workers and local communities and requiring the CPUC to ensure that Diablo Canyon’s retirement would not result in increases in greenhouse gas emissions. In subsequent proceedings since 2019, the CPUC has issued orders to PG&E and all other utilities in the state to procure a total of 22  GW of renewable energy and storage capacity by 2026—the vast majority of which by the time Diablo  Canyon-1 is to close in November  2024. The CPUC has affirmed publicly that its system planning proceedings and procurement orders have been directed at assuring grid reliability and emissions reductions through the retirements of Diablo Canyon and several fossil fuel power plants.468

   The Inflation Reduction Act contains six potential sources of funding and financing for existing and new reactors:

   • Zero-Emission Nuclear Power Production Credit: Production tax credits for existing reactors, available for nine years (2024 through 2032). All existing reactors are eligible. If a reactor owner meets prevailing wage and union apprenticeship requirements, they may claim as much as US$15/MWh in tax credits. If not, the credits are worth a maximum of US$3/MWh. If the annual sales revenue of the reactor is greater than US$25/MWh, the value of the credits that can be claimed is reduced, phasing out at US$0 for annual revenue of US$43.75/MWh. Other state or federal ZEC payments must be counted as sales revenue, unless those programs specify that their credits would be reduced in the amount of these federal credits.
   • Energy Infrastructure Reinvestment Financing: A US$250 billion loan guarantee program for owners of existing energy infrastructure to finance projects that will “avoid, reduce, utilize, or sequester air pollutants or anthropogenic emissions.” Existing reactors would likely be eligible for these loan guarantees, particularly for license renewals and/or major capital projects necessary to continue operating, such as steam generator replacements.
   • Tax credits for new generation sources
     • Clean Electricity Production Credit: Production tax credits for new electricity sources, available for 10 years after the facility begins operation. New reactors would be eligible. Similar to the Nuclear Production Credit, the credit is worth US$15/MWh if the owner meets prevailing wage and union apprenticeship requirements, and only US$3/MWh otherwise. Facilities sited in “energy communities”469 receive a 10 percent bonus to the credit. An additional 10  percent bonus is available for facilities that meet domestic content requirements.
     • Clean Electricity Investment Credit: Investment tax credits for new electricity sources. Facilities cannot claim both the production credit and the investment credit. Similar to the production credit, the investment credit can be claimed on 30 percent of the eligible investment amount for the facility if the owner meets prevailing wage and union apprenticeship requirements, but only 6  percent if it does not. Facilities sited in “energy communities” receive a 10 percent bonus to the credit. An additional 10 percent bonus is available for facilities that meet domestic content requirements.
   • Funding for DOE Loan Programs Office: Authorizes an additional US$40–43.6  billion for loan guarantees under DOE’s existing program, for which new reactors would be eligible.
   • Availability of High-Assay Low-Enriched Uranium (HALEU): Authorizes a total of US$700  million toward assuring the availability of HALEU for new commercial reactors research, development, and demonstration  (RD&D) projects and commercial use. US$100  million is allocated for development and certification of transportation canisters. US$500  million is allocated for procurement of HALEU for a commercial reactor development consortium. US$100  million is to assure availability of HALEU for RD&D and commercial use.

   

   Sources: Various, compiled by WNISR, 2022

   Notes:

   * Crystal River: No production after 2009 (WNISR considers it closed as of this date). Official closure announced in 2013. Renewal application submitted in 2008, withdrawn in 2013. See U.S.  NRC, “Crystal River – License Renewal Application”, U.S. Nuclear Regulatory Commission, Updated  9  December  2016, see  https://www.nrc.gov/reactors/operating/licensing/renewal/applications/crystal-river.html, accessed  8  September  2020.

   ** Possible deferral of closure until 2029 and 2030

   *** Early closure reversed following access to new subsidies. For Braidwood-1 &-2, and Byron-1 & -2, the enacted legislation extends the subsidies to 2027.

   **** License Renewal Application cancelled in 2018. In 2020, Energy Harbor announced its intention to submit a new license renewal application. See Perry Nuclear Power Plant, “Notice of Intent to Submit License Renewal Application”, Energy Harbor, addressed to U.S. Nuclear Regulatory Commission, 13  May  2020, see  https://www.nrc.gov/docs/ML2013/ML20134H987.pdf, accessed  8  September  2022. Submission is expected in 2023.

   As of 1 July 2022, legislation in five states (Connecticut, Illinois, New Jersey, New  York and Ohio) had been enacted—with one retraction in Ohio as a result of the FirstEnergy corruption scandal (see  below)—which in total provided state subsidies to 18  reactors at eleven nuclear plants. All of these five states have unbundled, retail-choice electricity markets, where generators do not receive cost recovery from state regulatory commissions. In the four states with active nuclear subsidy programs, those reactors account for 16  percent of the utility-scale generating capacity and 19  percent of the U.S. nuclear generating capacity.470

   As reported previously, central to the future of nuclear power in the PJM Interconnection LLC  (PJM) and other wholesale electricity markets are the rules governing how these state subsidies for incumbent nuclear power plants are rationalized in the competitive pricing auctions. Since state-level subsidies for merchant nuclear reactors were first implemented in 2016, regional wholesale markets (labeled alternately regional transmission organizations or independent system operators, RTOs or ISOs) and the Federal Energy Regulatory Commission  (FERC), which oversees them, have tried to balance the competing interests of different industry segments—principally, the coal, gas, and nuclear industries. RTOs/ISOs are private organizations whose governance is dominated by the commercial interests with the greatest market shares.471 For instance, in June  2018, FERC invalidated the PJM market rules.472 The FERC order related to how PJM set the price of capacity it procures through its capacity market, known as the Reliability Pricing Model  (RPM). The new FERC rules would have affected how state subsidies, including ZECs, would be considered in the wholesale market. At issue was whether the subsidies being received by utilities for their nuclear plants would be factored into the capacity auction pricing. As reported in previous WNISRs, the legislation passed in four of the five states has been Zero Emission Credits or ZECs.

   These instruments are similar in name but different in function from the more well-established system of renewable energy credits (RECs). ZECs in Illinois, New York, and New Jersey are awarded on an uncompetitive, fixed-price basis to single corporations gigawatts of nuclear capacity, representing large shares of the existing state/regional generation supply. In states that have established renewable energy (or portfolio) standards (RES or RPS), contracts for RECs are auctioned to renewable energy projects on a competitive basis, from a fixed pool of credits determined by annually increasing targets for renewable energy consumption. ZECs provide subsidies to help nuclear generators boost profitability and hold onto their market share, whereas RECs provide a competitively priced incentive for the deployment of new renewable technologies at the lowest cost. Both policies are intended to reshape market outcomes, and FERC noted in its 2018 order that “With each such subsidy, the market becomes less grounded in fundamental principles of supply and demand.”473

   In December 2019, FERC released an order474 directing PJM475 to significantly expand its minimum offer price rule  (MOPR) to mitigate the impacts of state-subsidized resources on the capacity market. The ruling had the potential to undermine renewable energy development and drew sharp opposition from a range of interests, including renewable energy industry associations, environmental groups, and states with specific RES/RPS policies, which are particularly concerned about the ruling’s de-facto support for continued fossil fuel use.476

   One consequence of the FERC ruling was a delay to the 2021 PJM auction (which are held twice annually). When it was held in June  2021, nuclear generation cleared the most additional capacity compared to the previous capacity auction, with an additional 4,460  MW.477 Industry analysts noted that Public Service Enterprise Group  Inc.  (PSEG) and Exelon’s Salem plant in New  Jersey and PSEG’s Hope  Creek plant in New  Jersey likely secured contracts by appealing for PJM’s unit-specific exemption to the MOPR, which allows them to bypass default numbers PJM may assign a resource because of its status as a state-subsidized resource.478 One explanation for the more successful auction for nuclear plants compared to the previous auction was the impact of the Biden administration’s active support for nuclear power.479 This was despite the 64-percent reduction in the auction price compared to 2018, with PJM confirming that for the period 2022–2023 the price was US$50/MW-day compared to the US$140/MW-day three years ago.480

   Exelon, in a filing with the U.S. Securities and Exchange Commission, revealed that its Byron, Dresden and Quad Cities nuclear plants in Illinois all failed to sell their power at the PJM auction, losing out to other power plants and energy resources.481 At the time of the filing, two reactors each at the Byron and Dresden sites were slated to be closed in September and November  2021 respectively, while Quad Cities is in receipt of Illinois state subsidies from 2017-2027. PJM confirmed that the four reactors can retire without putting overall grid reliability at risk,482 But Exelon retracted the closure plans in September 2021, after Illinois enacted legislation providing US$694 million in subsidies to them over five years.

   A proposal from PJM in response to the FERC MOPR ruling was issued on 30  June  2021. Under the PJM proposal, state policies providing out-of-market payments to generating resources, such as nuclear plants, would be recognized as being a legitimate exercise of a state’s authority over the electric supply mix. Those policies would not be subject to the MOPR “so long as the policy does not constitute the sale of a FERC-jurisdictional product that is conditioned on clearing in any RPM [Reliability Pricing Model] auction,” the grid operator said in its proposal summary.483

   A change in leadership at FERC and the retirement of a commissioner after President Biden took office in January  2021 resulted in a deadlock when the commission reviewed PJM’s “focused MOPR” proposal.484 The policy went into effect 90  days later without FERC taking action, effectively defaulting back to the previous rules after three years of market uncertainty and deferred capacity auctions. The proposals from PJM were to be incorporated into the next auction, which was to be held in December  2021, for the period 2023–2024. However, the auction was again delayed when FERC reversed a previous decision affecting the amount of capacity PJM must procure.485

   While efforts to secure ZEC legislation stalled in Pennsylvania, the decision by the state Governor to join the Regional Greenhouse Gas Initiative (RGGI) has led to the choice to reverse the decision to close Beaver  Valley-1 and  -2. Plant owner Energy Harbor Corp. notified PJM that it would rescind its March  2018 deactivation notices. The reactors were owned previously by FirstEnergy Solutions (the merchant generation subsidiary of utility holding company FirstEnergy Corp.) which had filed for bankruptcy in 2018. Beaver  Valley Units  1 and  2 were scheduled to close in May and October  2021. The RGGI is a cap-and-trade program to limit carbon dioxide emissions from power plants.

   Analysis in October  2019 reported that a carbon price of US$3 to US$5 per ton would be enough to keep nuclear plants in Pennsylvania economically viable for the foreseeable future.486 Pennsylvania issued the emissions regulations necessary to join RGGI in April  2022,487 but a court injunction prevents their implementation until rulings on legal challenges are issued.488 Hearings in the cases are scheduled for September and November  2022. The states that are in the RGGI are Connecticut, Delaware, Maine, Maryland, Massachusetts, New  Hampshire, New  Jersey, New  York, Pennsylvania, Rhode Island, Vermont, and Virginia.

   Prior to enactment of the IIJA and IRA, Exelon announced that it would not close any other reactors in Illinois for at least six more years. The state enacted legislation extending subsidies to the Braidwood-1 and  -2, Byron-1 and  -2, and Dresden-2 and  -3 reactors until 2027.

   Braidwood-1 and  -2 and LaSalle-1 and  -2 would be kept in operation through May  2023 to “provide time for the significant logistical and technical planning necessary to ensure a safe and orderly retirement.”489 The Braidwood reactors have secured operational licenses to 2046 and 2047 respectively, while the LaSalle reactors are licensed to 2042 and 2043 respectively. However, Exelon warned that early shutdown would take place “in the event policy changes are not enacted”.490 The bill enacted in September  2021 authorized subsidies worth a total of US$694  million over five years for Braidwood, Byron, and Dresden491—more than the study concluded was necessary, but far less than the subsidies enacted in 2016 and those proposed in the federal bills. Exelon committed to keeping all of its Illinois reactors operational through the period in which the subsidies are provided, including the unsubsidized LaSalle reactors.

   Reactor Construction

   “Part of the risk that we see is that if something else were to happen during the construction between now and when it goes online for commercial operations, we would have to pay that too. … If we tender and can replace that energy for less than $135 per megawatt hour is the right call for us.

   It saves us money.”

   Jay Stowe, Chief Executive Officer of Jacksonville Electric Authority (JEA),

   on the utility’s decision to request Vogtle co-owner Municipal Electric Authority

   of Georgia to cap its share of Vogtle construction costs

   10 August 2022492

   The Vogtle Debacle

   Only two commercial reactors are currently under construction on a single site in the U.S., the AP-1000 reactors Vogtle-3 and  -4 which began construction respectively in March  and November  2013.493 At construction start of Unit  3, the projected cost of the twin-unit project was around US$14  billion, with construction expected to be complete in 2017 and 2018 respectively.494 The reactors are being built in Burke County, near Waynesboro, in the state of Georgia, in the southeastern U.S. and are owned by Southern  Company (parent company of majority Vogtle plant owner, Georgia  Power).

   In 2017, Southern Company delayed the projected fuel-loading schedule to November  2021 for Unit  3 and November  2022 for Unit  4. Those dates have since slipped to March and December  2023. In August  2022, NRC approved Vogtle-3 for initial fuel loading now considered likely to take place in October 2022, and fuel loading for Unit 4 will not occur until at least 2023.495

   During the past year, the project passed certain construction milestones, but the actual progress in completing construction and meeting the latest startup schedule is still uncertain. As in previous years and as reported in previous WNISR editions, evidence continues to emerge that reveals the enormous scale of the Vogtle project failure. The most recent delays resulted primarily from administrative errors in failing to document over 26,000 inspection records for correcting errors in electrical cable installations.496 NRC issued violations for the errors in 2021, requiring additional oversight.497 In granting approval for fuel loading, NRC concluded that Southern Company had satisfied the required inspections, tests, analyses, and acceptance criteria for Vogtle-3 to begin operation.498

   As of September 2022, construction of Unit  3 was 99 percent complete according to Southern Company, which compares with 98-percent completion as of July  2021 and 81.2  percent as of March  2020.499 In the case of Unit  4, Southern Company reported that it was 96 percent complete as of September  2022, compared to 84  percent as of July  2021.500

   Critics of the Vogtle project had long predicted that there would be delays and that costs would be much higher than anticipated.501 Georgia Power’s original 46.7  percent share of the project cost approved by the Georgia Public Service Commission  (PSC) was US$6.1  billion in 2009,502 which corresponds to a cost of US$5,975/kW (gross), whereas the 2017 estimate of US$23  billion translates to a cost of US$10,300/kW. The revised 2018-estimate was in the range of US$28  billion.503 As of August  2022, total project costs are reported to have increased to US$30.34  billion, or US$13,581/kW—2.3  times greater than the original approved cost estimate.504 Those figures do not include US$3.68  billion Westinghouse refunded to the Vogtle owners in 2017.505 Taking that into account, actual construction cost is now  ~US$34 billion, or US$15,219/kW and more than 2.5 times the original approved cost. These costs compare with the Massachusetts Institute of Technology (MIT) 2009-assessment of the prospects for new nuclear power based on overnight costs of US$20074,000/kW.506

   As WNISR2018 reported, in December 2017, the Georgia PSC, following the recommendation from Southern Company, decided to continue to support the project. The Georgia PSC has backed the Plant Vogtle project from the start, including awarding the generous Construction Work In Progress  (CWIP), where interest payments on all construction costs incurred by Georgia Power are passed directly on to the customer. The Georgia Nuclear Energy Financing Act, signed into law in 2009, allows regulated utilities to recover from their customers the financing costs associated with the construction of nuclear generation projects—years before those projects are scheduled to begin producing benefits for ratepayers.

   As a result of the CWIP legislation, out of Georgia Power’s original estimated US$6.1  billion Vogtle costs, US$1.7  billion is financing costs recoverable from the ratepayer. The utility began recovering these financing costs from its customers starting in 2011. For that first year, the rule translates to Georgia Power electric bills’ rising by an average of US$3.73 per month. Georgia Power estimated that this monthly charge would escalate so that by 2018, Georgia Power residential customers using 1,000  kWh per month would have seen their bill go up by US$10 per month due to Vogtle-3 and  -4. As a result of increased costs of the project and approval by the Georgia PSC, ratepayers had already paid US$2  billion to Georgia  Power as of November  2017.507 In June  2021, Georgia  PSC staff estimated that the average household customer of Georgia Power will have paid US$854 for Vogtle-3 and -4 construction before the reactors begin generating electricity.508 As a result of further delays since then, those costs—and thus customer subsidies—will be higher still.

   Under the financing terms agreed with the Georgia PSC, the longer the Vogtle plant takes to construct, the higher its costs, which have invariably been passed on to Georgia ratepayers, resulting in higher income streams for Georgia Power and therefore Southern. In reporting 2018 Southern earnings, CEO Thomas  A.  Fanning stated that 2018, “was a banner year for Southern  Company (...). All of our state-regulated electric and gas companies delivered strong performance” with full-year 2018 earnings of US$2.23  billion, compared with earnings of US$842  million in 2017.509

   WNISR2019 reported extensively on the economics of the Vogtle project. According to an expert testimony to the PSC on 5  June  2020,

   The Staff CTC [cost to complete] analyses, which ignore the [US]$8.1  billion already incurred by the Company [Georgia Power] as of December  31, 2019, indicate that it is economic to complete the Project if the Company adheres to its current construction cost and the November  2021 and November  2022 regulatory COD [Commercial Operation Date] forecasts. The Staff analyses indicate that it is not economic to complete the Project if there is a delay of 24  months or longer beyond the current regulatory CODs.510

   There were major doubts before 2021 that Georgia Power would meet its COD target dates, but they were confirmed during 2020–2021, including in relation to the start and completion of Hot Functional Tests  (HFT).511 In 2019, PSC staff had concluded that “at this time the status of the Project is uncertain,” with major uncertainties whether the target date of HFTs scheduled for Unit  3 on 31  March  2020 could be achieved.512 Fuel loading at that time was scheduled for 14  October  2020.

   On 30  April  2020, Thomas Fanning, CEO of Georgia Power, stated that, “cold hydro testing is planned to begin in June or July, with hot functional testing beginning in August or September.”513 This schedule changed again, when in June  2020, Southern announced that cold testing would take place “this fall” to then be followed by hot testing.

   Credit-rating agency Standard & Poor’s said in a statement:

   The unexpected, late-stage changes to these planned activities is credit negative for Georgia Power because it signals that challenges with the project continue, increasing the likelihood of additional cost overruns and further schedule delays.514

   HFT was then supposed to begin in January 2021 but was delayed and considered the primary cause for delay in commercial operation of the reactor. HFT of Vogtle-3 finally began on 25  April  2021 and was planned to be completed within 6–8  weeks.515 Apparently, Southern Company reported to investors on 29  July  2021 that HFT had been completed.516

   On 18 May 2021, Southern Company informed the Georgia Public Service Commission that delays in testing of the Vogtle-3 reactor would mean that operation would not start before January  2022, at the earliest.517 The Commission was told that Unit  3 was 98  percent complete.

   While COVID-19 impacted workers on the site, delays were also caused by the need to replace electrical components and other work that the “company decided wasn’t up to standard.” Georgia Power told Commissioners that there was evidence “that contractors were declaring work complete without testing for deficiencies, relying on inspectors to catch it and fix any problems later.” The company engaged in hot functional testing of the first reactor and encountered more expansion of metal parts as systems were heated up than anticipated. “There’s a chance we may need to make some adjustments to the structural supports” Stephen  Kuczynski, President and CEO of Southern Nuclear, told Commissioners of the thermal expansion issues. The PSC was then informed that the schedule for operation of Unit  4 was November  2022.518

   Georgia Power is currently expected to recover approximately US$3.9  billion under the Nuclear Construction Cost Recovery (“NCCR”) tariffs imposed on customers during the construction period. “This is nearly double the US$2.1  billion the Company would have collected if the Units had been completed in accordance with the certification schedule of 11  April  2016 and 2017.”519 Under the NCCR, Georgia Power is permitted to request to add US$8.0  billion to its rate base once Units  3 and  4 are in commercial service.

   Lawsuits Against the Vogtle Project

   Multiple lawsuits against the Vogtle project initiated have continued through the courts. In 2022, Oglethorpe and Municipal Electric Authority of Georgia  (MEAG) filed suits against Georgia Power to enforce the terms of the 2018 settlement that allowed the project to continue after Westinghouse’s bankruptcy and cost increases to US$25  billion.520 At issue is a dispute over the allocation of recent cost increases for the project. Oglethorpe and MEAG claim that cost increases have surpassed the threshold at which Georgia Power would begin absorbing 100  percent of the costs and taking a greater ownership share of the reactors. Georgia Power disputes their argument, claiming that the cost baseline should be US$1.3  billion greater than the US$17.1  billion amount Oglethorpe and MEAG claim. The disputes center on US$695  million in expenses for which Georgia Power has billed the two co-owners. In August  2022, JEA wrote to MEAG requesting that it exercises its option in the 2018 agreement to tender a portion of its ownership share of the reactors to halt further payments for cost increases. In order to do so, all 39 of MEAG’s member utilities must agree. JEA is not a member of MEAG and cannot vote on the matter but signed a contract with MEAG in 2008 for a stake in its share of Vogtle-3 and  -4. The fourth and smallest co-owner, Dalton Utilities, has not sued Georgia Power, but its board voted on 18  July  2022 to exercise its tender option and end its capital spending on Vogtle-3 and -4.521 Whatever the outcome of the Oglethorpe and MEAG suits, it is likely that Southern Company will begin assuming an increasing share in ownership of the project going forward. Georgia PSC may not permit cost recovery for the full amount of further cost increases, requiring Southern Company to pass those costs onto its shareholders.

   The most recent challenge to the Vogtle construction project was in May  2020, when the Blue Ridge Environmental Defense League  (BREDL) filed a challenge to an NRC License Amendment request from Southern.522 BREDL contends that, under the guise of a one-inch change in the seismic gap between two critical walls in the Vogtle Unit  3 reactor, Southern has admitted to a much more serious structural problem, the “dishing” of the nuclear plant’s concrete foundation which creates instability.523 Southern contends that it’s just a minor construction flaw, whereas BREDL expert witness, nuclear engineer Arne  Gundersen, stated “that the sheer weight of the nuclear island building is causing it to sink into the red Georgia clay.”524 During a preliminary oral hearing of Southern’s License Amendment request, the case was heard by the NRC’s Atomic Safety and Licensing Board  (ASLB) on 1  July  2020. On 10  August  2020, the ASLB issued Memorandum and Order, denying BREDL’s intervention, and dismissing the two contentions and terminating the proceeding.525 On 4  September  2020, BREDL filed with the NRC seeking Commission review of the ASLB decision.526 NRC denied the petition on 22  December 2020.527 BREDL filed a motion to reopen the proceeding on 7  December  2020528 and an amended contention on 28  December  2020,529 which NRC denied on 15  March  2021.530

   Vogtle Federal Loan Guarantees

   Under the terms of the Department of Energy (DOE) Loan Guarantee Program, owners of nuclear projects can borrow at below-market Federal Financing Bank rates with the repayment assurance of the U.S.  Government. DOE loan guarantees permitted Vogtle’s owners to finance a substantial portion of their construction costs at interest rates well below market levels, and to increase their debt fraction, which significantly reduced overall financing costs. In justification for the loan guarantee to Vogtle, the Obama administration stated in 2010 that

   the Vogtle project represents an important advance in nuclear technology, other innovative nuclear projects may be unable to obtain full commercial financing due to the perceived risks associated with technology that has never been deployed at commercial scale in the U.S. The loan guarantees from this draft solicitation would support advanced nuclear energy technologies that will catalyze the deployment of future projects that replicate or extend a technological innovation.531

   The loan-guarantee program has therefore played a critical role in permitting the Vogtle project to proceed but has failed to catalyze a nuclear revival, with no prospects of further new large nuclear plants being built in the foreseeable future. Oglethorpe Power Corporation  (OPC), which has a 30-percent stake in Vogtle, confirmed in August  2017 that it had submitted a request to DOE for up to US$1.6  billion in additional loan guarantees. The company already had a US$3  billion loan guarantee from DOE. 532 The other owners—Georgia Power and MEAG—had secured US$8.3  billion in separate loan guarantees from DOE since 2010, when they were approved by the Obama administration.533 Both companies confirmed in August  2017 that they were seeking additional loan guarantee funding.

   On 29 September 2017, DOE Secretary Perry announced approval of additional US$3.7  billion loan guarantees for the Vogtle owners, with US$1.67  billion to Georgia Power, US$1.6  billion to OPC, and US$415  million to MEAG.534 A decision on terminating the Vogtle project would raise the prospect of repayment of the previous US$8.3  billion loan to Southern.535 In April  2019, the DOE provided an additional loan guarantee of US$3.7  billion to Plant Vogtle construction, only the second loan guarantee issued under the Trump administration and the second to Plant Vogtle.536 This brought the total loan guarantees provided for the Vogtle project by the DOE to US$12.03  billion.537

   Criminal Investigations of Nuclear Power Corporations

   Since 2017, the U.S. Justice Department has opened three separate investigations against utility corporations over criminal activities related to nuclear power. The cases have resulted in indictments of executives, lobbyists, and state officials. The cases have been accompanied by additional lawsuits and state-level investigatory proceedings, and they have had political ramifications which appear to have had further impacts on the industry, economically, as well as legally and politically. This does not appear to have deterred the industry from continuing to engage in significant lobbying and political action even as the Justice Department continued corruption investigations involving nuclear corporations. Through enactment of the IIJA and IRA, the authorization of an unprecedented amount of federal direct support for commercial nuclear energy over the previous 12  months is testimony to the extent of political activity by the industry. In total, ten of the largest nuclear corporations and their major trade groups reported over US$58 million in lobbying expenses at the federal level in 2021.538

   Fraud Investigation and Prosecutions over V.C. Summer Project

   As reported in previous WNISR editions, the decision on 31 July 2017 by Santee Cooper and SCANA Corporation (the parent company of South Carolina Electric & Gas or SCG&E) to terminate construction of the V.C.  Summer reactor project has seen ongoing financial and legal fallout for the companies and ratepayers of South Carolina during the past five years. At the time of cancellation, the total costs for completion of the two AP-1000 reactors at V.C. Summer was projected to exceed US$25  billion—about 2.5 times the initial estimate.539 The conspiracy to deceive regulators and ratepayers, which has been revealed by federal investigations, was intended to allow SCANA to apply for numerous rate increases to help pay for ongoing reactor construction. The rate increases were “fraudulently inflated bills to customers for the stated purpose of funding the project,” according to federal filings.540 Under legislation passed by the South Carolina state Legislature in 2007541—but strongly opposed by civil society groups—construction costs for the V.C. Summer reactors were to be paid by state ratepayers.542 When SCANA was taken over by Dominion Energy in January  2019, it “committed to make extensive remedial efforts to redress ratepayers,” which was estimated to be approximately US$4  billion.543 Exactly what this means remains unclear, as under current plans Dominion will be charging South Carolina ratepayers an additional US$2.3  billion over the next two decades for the collapsed V.C. Summer project.544 The 8  June  2020 filing made it clear that Dominion will not be prosecuted, with a utility spokesman stating that “We have no further comment regarding this matter or the investigation”.545

   Executives from both SCANA and Westinghouse were found guilty of unlawfully withholding information for years about the failure of the V.C  Summer project both from regulators and shareholders.

   On 7 October  2021, former SCANA CEO Kevin  Marsh was sentenced to two years in prison after pleading guilty to charges of conspiracy to commit mail and wire fraud.546 Marsh was the first defendant to be sentenced, though three others have pleaded guilty to having participated in an illegal abuse of public trust by engaging in a deliberate plan to hide the extent of SCANA’s financial troubles at the nuclear project from the public, from regulators, and from investors in the publicly traded utility.

   The Director of Savannah River Site Watch (SRS  Watch) Tom  Clements stated that “The [US]$5  million fine is really like a traffic ticket to him… I assume he (Marsh) is going to suffer for two years in prison, but he really deserves a much longer prison sentence for what he’s done to the state of South  Carolina,” said Clements, who predicted more people will eventually be charged.547

   In the case brought against Carl Dean Churchman, former vice President of Westinghouse Electric Corporation and the director of the V.C. Summer project for the company, it was found that he was communicating “with colleagues from the Westinghouse Electric Corporation through multiple emails in which they discussed the viability and accuracy of (completion dates) and thereafter, he reported those dates to executives of SCANA and Santee Cooper during a meeting held on Feb.  14, 2017.”548 On 10  June  2021, Churchman pleaded guilty to the felony offence of lying to the FBI.549

   A parallel legal case, brought by the Securities and Exchange Commission (SEC) against SCANA executives, was settled in December  2020. They were accused of civil fraud in being at the center of a scheme that artificially inflated SCANA’s stock price in the period 2014–2017. The proposed settlement, announced by the SEC on 2  December  2020, requires SCANA to pay a US$25  million civil penalty, and SCANA and SCE&G to pay US$112.5  million in disgorgement plus prejudgment interest.550

   Acting U.S. Attorney Rhett DeHart stated in June 2021, “It’s clear that our investigation into the V.C.  Summer nuclear debacle didn’t end with the SCANA case,” he said. “Our office is committed to seeing this investigation through and holding all individuals and companies who participated in this fiasco accountable.”551

   The pace of developments in the investigation appears to have slowed, with no further indictments, convictions, or sentences since October 2021. On 9  May  2022, a procedural ruling was reported to clear the way for the trial of former Westinghouse Vice President Jeff  Benjamin in a sixteen-count felony criminal indictment.552 The court ruled that Benjamin could continue using an attorney who also represented another former Westinghouse executive who is cooperating with prosecutors. The trial of Benjamin may begin as soon as October  2022 as a result of the ruling.

   Ohio Corruption Scandal and Nuclear Subsidy Legislation

   “FirstEnergy’s core values and behaviors include integrity, openness,

   and trust. As an organization, we are redoubling our commitment to live up to these values and the standards that we know our stakeholders expect of us.”

   Steven E. Strah, FirstEnergy president and chief executive officer

   22  July  2021.553

   In July 2020, the speaker of the Ohio House of Representatives, Larry Householder, was arrested by the FBI on charges of racketeering. It was alleged at the time that he and his associates had set up a US$60  million slush fund

   to elect their candidates, with the money coming from one of the state’s largest electricity companies. (...) Prosecutors contend that in return for the cash, Mr. Householder, a Republican, pushed through a huge bailout of two nuclear plants and several coal plants that were losing money.554

   As a result of the leadership role of Householder, in 2019, legislation House Bill  6 (HB6)555 was passed and FirstEnergy’s Davis-Besse and Perry reactors were granted subsidies totaling US$1.05  billion of electricity customer money to support keeping their uneconomic units on the grid. The conspiracy was “likely the largest bribery, money-laundering scheme ever perpetrated against the people of the state of Ohio,” the U.S. attorney for the Southern District of Ohio, David  M.  DeVillers, said in a news conference in 2020.556 Householder pleaded not guilty. In the two years since, the scandal has escalated, leading to the admission of guilt by FirstEnergy, and the enactment of a bill in 2021 repealing the nuclear subsides and a profiteering ratemaking provision in HB6, while leaving a smaller subsidy program for two coal plants and provisions that effectively ended energy efficiency and renewable energy standards in place.557

   In October 2020, when FirstEnergy was still denying its guilt, it continued its efforts to prevent further disclosures, leading Miranda  Leppla, Vice President of Energy Policy for the Ohio Environmental Council Action Fund, to state, “FirstEnergy’s lack of transparency is a continuation from its resistance to prove it even needed the bailout it received in House  Bill  6, despite requests from lawmakers during HB  6 hearings.”558

   Tom Bullock, executive director of the Citizen Utility Board, warned that “Ohio consumers have been harmed by HB  6, and the damage gets much worse on January  1 [2021] when US$150  million [in] nuclear bailout charges kick in…FirstEnergy says it’s not complicit in alleged HB  6 bribery, but it’s using legal maneuvers to block transparency, deny consumer refunds, and keep nuclear bailout money. Consumers need PUCO [Public Utilities Commission of Ohio] to side with us and order FirstEnergy to cooperate.”559

   On 16 November 2020, FBI agents raided the home of PUCO Chairman Sam  Randazzo.560 He was appointed by Governor  DeWine in February  2019, prior to which he was a longtime lawyer for the utility industry. In mid-July  2021, it was disclosed that FirstEnergy admitted in a deferred prosecution agreement that it paid Randazzo US$22  million between 2010 and 2019, prior to his appointment to chair of PUCO.561 PUCO, also in November  2020, began an audit of FirstEnergy to see whether the company broke any laws or regulations regarding its interactions with an ex-subsidiary while the companies pushed to secure HB6.

   On 29 December 2020, the Ohio Supreme Court ordered a halt to electric utilities collecting monthly fees under HB6.562

   In March 2021, FirstEnergy informed Ohio regulators that it would refuse to refund customers US$30  million collected from revenue generated under the HB6 legislation.563 The Ohio Consumers’ Counsel had called on the Ohio PUCO to order FirstEnergy to “remedy what would be a miscarriage or perversion of justice” was the company to keep income from rate guarantees. “As we see it, the PUCO or the legislature shouldn’t allow FirstEnergy to walk away from the House  Bill  6 scandal with even a penny of Ohioans’ money, and certainly not with the US$30  million it charged consumers for recession-proofing,” the Consumers’ Counsel said in a statement.564

   On 31 March 2021, Ohio Governor DeWine signed House Bill 128, which permanently cancels nuclear power subsidies paid under HB6.565 FirstEnergy, also on 31  March  2021, reversed its previous position and agreed to refund US$26  million to consumers for charges it collected through HB6.

   On 22 July 2021, it was announced that FirstEnergy agreed to pay a US$230  million fine for bribing key Ohio officials in its efforts to secure the HB6 US$1-billion ratepayer-funded bailout for two nuclear plants. The U.S.  Department of Justice detailed that in court filings, FirstEnergy had admitted that

   it conspired with public officials and other individuals and entities to pay millions of dollars to public officials in exchange for specific official action for FirstEnergy Corp.’s benefit.

   FirstEnergy Corp. acknowledged in the deferred prosecution agreement that it paid millions of dollars to an elected state public official through the official’s alleged 501(c)(4) in return for the official pursuing nuclear legislation for FirstEnergy Corp.’s benefit.

   (…)

   FirstEnergy Corp. further acknowledged that it paid $4.3 million dollars to a second public official. In return, the individual acted in their official capacity to further First Energy Corp.’s interests related to passage of nuclear legislation and other company priorities.566

   The fine is the “largest criminal penalty ever collected, as far as anyone can recall, in the history of this office,” acting U.S.  Attorney for the Southern District of Ohio Vipal  Patel said.567 However, the fine is less than a quarter of the US$1  billion in earnings in 2020, and FirstEnergy’s stock price soared after the three-year deferred prosecution agreement was announced.

   The agreement with the Justice Department details how FirstEnergy bought key Ohio public officials—notably former Ohio House Speaker Larry Householder and former PUCO Chairman Sam  Randazzo—with millions of dollars funneled through the dark money group Generation  Now, controlled by Householder. Between 2017 and March  2020, FirstEnergy  Corp. and FirstEnergy  Solutions (which was spun off and reconstituted through bankruptcy as Energy Harbor) donated US$61  million to Generation Now.568 Householder led efforts to pass HB6 to bail out the nuclear plants and bankrolled a counter campaign to stop a ballot initiative that would have challenged HB6. The termination of Ohio subsidies for the two reactors at Davis-Besse and Perry did not lead Energy Harbor to issue any public statements indicating it might close the reactors, which are now owned by FirstEnergy Solutions’ creditors since the execution of the restructuring and spin-off through the bankruptcy settlement. With the advent of Congress enacting the IIJA and IRA, Energy Harbor’s reactors will effectively transition to relying on federal support for their continued operation.

   Exelon Corruption Investigation Involving Utility Rate-Setting and Nuclear Subsidies

   Federal investigators began a far-ranging investigation into corrupt practices in Illinois as early as 2014.569 The focus of the investigation on Exelon became evident in 2019 with subpoenas and search warrants being issued to two public officials, an Exelon lobbyist, and a staffer to the Speaker of the Illinois House of Representatives.570 In July  2020, prosecutors with the US Attorney’s Office for the Northern District of Illinois announced charges against the defendants and a deferred prosecution agreement (DPA) with Exelon subsidiary Commonwealth Edison (ComEd).571 ComEd paid a fine of US$200  million as a condition of the DPA. In November  2020, DOJ filed charges against two ComEd executives and two lobbyists/consultants.572 The charges involve jobs and contracts Exelon gave to associates of House Speaker Madigan, from 2011–2019. Specifically, the investigation centers on Exelon’s efforts to enact legislation in 2011 and 2016 worth billions of dollars in payments to its subsidiaries ComEd and Exelon Generation:

   • The 2011 Energy Infrastructure and Modernization Act  (EIMA) reformed Illinois utility ratemaking process to allow ComEd largely to set its own delivery rates with less scrutiny by the Illinois Commerce Commission, through so-called “formula rates.” A 2020 report estimates ComEd collected US$4.7  billion in excess revenue from 2011–2019.573
   • The 2016 Future Energy Jobs Act, which extended EIMA’s formula rates and included US$2.35  billion in “zero-emissions credits” over ten years for Exelon’s Clinton and Quad Cities nuclear power plants. Exelon had blocked legislation to repair Illinois’s renewable energy standard since 2014, demanding that the legislature enact subsidies for its nuclear power plants before fixing the renewable energy program. Householder played the key role in blocking legislation Exelon opposed and in orchestrating the FEJA compromise.

   The investigation culminated in the indictment of former Illinois House Speaker Michael  Madigan on 2  March  2022.574 Madigan held the Speakership of the Illinois House of Representatives for nearly 40  years and was long regarded as the most powerful political figure in the state. The 22-count indictment includes racketeering and bribery charges. Under a 2  August  2022 procedural ruling, Madigan’s defense must file pre-trial pleadings by 1  February  2023.575 The trial will not begin until later in 2023, at the earliest.

   Conclusion

   The number of reactors and annual nuclear generation continued to decline in the U.S. in 2021-22. With the closure of Palisades in May  2022, there were 92 commercial reactors operating as of mid-2022. Generation declined by 1.5  percent in 2021 and nuclear’s share of commercial electricity generation fell from 19.7  percent to 18.9  percent, its lowest level since the peak of 22.5  percent in 1995.

   While construction of Vogtle-3 and  -4 continued, so did cost overruns and schedule delays. Total project costs have now topped US$30  billion, with co-owners announcing their intent to cap their investments and, in the cases of Oglethorpe and MEAG, filing legal claims disputing the distribution of recent cost increases. The NRC approved first fuel loading for Unit  3, expected to start in October  2022. Grid connection dates for Vogtle-3 and  -4 are now projected for March  2023 and 4Q2023, respectively.

   Since WNISR2021 was published, the nuclear subsidy trend has continued. Illinois enacted a relatively modest, five-year subsidy for six reactors in September  2021. However, the U.S.  Congress has recently enacted significant subsidies and financing measures from which the nuclear industry stands to benefit. In November  2021, the Infrastructure Investment and Jobs Act included US$6  billion for a Civil Nuclear Credit grant program for existing reactors, and US$3.2  billion in grants for new reactor demonstration projects. In August  2022, the Inflation Reduction Act (IRA) included several provisions. A tax credit program for existing reactors may total US$30  billion or more over the next decade. There are also additional tax credits and loan guarantees for new reactors, as well as a new loan guarantee program for which existing reactors may be eligible.

   Three major corruption and fraud investigations involving both new reactors and nuclear subsidies continued in 2021–2022. Significant developments include the indictment of former Illinois House Speaker Michael  Madigan in the corruption investigation focusing on Exelon, and the initiation of trial proceedings for former Westinghouse executive Jeff Benjamin in the Summer-2 and  -3 fraud investigation, which may begin in October  2022.

   Fukushima Status Report

   Overview of Onsite and Offsite Challenges

   Introduction

   “Slow but steady” appears to be an appropriate description of the decommissioning process of the Fukushima Daiichi nuclear plant. Removal of spent fuel from Unit  1 and Unit  2 has not started yet. Investigations of fuel debris using specially designed robots inside the reactors 1, 2, and  3 continues and is making some progress, but there is still no clear prospect in dealing with the debris. For management of contaminated water, an IAEA expert team visited the Fukushima site and published a report on the release of treated water containing tritium and other radionuclides. The government plans to start the release to the sea next year, while public opposition remains strong. In June  2022, for the first time since the beginning of the disaster, some sections of the “difficult-to-return” areas were considered “safe to return”. But still, many residents have not returned and legal disputes over responsibility for the accident and compensation of victims continue.

   Onsite Challenges576

   Current Status of the Fukushima Daiichi Reactors

   Due to the continuous injection of water into Fukushima Daiichi Units  1–3, the temperatures of the Reactor Pressure Vessel  (RPV) and the Primary Containment Vessel  (PCV) were maintained within the range of approx. 15–30 degrees Celsius. Data gathered at monitoring posts at site boundaries between 30  March  and 25  April  2022 showed 0.336–1.078  microSievert  per hour (µSv)/h. As the radiation dose inside the reactor buildings is still extremely high, it is not possible to carry out measurements at all locations.

   The removal of spent fuel from the cooling pools of Units 4 and 3 was completed in December  2014 and February  2021 respectively.

   On 13  April  2022, drilling started to install an anchor in the reactor building of Unit  1. The anchor is designed to stabilize the large cover to be installed over the unit prior to spent fuel removal. In order to minimize radiation exposure to the workers, remotely operated anchor drilling equipment has been used.

   At Unit  2, ground improvement work preparing for the installation of the fuel removal gantry started on 28  October  2021 and was completed on 19  April  2022.

   Spent fuel removal from the pools is planned to start around FY  2024–2026 at Unit  2, and around FY  2027–2028 at Unit  1. It is currently expected that all spent fuel from both units will be removed by 2031.577

   A magnitude 7.4 earthquake occurred on 16  March  2022 in the same offshore area as the Great East Japan Earthquake in 2011. On 17  March  2022, TEPCO reported that the water level in the reactor pressure vessel of Unit  1 had dropped by 20  centimeters  (cm), and a robotic probe on 22  March 2022 found the water had fallen to a level 40  cm lower than usual. Water levels also dropped at Units  1 and  3 following a large earthquake in February  2021. In order to maintain water levels, the water injection rate was increased. 578 On 29  March  2022, TEPCO confirmed that the water had reached the necessary levels.

   Internal investigation of fuel debris inside the reactor vessels of Unit  1, originally scheduled to start in FY  2019, was then planned to start on 12  January 2022, but again postponed to 4  February  2022 due to malfunctioning of the remotely operated vehicle (ROV). The investigation was finally suspended due to transmission loss of the mounted camera and other parts of the machine.

   Analysis of fuel debris samples taken from the inside of the pipe for joint standby gas treatment process  (SGTS) for Units  1 and  2—assumed to be the main gas transport route during the containment vent at the time of the accident—has resulted in limited useful for the investigation of the course of the accident.

   According to a recent study published in the Journal of Hazardous Materials by a team of scientists from Japan, France, Finland, and the U.S., most of the control rod boron remains in at least two of the damaged reactors (Units  2 and  3). This means that there will be less likelihood of a “criticality accident” during the removal of debris from the reactor.579 However, at present, there is no clear prospect when and how fuel debris could be removed from the damaged reactors.

   Contaminated Water Management

   Through various measures introduced by TEPCO, the generation of contaminated water has been gradually decreasing. The measures introduced include the pumping of water by sub-drains, the construction of land-side frozen walls, and rainwater-infiltration prevention measures including repairing damaged portions of building roofs etc. The amount of contaminated water generation within FY2021 declined to approx. 130  m3/day from over 500  m3/day before taking those measures. This means that still almost every week a new 1,000  m3 tank is still needed.

   Part of the radioactive substances that contaminate the water are being removed by a multi-nuclide removal equipment called Advanced Liquid Processing Systems  (ALPS). After the removal of most radioactive substances except tritium, treated water is being stored in tanks.

   As of 9 June 2022, about 1.3  million  m3 of treated water is stored in 1,020 tanks. There are currently 1,061 tanks on site. Reportedly, as of 28  July  2022, capacity saturation had reached 96  percent, and without adding any further storage, the tanks would be full by summer or fall of 2023.580

   27 tanks store water that has undergone strontium (Sr) removal. Strontium removal is carried out by cesium-absorption in three stages.

   ALPS is supposed to separate most of the radionuclides except tritium, so the concentration of other radionuclides remain below regulatory standards. However, due to malfunction and lower-than expected ALPS performance, of 1.3  million  m3 only 32  percent (about 412,000  m3) satisfies regulatory standards and two thirds (about 855,000  m3) of treated water need to be re-purified.581 (See Figure 43)

   According to a government decision of 13  April  2021, treated water containing tritium will be discharged into the ocean. TEPCO has been preparing the discharge plan as follows.582

   • Measurement and confirmation. The concentration of tritium, carbon-14, and 62 other radionuclides will be measured, and a third party should confirm that all concentrations remain below the regulatory limits for discharge.
   • Dilution. The treated water will be diluted further (at least 100 times) so that the tritium concentration after dilution should be below 1,500 becquerel per liter (Bq/L)583. Measuring results will be made public promptly.
   • Discharge. Treated water will be discharged via an undersea tunnel (about 1  km) in order to avoid recirculation into the seawater (cross-contamination) taken in for cooling purposes. In the near term, discharge amounts will be within the threshold of 22 trillion Bq per year, which was the regulatory limit for Fukushima Daiichi before the accidents. This amount will be reviewed as needed.
   • Abnormal Events. Discharge will be stopped if an abnormality is found, and two emergency isolation valves shall be installed for emergency shutdown.

   On 18  May  2022, Nuclear Regulation Authority (NRA) endorsed TEPCO’s plan to discharge treated water into the sea. The NRA concluded that the water discharge will help TEPCO secure space for facilities needed for future decommissioning work and lower overall risks to the Fukushima plant.584

   Before TEPCO can begin implementing the discharge plan, local consent will be needed based on a pledge made in 2015 that TEPCO would not discharge the water “without gaining an understanding from stakeholders”585. On 5  April  2022, a major fisheries group in Japan told Prime Minister Kishida that they still firmly oppose the discharge of treated water into the sea due to concern over negative impact on the industry.586

   In order to reduce public concern over the discharge plan, the Japanese government asked the IAEA to review the overall plan. The IAEA Task Force published its first report on 29  April  2022, saying: “TEPCO successfully incorporated prevention measures in the design of the [water dilution and discharge] facility as well as in the associated operating procedures…the doses to the assumed representative person are expected to be very low and significantly below the dose constraint set by the regulatory body (NRA).”587

   International concerns over the discharge plan remain. In July 2021, the Pacific Islands Forum Ministers Meeting declared themselves “deeply concerned over the implications” and noted

   the concerns surrounding the seriousness of this issue in relation to the potential threat of further nuclear contamination of our Blue Pacific and the potential adverse and transboundary impacts to the health and security of the Blue Pacific Continent, and its peoples over both the short and long term.588

   In April  2022, South Korean Representative Seo Sam-seok stated: “The contaminated water released into the ocean will spread across the entire Pacific Ocean in 10  years and affect almost all of our sea”.589

   The Japanese Government also tried to reduce international concerns over the discharge of treated water, by sending out monthly information sheets and by holding video conferences for foreign missions in Japan. For example, on 10  May  2022, the Japanese government held a video conference for all diplomatic missions in Tokyo590, and on 2  June  2022, a video conference was held for the Government of the Republic of Korea.591 Despite such efforts, there is no palpable indication that international concerns are disappearing.

   Worker Exposure Trend

   TEPCO publishes data on worker exposure every month since the Fukushima accidents began. According to the latest report for FY2021 (April  2021–March  2022),592 average dose rate for TEPCO employees (1,001  employees) was 0.85  mSv, while the average dose rate for contractors (5,860  contractors) was 2.77  mSv, resulting in the total average of 2.51  mSv. The maximum estimated dose in FY2021 for a TEPCO employee was 13.10  mSv while that for contractors was 17.45  mSv. As illustrated above, contractors typically receive about three to four times higher radiation doses than TEPCO employees. The average exposure for the first year (FY2011) was exceptionally high for TEPCO employees, but contractors received higher doses since FY2012 and afterward. Contractors constantly received higher doses for maximum exposure since FY2011 through FY2021 (see Figure 44). There are no epidemiological studies on worker health post-3/11.

   Offsite Challenges

   Current Status of Evacuation

   As of March 2022, 32,404 residents of Fukushima Prefecture are still living as evacuees, the number decreased from a peak of 164,865 in May  2012.593

   “32,404 residents of Fukushima Prefecture are still living as evacuees.”

   On 12  June  2022, the evacuation order was lifted for a district designated as “difficult-to-return” zone (an area with high level of radiation, meaning higher than 50 mSv  per  year) for the first time since the disaster began in 2011. Residents of Noyuki district, about 20  percent of the village called Katsurao, were forced to evacuate after the accident. Village officials say 82  people are registered as residents but only eight people from four households expressed an interest in returning.594 On 30  June  2022, the evacuation order was also lifted for the first time for a part of a town, Okuma, which hosts the Fukushima nuclear power plant. The areas were designated as “Special Zones for Reconstruction and Revitalization (SZRR)” and received special government funding.595

   As of February  2022, in the case of towns where the evacuation order was lifted for the whole municipal territory, rates of return have been relatively high; for example, Tamura City 84.6  percent, Naraha Town 62.2  percent, Kawauchi Village 82.6  percent. But for those where evacuation orders were only partially lifted the rate of return has been much lower; for example, Namie Town 11.2  percent, Iidate Village 29.6  percent, Tomioka Town 15.2  percent, Okuma Town 3.6  percent.596

   Food Contamination

   Nationwide inspections for food contamination continue, with a total of 41,361 samples analyzed in FY2021, according to data published by the Ministry of Health and Welfare, of which 157  samples (0.38  percent) exceeded the legal limits.597,598 In Fukushima Prefecture, 42  samples out of 14,053 (0.30  percent) were found to exceed legal limits, of which 29 were wild animal meat (wild boar, bear and pheasant) and only three  samples out of 4,390  fishery products monitored (0.07  percent) were exceeding legal limits. A surprising phenomenon is that in some other prefectures with much smaller numbers of samples, excessive contamination has a significantly higher share. For example, in Gunma Prefecture, only 842 samples were taken (2  percent of national total) but 33 were found exceeding limits (21  percent of national total). It is unclear, whether the post-3/11 food monitoring program is really representative.599

   On 8  February  2022, it was reported that Taiwan would relax a ban on Japanese food imports. Taiwan has banned imports of food products from five prefectures in Japan following the Fukushima accidents. Taiwan cabinet spokesperson said that the government had decided to make a “fair adjustment” to its ban, as so many countries have already lifted restrictions.600 On 29  June  2022, the U.K. government announced that it would also lift food import restrictions from Japan.601 Of the 54  countries that began imposing import restrictions (e.g.  banning Japanese food without certificate of origin or certificate of analysis for radioactivity) after the beginning of the disaster, as of February  2022, 14  countries continued implementing some additional import regulations for “vegetables and fruits”, 12  countries for “fishery products”, and five  countries for “rice” and “tea”.602

   Decontamination and Contaminated Soil

   The decontamination work for the Special Decontamination Area of Fukushima Prefecture under the direct control of the national government603 was completed in March  2018, and the decontamination work for relevant municipalities including the rest of Fukushima Prefecture604 was completed in March  2017 (this decontamination work did not include the Difficult-to-Return Zones). However, the reality is that decontamination has only been conducted over a small percentage (15  percent) of the overall contaminated land area.605

   The biggest issue is what to do with the huge amount of contaminated soil shipped to provisional storage sites. The government designated a total of 1,600 ha of area as “interim storage site”, and as of May  2022, close to 80  percent of the area (1,273  ha out of 1,600  ha) had been purchased from some 1,800  local landowners for the establishment of a storage facility.606 As of the end of May  2022, a total of about 13  million  m3 of contaminated soil had been transferred to such interim storage facilities.607

   The law stipulates that the government is responsible for disposing of the waste at a final disposal site outside Fukushima Prefecture, to be carried out by a company wholly owned by the government within 30  years after starting the interim storage of the waste.608 However, at present, the government has taken no specific action towards final disposal of contaminated wastes generated due to the Fukushima disaster. The government plans to reuse some of the contaminated soil which was qualified as “below regulatory standards” and started the demonstration program. It plans to issue guidelines by FY  2024. But not a single prefecture backs such reuse plan.609 It shows that there is still a lack of public trust in the government plans. Still, as of March  2022, 830 locations in six municipalities in Fukushima are hosting “temporary” storage sites for 8,460  m3 of contaminated soil waiting for shipping to an interim storage site. As reported by Asahi Shimbun, a key reason for the repeated delays is that “new houses were built on land where contaminated soil was buried as negotiations over storage sites in many communities dragged on. This accounts for about 50 percent of the cases cited by municipalities in a survey by the prefectural government last September [2021]”.610

   Health of Residents, Legal Cases, Compensation

   There are a large number of legal cases related to the Fukushima disaster (for background, see  Judicial Decisions on Damages and Criminal Liability for the Fukushima Nuclear Accidents in WNISR2021) including the following recent ones:

   • In January 2022, a group of six men and women, aged between 17 and 27, diagnosed with thyroid cancer as children, filed a class action suit against TEPCO, seeking US$5.4  million in compensation. This is the first such case which seeks to clarify the relationship between illnesses developed by residents from the vicinity of the Fukushima Daiichi power plant and the 3/11 nuclear disaster. Due to the treatments of thyroid cancer (reportedly, two of the persons had one side of their thyroid removed and four are planning or undergoing radiation therapy), they had to drop out of school or college. They argued that the cancer prevented them from having a normal education or employment as well as marriage and a family life. The Japanese government position on this issue is that there is no causal link between exposure to radiation from the accident and the thyroid cancer developed among children living near the Fukushima plant.611 The position is highly controversial (for background, see Health Effects of the Fukushima Daiichi Nuclear Power Plant Disaster in WNISR2021).
   • On 4  March  2022, Japan’s Supreme Court ordered TEPCO to pay compensation of 1.4  billion  yen (US$12  million) to about 3,700  people whose lives were heavily impacted by the Fukushima disaster, equating to an average payout of about 380,000  yen (US$3,290) per plaintiff. This is the first Supreme Court decision on accident compensation.612
   • Following the March ruling, on 10  June  2022, the Supreme Court dismissed claims that the Japanese Government is also responsible for the accident and should therefore pay compensation to these 3,700  people. The decision by the Supreme Court was the first one to judge potential government responsibility for the accident. The decision covered four lawsuits filed in Fukushima, Gunma, Chiba, and Ehime Prefectures.613
   • On 2  June  2022, the Koriyama branch of the Fukushima District Court ordered TEPCO to pay a total of 73.5  million  yen (around US$566,000) to current and former residents of Tamura City. But the 525  plaintiffs, who sought 11  million  yen per person (about US$85,000 per person) from TEPCO as well as the Japanese Government, are considering an appeal to higher court, as the court did not acknowledge the responsibility of the government, similar to the decision by the Supreme Court described above.614
   • On 13  July  2022, the Tokyo District Court ordered four former executives of TEPCO to pay 13  trillion  yen (US$95  billion) in damages to the operator of the Fukushima Daiichi nuclear power plant. The case was brought by TEPCO shareholders, and the ruling was the first time a court has found former executives responsible for the nuclear accident. The four have appealed the court ruling.615 The criminal case against three of these four former executives had resulted in their acquittal in 2019.616

     Conclusion

   Eleven years have passed since the Fukushima nuclear disaster began. Although there has been some steady progress in decommissioning and food safety, many onsite and offsite challenges remain.

   Onsite, little progress was made in removing the remaining spent fuel from cooling pools and in the investigation of debris removal options. Public trust in TEPCO and the government has not been restored and has been further stressed considering the difficulties with water treatment.

   

   Sources: TEPCO Holdings, “Treated Water Portal Site”, September  2021.617

   Note: This chart shows that two thirds of ALPS-treated water require a second or additional treatments to make sure that all radionuclide concentrations remain below regulatory limits, as current contamination levels exceed limits by several to up to almost 20,000 times.

   Offsite, according to sample measuring results, food contamination has been significantly reduced and the number of countries banning the import of Japanese food has also declined. And for the first time, the evacuation order was lifted for a part of the area designated as “difficult-to-return”. Only a fraction of the residents has returned, and the management of contaminated soil will likely take a long time. Finally, legal fights over the compensation of victims continue. In short, the Fukushima disaster is still underway.

   

   Source: TEPCO, 2022618

   Decommissioning Status Report 2022

   Introduction

   At the end of 2021, the number of closed power reactors exceeded 200 for the first time. Decommissioning nuclear power plants is an important element of the nuclear power system. Defueling, deconstruction, and dismantling—summarized by the term decommissioning—are the final steps in the lifetime of a nuclear power plant (excluding waste management and disposal). The process is technically complex and poses major challenges in terms of long-term planning, execution, and financing. Decommissioning was rarely considered in the reactor design, and the costs for decommissioning at the end of the lifetime of a reactor were usually expected to be discounted away, and thus, subsequently, largely ignored. However, as an increasing number of nuclear facilities either reach the end of their operational lifetimes or have already been closed, the challenges of reactor decommissioning are increasingly attracting stakeholder and public attention.

   Elements of National Decommissioning Policies

   When analyzing decommissioning policies, one needs to distinguish between the process itself (in the sense of the actual implementation), and the financing of said process. The technical procedure can generally be divided into three main stages, which are briefly described hereunder (for more details, see  WNISR2018).

   • The warm-up stage comprises the post-operational stage and the dismantling of systems that are not needed for the decommissioning process. In addition, the dismantling of higher contaminated system parts begins. An indicator for the progress of this stage is the defueling of the reactor, as it is crucial for further undertakings: defueling means removing the spent fuel from the reactor core and the spent fuel pools.
   • The hot-zone stage comprises the dismantling activities in the hot zone, i.e. dismantling of highly contaminated or activated parts, e.g. the reactor pressure vessel  (RPV) and its internals  (RVI) as well as the biological shield.
   • The ease-off stage comprises the removal of operating systems as well as the decontamination of onsite buildings. Ideally, this stage ends with the demolition of the buildings and the release of the reactor site as a greenfield site for unrestricted use. Some countries also permit the release as a brownfield site, which means that the buildings can also be further used, for nuclear or other, mostly industrial purposes.

   This technical procedure can begin after varying amounts of time after reactor shutdown. This depends on the strategy the operator chooses. These include:

   • immediate dismantling, that is characterized by a rapid beginning of decommissioning activities after closure,
   • deferred dismantling, where reactors are placed into Long-Term Enclosure (LTE) for several decades to allow for radiation levels to decline before decommissioning begins, and
   • entombment, characterized by LTE (50  years or more) that can become permanent.

   One of these strategies or a mix of them have been adopted by most countries, although some have placed restrictions, such as France or Germany.619

   With respect to financing, four main approaches are observable: Public budget, external segregated fund, internal non-segregated fund, and internal segregated fund (for more details, see WNISR2018).

   Global Overview

   Decommissioning Worldwide

   As of 1 July 2022, worldwide a total of 204 reactors, corresponding to 97.4  GW of capacity, have been closed. Since WNISR2021, eight additional reactors (6.1  GW) have been closed: two in the U.K., three in Germany and one each in Russia, Pakistan and the U.S.

   Of the total number of closed units, 123 (60  percent) are located in Europe (98  in Western  Europe and 25 in Central and Eastern Europe), followed by nearly a quarter of the total in North  America  (47) and one sixth in Asia (34).

   Almost four in five or 160  reactors used three technologies:

   • Pressurized Water Reactors (PWRs) with 64  units or 31  percent,
   • Boiling Water Reactors (BWRs) with 54  units or 26  percent, and
   • Gas-Cooled Reactors (GCRs) with 42 units or 21 percent, of which the majority (31 units) are located in the U.K.

   Table 10 provides an overview of the closed reactors worldwide. Compared to WNISR2021, the table also includes the number of defueled reactors, and those that have been released from regulatory supervision, i.e. where a full greenfield situation has been re-established.

6. Table 10 - Overview of Reactor Decommissioning Worldwide (as of July 2022)

   Country	Closed Reactor	Post- Operational Stage(a)	Decommissioning Status
   			Warm-up (of which Defueled)	Hot-zone	Ease-off	LTE	Completed (of which Released	Completed Share (of which Released)
   U.S.	41	1	7 (7)	3	1	12	17 (6)	41% (15%)
   U.K.	34	4	13 (11)	9	0	8	0	0%
   Germany	33	2	8 (5)	9	9	1	4 (3)(b)	12% (9%)
   Japan	27	0	26 (4)	0	0	0	1 (1)	4% (4%)
   France	14	0	4 (1)	2	0	8	0	0%
   Russia	10	1	0	0	0	9	0	0%
   Sweden	7	0	3 (1)	4	0	0	0	0%
   Canada	6	0	0	0	0	6(c)	0	0%
   Bulgaria	4	0	4	0	0	0	0	0%
   Italy	4	0	3 (2)	1	0	0	0	0%
   Ukraine	4	0	0	0	0	4(d)	0	0%
   Slovakia	3	0	1 (1)	2	0	0	0	0%
   Spain	3	0	1	0	1	1	0	0%
   Taiwan	3	1	2	0	0	0	0	0%
   Lithuania	2	0	2 (2)	0	0	0	0	0%
   South Korea	2	0	2	0	0	0	0	0%
   Armenia	1	0	0	0	0	1(e)	0	0%
   Belgium	1	0	0	0	1	0	0	0%
   India	1	0	1 (1)	0	0	0	0	0%
   Kazakhstan	1	0	0	0	0	1	0	0%
   Netherlands	1	0	0	0	0	1	0	0%
   Pakistan	1	1	0	0	0	0	0	0%
   Switzerland	1	0	1	0	0	0	0	0%
   Total	204	10	78 (35)	30	12	52	22 (10)	11% (5%)

   Sources: Various, compiled by WNISR, 2022

   Notes:

   (a)  -  Many recently closed reactors have not officially begun with decommissioning and are in a so-called “post-operational stage”. These are Brokdorf and Grohnde in Germany, Kursk-1 in Russia, Kuosheng-1 in Taiwan, Dungeness  B-1 &  -2 and Hunterston  B-1  &  -2 in the U.K. and Palisades in the US.

   (b) - Contrary to the categorization in previous WNISR editions that counted Gundremmingen-A to be fully decommissioned, the plant should rather be placed into the “Ease-Off-Stage” of decommissioning, as work is still ongoing.

   (c) - Contrary to categorization in previous WNISR editions, the Douglas Point only reached the warm-up stage in August 2022, thus as of July 2022, Canada does not count any reactor beyond LTE.

   (d)  -  With the “New Safe Confinement” being completed at Chernobyl-4, this reactor is now categorized as LTE.

   (e)  –  Contrary to previous WNISR editions, the Armenia/Metsamor-1 reactor is categorized as LTE.

   Decommissioning plays an increasing role in nuclear politics, both in timing and the production process, as well as the financing thereof. The numbers of reactors in active decommissioning will increase significantly: not taking into account the 110  reactors which started operating before 1982, assuming a 40-year average lifetime, a further 158 reactors will close by 2030 (reactors connected to the grid between 1982 and 1990); and an additional 143 will be closed by 2062. This does not even account for an additional 29  reactors in Long-term Outage  (LTO) and 53  reactors under construction as of mid-2022.

   Overview of Reactors with Completed Decommissioning

   As of mid-2022, 182 units are globally awaiting or in various stages of decommissioning, five more than one year earlier (Gundremmingen-A in Germany was previously incorrectly considered as fully decommissioned).

   Since WNISR2021, three reactors—all in the U.S.—have completed the technical decommissioning process. As WNISR2022 has corrected the status of one German reactor from “completed” to “ease off”, the number of completed units totals 22.

   Humboldt  Bay, a small BWR with 63  MWe capacity, located in California and closed in 1976, was declared fully decommissioned in late 2021.620 The site has not yet been released from full regulatory control, as spent fuel is still located in an on-site interim storage facility.621 The two 1040  MWe PWRs at Zion, Illinois, are awaiting final approval of their license termination applications by the U.S.NRC.622 Technical decommissioning work was completed at both units in 2020.623

   Of the 22 decommissioned reactors, only 10 have been returned to greenfield sites. The average duration of the decommissioning process, independent of the chosen strategy, is around 21  years, with a very high variance: the minimum of six years for the 22-MW Elk River plant, and the maximum of 45  years for the 63-MW reactor at Humboldt Bay, both in the U.S.

   Only three countries amongst the 23 with closed nuclear power reactors have completed the technical decommissioning process of at least one reactor: the United  States  (17  units), Germany  (4), and Japan  (1). Some of the U.S. reactors are amongst the most rapidly decommissioned. In Germany, the HDR (Heißdampfreaktor, a superheated steam reactor) Großwelzheim was only on the grid for one year, but decommissioning lasted well over 20  years. Würgassen has de facto completed the technical decommissioning process but, legally, cannot be released from regulatory control as buildings are used for interim storage of wastes.624 Gundremmingen-A, erroneously classified as fully decommissioned in previous WNISR editions, has in fact not yet completed the process as demolition work is still ongoing and expected to be finalized only in the early 2030s.625 In Japan, the only reactor decommissioned was a small 10  MW demonstration plant, whereas none of the large commercial reactors has yet been decommissioned.626 Figure 45 provides the timelines of the 22  reactors that have completed the decommissioning process.627

   

   Sources: Various, compiled by WNISR, 2022

   Note:

   Contrary to the categorization in previous WNISR editions that counted Gundremmingen-A to be fully decommissioned, the plant should rather be placed into the “Ease-Off-Stage” of decommissioning, as work is still ongoing.

   Overview of Ongoing Reactor Decommissioning

   This section contains a brief overview of the decommissioning status in the countries that are not covered in the subsequent case studies.

   Following a partnership agreement with the European Union, the Armenian Medzamor  (or Metsamor) nuclear power plant is to be completely closed as soon as possible due to significant safety concerns.628 Unit  1 was already closed in 1989 after an earthquake. A pilot decommissioning project by Rosatom subsidiary Nukem Technologies, EWN and WorleyParsons is currently underway.629 Unit  2 is scheduled to operate until September  2026.630

   In Belgium, the only reactor currently undergoing decommissioning is the prototype 10  MW reactor BR-3 in Mol. The reactor, closed in 1987, has recently entered the ease-off stage and is used as a lead-and-learn site for future decommissioning projects.631 Currently, the Belgian legislation calls for the closure of all seven operational reactors at Doel and Tihange until the end of 2025 and estimated decommissioning costs of €18  billion (US$18.82  billion).632 In March  2022, however, the Belgian administration decided to initiate negotiations with the operator to extend operational lifetimes of Tihange-3 and Doel-4 until 2035 (see section on Belgium).633

   Four PWR-type reactors of the VVER V-230 design are currently undergoing decommissioning in Bulgaria (Kozloduy  1–4). At all four units of Kozloduy nuclear plant, turbine hall dismantling was completed in 2019.634 Since then, not much progress has been made. Preparations and detailed plans for reactor dismantling are to begin in 2022. 635

   Rajasthan-1 in India—placed in LTO status since 2004 and since 2014 considered as closed by WNISR—has been completely defueled and is currently “maintained under dry preservation”.636 WNISR considers the reactor in the warm-up-phase.

   Decommissioning has been underway since 1998 at Aktau BN-350,637 a sodium-cooled fast reactor in Kazakhstan. The reactor is being prepared for LTE, expected to last for 50  years.638

   In the Netherlands, the 55 MW reactor Dodewaard was placed in LTE for forty years in 2005 with the aim to return the site to a greenfield status.639

   In August 2021, Pakistan closed its first reactor KANUPP-1, a 90-MW CANDU reactor that had been operational for 50 years.640 No indication of a decommissioning strategy has been communicated.

   Slovakia’s decommissioning efforts are advancing, with reactor pressure vessels having been removed in late 2021 at Bohunice-1  and  -2, two PWR-type VVER V230 design reactors also jointly called Bohunice  V1), by Slovakian company JAVYS and a Westinghouse-led consortium.641 Completion of Bohunice  A1 decommissioning, a 93-MW heavy water GCR-type reactor, is scheduled for 2033.642

   Sweden’s latest reactor closures at Ringhals nuclear power plant occurred in 2020. Both reactors at the site are currently in the warm-up stage. Actual decommissioning work is set to begin in the third quarter of 2022 and to be conducted by Westinghouse.643 The first Swedish reactor, Ågesta, was closed in 1974 and subsequently defueled.644 The plant was used as a training facility until 2020, when Westinghouse was tasked with its dismantling.645 Reactors at Barsebäck and Oskarshamn are currently in the “hot-zone”. At Barsebäck-1, the reactor pressure vessel was successfully dismantled in late 2021.646 At Barsebäck-2 the vessel was dismantled by Westinghouse in 2018.647 Reactor internals at Oskarshamn were dismantled for both reactors in 2019 by GE Hitachi Nuclear Energy.648 Decommissioning work is scheduled to be completed by 2028 at both nuclear power plants.649

   Switzerland has limited decommissioning experience, having completed technical decommissioning at the research reactor Lucens in 2004.650 Decommissioning of the commercial reactor at Mühleberg began shortly after its closure in 2019. Hot-zone works are expected to last from 2025 to 2030 and plans indicate decommissioning to be completed in 2034.651

   In Taiwan, nuclear reactors are being progressively closed with Kuosheng-1 being the latest closure in 2021.652 Mid-2021, operator Taipower submitted the application to cease operation at the Maanshan nuclear power plant by 2025.653 Decommissioning of all Taiwanese reactors (including still operational reactors) is to be completed by 2043,654 but at Chinshan-1 (closed in 2014) delays occurred already in 2018 due to belated approval of onsite dry storage facilities.655 No further information on the potential revision of the decommissioning plans at Chinshan-1 and  -2 has been published.656 Taipower considers that decommissioning procedures last 25  years upon issuance of the decommissioning permit, which the Atomic Energy Commission granted on 12  July  2019. Taipower announced it had initiated decommissioning work when the license became effective on 16  July  2019.657

   In Ukraine, work at the four reactors of the Chernobyl plant is continuing. Chernobyl 1–3 are currently being defueled658 and will be placed into LTE following the chosen deferred dismantling strategy.659 The New Safe Confinement for Unit 4 was completed in 2016.660

   Country Case Studies

   Decommissioning in selected countries

   This section provides an update of decommissioning development reviews in eleven major countries: the U.S., Germany, Japan, Spain, the U.K., France, Italy, Lithuania, South  Korea, Canada, and Russia. As in previous years, decommissioning projects encounter delays as well as cost increases. This section provides information on developments since WNISR2021. WNISR2022 counted 146  reactors currently in the different decommissioning stages (or in LTE) in these 11 countries; this represents around 85  percent of all closed reactors. Of these, 66 are currently in the “warm-up stage”, 24 reactors in the “hot-zone -stage”, and 11 are in the “ease-off stage”.

   The early nuclear states U.K., France, Russia, and Canada are yet to fully decommission a single reactor. Initially, the U.K. and Russia put all their closed reactors into Long-term Enclosure  (LTE), postponing decommissioning into the future. The U.K. has since changed its strategy and has begun earlier decommissioning for its extensive GCR fleet. WNISR counts a total of 52  reactors in LTE worldwide, 45  located in the 11  countries.

   

   Sources: Various, compiled by WNISR, 2022

   Notes:

   After a decommissioning strategy change, the U.K. has begun to move reactors from LTE to various stages of decommissioning. This figure does not include Canada and Russia, with no reactors beyond LTE.

   Contrary to the categorization in previous WNISR editions that counted Gundremmingen-A to be fully decommissioned, the plant should rather be placed into the “Ease-Off-Stage” of decommissioning, as work is still ongoing.

   Figure 46 reflects the slow progress that the global decommissioning industry is making. Over the past four years, few reactors have moved on in their decommissioning processes. Most notably, the U.K. has changed its initial LTE approach for its GCR Magnox fleet to a more short-term dismantling approach. Germany is also making progress, with the last three still operational reactors scheduled to close by the end of 2022. In the U.S., work in the hot-zone began at four reactors. For further details, see the following Case Studies.

   United States

   The U.S. has not only the largest fleet of operating (92) and closed reactors but also the highest number of decommissioned units representing nearly three quarters of the global total.

   In the U.S., as of mid-2022, 41 reactors (20  GW) have been closed.661 By 2050, at least 100 reactors are likely to undergo decommissioning. Of the 41 closed reactors (21 PWR, 14  BWR, 2  HTGR, 1  FBR, 1  PHWR, 2  others)662, 17 or 7.1  GW have been decommissioned. Currently, decommissioning work is ongoing at 11 units:

   • Seven reactors are in the warm-up stage: Crystal River-3, Indian Point-2 &-3, Kewaunee, San Onofre-2  &  -3 and Vermont  Yankee;
   • Three reactors are in the hot-zone stage: Fort Calhoun-1, Oyster  Creek and Pilgrim-1;
   • One reactor is in ease-off stage: San  Onofre-1.

   Since mid-2021, some progress was made in the U.S. where one additional reactor was closed. Most notably, three reactors completed their technical decommissioning. Humboldt  Bay was fully decommissioned in 2021, and all land—except for the on-site interim spent-fuel storage-facility—has been released for unrestricted use.663

   Zion-1 and  -2 (work completed in 2020) are however still awaiting delicensing decisions by the NRC for unrestricted use (as is LaCrosse).664

   Furthermore, three reactors have moved into the hot-zone-stage.

   At Fort Calhoun, initial plans were changed from deferred to direct dismantling, with the aim of completing the task by 2026.665 As of February  2022, reactor pressure vessel segmentation was underway.666

   Prior to the acquisition of Oyster Creek by Holtec, Exelon had opted for a strategy involving LTE.667 In 2018, Holtec decided to directly dismantle the site,668 and was able to defuel the plant in 32  months.669 In parallel, several components have been demolished, such as the air ejection off-gas building or the torus water storage tank.670

   Pilgrim-1 was defueled in late 2021 and work has since begun to dismantle the reactor itself.671 The plant is to be fully decommissioned by 2027 and is also operated by Holtec.672

   In April 2022, the NRC approved the license transfer at Kewaunee reactor from Dominion Nuclear Projects to EnergySolutions. The transfer had been requested in May  2021 after the dry storage facility had already been transferred to EnergySolutions in 2018. Consequently, active decontamination and demolition work is expected to begin in 2022 and be completed by 2030.673

   The early shutdown of Palisades marks the latest reactor closure in the US. The plant was originally licensed to operate until 2031 but was taken off the grid in May  2022.674 In June  2022, Holtec became the owner of the plant and plans to complete decommissioning by 2041.675

   For the time being, decommissioning remains the responsibility of the operators, who tender out to specialized companies some of the work, especially in the hot-zone stage.676 It seems, however, that the new organizational model of selling the license to a decommissioning contractor (identified in WNISR2018) is increasingly popular and may even accelerate decommissioning (see WNISR2020 for more details). This “new” method consists of transferring the decommissioning license from the operator to a decommissioning contractor, mostly a waste management company, with the goal to reap efficiency gains through the co-management of the decommissioning process by a company owning disposal facilities. However, it is unclear whether this organizational model will resolve the financing issue or end up in the socialization of costs in the end.677

   Germany

   By the end of 2021, Germany had a total of 33 closed reactors the second largest closed fleet worldwide. It also has the second highest number of decommissioned units. The latest closures were Brokdorf, Grohnde (both operated by Preussen  Elektra) and Gundremmingen-C (operated by RWE) on 31  December  2021 after an average time of operation of 36  years.

   Of the larger commercial reactors, only the 640-MW Würgassen unit has de facto completed the technical decommissioning process. However, Würgassen cannot be released from regulatory control as buildings onsite are used for interim nuclear waste storage. Several commercial reactors have finalized the “Hot-Zone-Stage” and have moved on to the “Ease-Off-Stage”. Smaller prototype or demonstration reactors, HDR  Großwelzheim, Niederaichbach, and VAK  Kahl, have all been fully decommissioned and released from regulatory control. The prototype reactor THTR-300 is the only German reactor still in LTE. Recently closed plants Grohnde and Brokdorf are still awaiting approval of their decommissioning applications and are thus not yet placed into any stage. (See  WNISR2021 for further details on German nuclear decommissioning procedure.)

   Currently, two reactors are in post-operational stage and one in LTE, while decommissioning work is being conducted at 26 reactors:

   • Eight reactors are in the warm-up-stage: Biblis-A &  -B (both defueled), Grafenrheinfeld (defueled), Gundremmingen-B &  -C, Krümmel (defueled), Lingen (defueled) and Philippsburg-2;
   • Nine reactors are in the hot-zone-stage: AVR Jülich, Brunsbüttel, Isar-1, Mülheim-Kärlich, Neckarwestheim-1, Obrigheim, Philippsburg-1 and Unterweser;
   • Nine reactors are in the ease-off-stage: Greifswald 1–5, Gundremmingen-A, MZFR, Rheinsberg and Stade.

   Decommissioning has been underway at Gundremmingen since 1983. This nuclear power plant consists of two parts, with KRB  A or Gundremmingen-A, a BWR that was closed in 1977, and KRB  II, incorporating Gundremmingen-B and  -C, two BWRs commissioned in 1984 and 1985, respectively.

   Contrary to the categorization in previous WNISR editions that counted Gundremmingen-A to be fully decommissioned, the plant should rather be placed into the “Ease-Off-Stage” of decommissioning, as work is still ongoing. The site has been free of fuel since 1988 and most critical components have successfully been dismantled. In 2020, demolition at the reactor building continued and is expected to be completed sometime in the early 2030s. Individual buildings of the Gundremmingen-A site have been reassigned to KRB  II and are currently being used as a facility for dismantling and decontamination of components from KRB  II. Furthermore, the site includes an interim storage facility that is managed by BGZ (Gesellschaft für Zwischenlagerung mbH), the German state-run company for long-term waste management. A decommissioning license for Gundremmingen-B and  -C was granted in May  2021. With Gundremmingen-C only closed in December 2021, decommissioning work is expected to continue into the 2040s.678

   The Krümmel reactor was shut down in 2011. In 2015, the operator applied to the local authority in the state of Schleswig-Holstein to fully shutdown and decommission the plant. However, the permit has not yet been granted. During the application process, the operator planned to defuel the plant, which was achieved in late 2019. Whether the plan to decommission Krümmel by 2038 can be achieved, remains uncertain as the permission to fully begin decommissioning was originally expected to be granted in 2022. As a major step of the warm-up stage, defueling, was already completed, WNISR considers Krümmel to be in this stage, although a permit has not yet been granted.679

   Japan

   As of mid-June 2022, 27 reactors or 17.1  GW were permanently disconnected from the grid in Japan. Japan, one of the early adopters of nuclear power, has not completed decommissioning of a single commercial reactor. The only accomplished decommissioning project is the small 12-MW research reactor Japan Power Demonstration Reactor  (JPDR), released as a greenfield site in 2002 after having been used as a test site for decommissioning techniques.680

   The decommissioning of the Magnox reactor Tokai-1 has been ongoing since 2001, with turbines having been dismantled and plans to begin reactor dismantling in 2024 to complete decommissioning by 2030.681

   The decommissioning of Fugen ATR started in 2006 and is planned to be completed by 2034; work on Hamaoka-1 and  -2 began in 2009 and is to last until 2036.

   Genkai-1, Ikata-1, Mihama-1 and -2, Shimane-1, and Tsuruga-1 received their decommissioning licenses in 2017.682 The plans foresee the reactors to complete decommissioning in the mid-2040s, respectively mid-2050s for Ikata-1 and possibly Genkai-1.

   Fukushima Daiichi-5 and -6 as well as the Units 1–4 have no official completion target-date. Crucial next steps in the decommissioning process are spent fuel removal at Units 1–4, that will be completed when Unit  2 is defueled in 2026.683 Unit  5 and  6 are to be defueled by 2031.684 US-based engineering company Jacobs will assist TEPCO in decommissioning the site.685

   In 2019, U.K.-based company Cavendish Nuclear won a contract to support decommissioning of the Fast Breeder Reactor  (FBR) Monju. It is expected that work will last around 30  years and cost more than ¥375  billion (US$20193.5  billion).686 According to a media report, defueling at Monju was completed in April  2022.687

   In 2020, Kyushu Electric Power filed the decommissioning license for the Genkai-2 reactor with the Japanese National Regulation Authority  (NRA). Defueling of Unit  2 is expected to occur from 2026 to 2040. Kyushu Electric Power also requested approval to change of its ongoing decommissioning plan for Genkai-1, which would push back the completion target-date from 2043 to 2054. According to the operator, the reason for this is that the slowdown at Unit  1 would allow the decommissioning process to catch up with Unit  2, so that decommissioning works at both units could be carried out simultaneously.688 For the decommissioning of Genkai-1 and  -2, Kyushu operates a special account related to decommissioning, that, at the end of 2021, held approx. US$378  million.689

   At Ikata-1, decommissioning work began in January 2021, when the unit entered the first phase of decommissioning (fuel removal and dismantling of secondary system equipment), which is expected to go on until 2026.690 In October  2020, the NRA approved the decommissioning license for Ikata-2. Defueling of the reactor is scheduled to be carried out during the preparatory stage lasting ten years. Overall decommissioning should take 40  years.691

   Spain

   Spain defines its national policy for reactor decommissioning in the official, periodically updated “General Radioactive Waste Plan”. According to this strategy, all decommissioning and waste-management activities are developed by the state-owned radioactive waste-management company Enresa (Empresa Nacional de Residuos Radiactivos S.A.). While the LTE strategy is applied for the GCR Vandellos-1 (until 2028),692 all LWRs are bound to be directly dismantled to greenfield status.

   Spanish administration describes decommissioning and waste management as an essential public service and assigns these tasks to Enresa by law.693 Demolition work is underway at the José  Cabrera (Zorita) plant, while Enresa is still awaiting approval of its decommissioning documentation that was submitted in 2020.694 In June  2022, demolition of the turbine building, being the last large building on site, was completed.695 (See WNISR2019 for details on the decommissioning process in Spain.)

   United Kingdom

   The U.K. has a long history of nuclear power use resulting in a large fleet of 26  GCR Magnox reactors, now all closed. Two FBRs also belong to this this so-called legacy fleet. Since WNISR2021, many of these reactors were transferred from an LTE state to active decommissioning. The whole process of decommissioning is nevertheless expected to last until the 2130s, more than a century from now.696 After an initial approach of privatized decommissioning, the National Decommissioning Authority  (NDA) has reassumed control over recent years of all so-called Site Licence Companies  (SLC) that operate the different sites.697 At the most recently closed sites, all AGRs, Dungeness B-1 and  B-2 as well as Hunterston B-1 (all closed in 2021) and  B-2 (closed in 2022), defueling is expected to begin in 2022.698 These sites are currently still operated by EDF Energy who will conduct these initial tasks before transferring ownership to the NDA for further decommissioning.699

   Currently, 22 reactors are undergoing decommissioning.

   • Thirteen reactors are in the warm-up stage: Chapelcross 1–4 (all defueled), Dounreay  DFR, Dounreay  PFR, Dungeness  A-1 &  -2 (both defueled), Trawsfynydd-1 &  -2 (both defueled), Windscale (defueled), and Wylfa-1 &  -2 (both defueled);
   • Nine reactors are in the hot-zone-stage: Hinkley Point A-1 &  A-2, Hunterston  A-1 &  -2, Oldbury  A-1 &  -2, Sizewell  A-1 &  -2 and Winfrith.

   Eight reactors are currently in LTE.

   Sellafield  Ltd was the first SLC to be returned to full NDA ownership in 2016.700 This SLC is responsible for the clean-up at the Sellafield site, the largest, oldest, and most complex nuclear site in the U.K. This includes legacy fuel pools and storage ponds, as well as nuclear reactors Calder  Hall  1–4 (in LTE) and Windscale. Fuel from all nuclear reactors and legacy ponds will be transferred to Sellafield into interim storage. 701

   Milestones that are currently being worked on include the retrieval of bulk sludge and fuel from legacy ponds and silos, originally expected to be completed by the early 2030s702. Legacy oxide fuel was retrieved from Sellafield’s ponds in 2016. Legacy Magnox fuel that had been stored in fuel ponds at Sellafield was envisioned to be fully retrieved by 2025.703 However, . first removal of Magnox legacy fuel was achieved only in June  2022. According to staff on site, the task will take around 20 additional years to fulfil.704 Thus, whether the envisioned dates for milestone completion can be achieved remains to be seen.705Sellafield  Ltd plans to demolish the upper diffusion section of the Windscale  Pile Chimney  Number  1 and begin cleaning out the MAGNOX reprocessing plant. Both steps are to be completed by end-2023.706

   Magnox Ltd became an NDA subsidiary in 2019 and is responsible for decommissioning at Berkeley, Bradwell, Chapelcross, Dungeness  A, Harwell, Hinkley  Point  A, Hunterston  A, Oldbury  A, Sizewell  A, Trawsfynydd, Winfrith and Wylfa. The net capacity of these old MAGNOX reactors accumulates to approx. 4.5  GW. Winfrith, Trawsfynydd, and Dounreay, operated by U.K. Atomic Energy Authority  (UKAEA) and Dounreay Site Restoration Ltd  (DSRL), have been nominated as “lead and learn sites” to optimize the decommissioning strategy for the legacy fleet, including Calder  Hall at Sellafield, and determine best practices for the upcoming decommissioning of the GCR fleet operated by EDF  Energy. Thus, for Winfrith and Trawsfynydd, revisions of initial strategies concluded that some contaminated underground structures (e.g. subsurface portion of the biological shield) will remain in place and land will nevertheless be suitable for its next planned use. Each site operated by Magnox  Ltd will receive a revised decommissioning plan with milestone dates. These have however not yet been published for each site.707

   At the Dounreay site in northern Scotland, two reactors are to be decommissioned. These sites are managed by DSRL. The 15-MW Dounreay Fast Reactor  (DFR) was closed in 1977 and is to be fully dismantled by 2025. The 250-MW Prototype Fast Reactor  (PFR) was closed in 1994, and dismantling is scheduled to be completed by 2027. According to the schedule, defueling of both reactors should be completed by 2025. 708 Most fuel has now been reprocessed at the Sellafield reprocessing plant. Remaining fuel will be moved to Sellafield for interim dry storage following above-described timeframe.709

   EDF Energy is the owner and operator of all remaining nuclear power plants in the U.K. Of these, two sites, Dungeness-B (2  x  545  MW) and Hunterston-B (2  x  490  MW), have been closed. Since September  2018, Dungeness-B had been in a long-term outage (LTO) following safety inspections that exposed faster than expected decay of relevant, unreplaceable components. Thus, in June  2021, it was decided to defuel both reactors at Dungeness-B.710 After initially extending the lifetime of both reactors at the Hunterston-B site to 2023 with a +/- 2-year proviso in 2012, closure was recorded in November  2021 for the first reactor and in January  2022 for the second. Defueling is to begin in the course of 2022.711 Hinkley  Point B, a nuclear power plant consisting of two GCR reactors with a net capacity of 485  and 480  MW, respectively, was to be closed by the end of July  2022 (See also United Kingdom  Focus).712 In terms of decommissioning, the British government signed an arrangement with EDF Energy to transfer the ownership of its GCR fleet to the NDA after the plants have been defueled. This agreement includes a defueling performance-premium of up to £100  million (US$122.4  million) or the loss of the same amount if performance is deemed insufficient. Whether this amount will be able to incentivize efficient defueling and smooth transfer of sites into NDA custody, remains to be seen. The House of Commons’ Commission of Public Accounts remains skeptical as to the potential positive impact of this incentive.713 This arrangement was made specifically for EDF Energy’s British GCR fleet and excludes the PWR plant Sizewell B.714

   France

   The closed reactor fleet in France is diverse in comparison to the current largely standardized operational PWR fleet. In total, 14 reactors (8 GCR, 3 PWR, 1 HWGCR, 2 FBR) have been closed, corresponding to approximately 5.5  GW. Apart from the reactors at the Marcoule site, for whose decommissioning CEA is responsible as owner (G-2, G-3) or co-owner (Phénix, 20  percent of shares belong to EDF), all reactors are decommissioned by EDF. 715

   Despite France’s theoretical official strategy of as-fast-as-possible decommissioning, the process is advancing slowly.716 EDF is currently responsible for the decommissioning of six first-generation GCRs at Bugey, Chinon, Saint-Laurent, three PWRs (Chooz-A, Fessenheim-1 and  -2), one HWGCR at Brennilis  (EL-4) and the Superphénix FBR at Creys-Malville.

   In the years to come, EDF will also have to manage decommissioning activities of its large PWR fleet still in operation. When exactly these units will enter their respective decommissioning phases depends on decisions concerning lifetime extensions. EDF hopes to use the Fessenheim reactors as test sites to learn best practices that can then be applied to to-be-decommissioned PWR sites and reduce costs and necessary efforts for decommissioning.717

   The PWR reactor at Chooz-A was shut down in 1991 and has been undergoing decommissioning since 2007. Work on the reactor internal vessels was completed in 2021. Cutting of the pressure vessel is to start in 2023. EDF expects these tasks to be completed by 2024, when final decommissioning and decontamination can begin. The original plan issued in 2007 expected Chooz-A to be fully delicensed by 2047, but following a change of strategy, estimations had advanced the date to 2035. However, work has been delayed due to the impact of COVID-19. Due to the site’s unique location in a cave, unexpected difficulties have led to multiple cost increases, the last amounting to additional €77  million (US$81  million) in 2021.718

   For its six GCRs Chinon A-1, A-2 and A-3, Saint-Laurent-des-Eaux A-1 and  A-2, and Bugey-1, EDF in 2001 initially adopted a strategy of Long-term enclosure by flooding the reactor vessel with water and then performing decommissioning procedures underwater.719 However, due to France’s decommissioning strategy of as-fast-as-possible decommissioning and technical issues of underwater dismantling, EDF decided to change the strategy to in-air dismantling in 2016. Thus, initial targets for dismantling no later than 2031 have been scrapped. The French Nuclear Safety Authority ASN (Autorité de Sûreté Nucléaire) stated in 2021 that “EDF has not as yet provided any demonstrations such as to permit authorisation of the next stages in the decommissioning of the Chinon A1 and A2 reactors.”720

   EDF’s current plans include reactor internal vessel and graphite block removal at Chinon A-2 to begin in 2033 and last up to 2054. By 2035, all other reactors are scheduled to be placed into a “safe storage configuration” for decommissioning to commence by 2055.721 The French Nuclear Safety Authority ASN  (Autorité de Sûreté Nucleaire) however is opposed to this strategy as it would place decommissioning tasks well into the future and contradict the as-fast-as-possible decommissioning strategy.722 Thus, all GCRs must apply for new decommissioning decrees in 2022. Total decommissioning costs for all six GCRs have doubled and are now estimated at €6.6  billion (US$20226.9  billion).723

   The FBR reactor Superphénix at Creys-Malville has been undergoing decommissioning since 2006. Currently, reactor vessel internals are being dismantled. This is expected to be completed by 2026, with the target for the whole site to be released from regulatory oversight by 2038. Decommissioning costs are estimated at €1.8  billion (US$20221.9  billion). This marks a four-fold increase in costs since the beginning of decommissioning in 2006.724

   In 2011, the EL-4 reactor at Brennilis (Monts d’Arrée) received a partial dismantling license for parts outside the nuclear island. Since then, progress has been made such as spent fuel removal and machine room dismantling. EDF is currently awaiting approval to begin further work on the reactor itself. These operations are planned to be completed by 2040. In the 1990s, decommissioning provisions varied between €10–20  million (US$202210.5–20.9  million). Most recent estimates place total decommissioning costs for this one reactor at €880  million (US$2022919.6  million), about double the cost estimate when decommissioning began in 2011.725

   The two PWRs at Fessenheim were closed in 2020. EDF currently plans a five-year preparatory phase until the decommissioning license is obtained, which is expected in 2025. This includes fuel removal, scheduled to be completed in 2023. Furthermore, work has begun on the removal of replaced steam generators that were still stored onsite and their transfer to the Cyclife (an EDF subsidiary) recycling plant in Sweden. This is done to free storage capacities for the replacement steam generators that are still in the reactors and must still be dismantled.726

   Decommissioning of the FBR Phénix at Marcoule began shortly after its closure in 2009. After disruptions during the COVID-19-lockdown in 2020, work on fuel and equipment removal continued. A strategy change involving a new decommissioning license is to set the deadline for decommissioning completion to end-2023.727 The remaining GCR plants G-2 and G-3, also located at Marcoule, are currently in LTE after having been defueled and partly dismantled. Graphite removal was supposed to begin in 2020, but no indication on progress could be identified. The last documented target completion date for the steps of graphite removal and reactor dismantling was published in 2015 as sometime in the 2040s.728

   Italy

   In Spring 2022, Sogin, the Italian agency tasked with decommissioning all nuclear facilities in the country, announced that by the end of 2022, it will have completed 45  percent of physical decommissioning tasks.729 Sogin was able to release the first nuclear facility, fuel fabrication plant Bosco Marengo, to brownfield status in June  2022.730 However, of the four closed commercial nuclear reactors, only Garigliano, a 150-MW BWR, has made progress since WNISR2021 by moving into the hot-zone stage. Reactor internal dismantling work is currently being tendered, with contracts amounting to over €12  million (US$12.6  million).731 This work is scheduled to be completed by 2025.732 The other three reactors, Caorso, Enrico Fermi (Trino) and Latina, are still in the warm-up stage. At Latina, spent fuel pools are currently being decommissioned, originally expected to be completed by 2021.733 However, instead of completing radioactive sludge removal in 2019, as expected, this task was completed only in May 2022.734 Further pool decommissioning tasks include the removal of metallic structures and dismantling of the fuel pond basin. But, as of writing, no updates on the current plan have been published. 735 Dismantling of steam turbines at Enrico Fermi is reportedly underway, indicating some progress, although the task was supposed to be completed by 2021.736 All four plants are to be released as brownfield sites. Individual cost estimations to reach this stage range from €245  million  (US$2022256  million) for Enrico  Fermi (Trino)737 to €360  million (US$2022376.2  million) for Garigliano.738 (See  WNISR2019 and WNISR2020 for detailed information on decommissioning of reactors in Italy.)

   Lithuania

   In Lithuania, two reactors at Ignalina with 1185 MW each were closed in 2004 and 2009, respectively, following a pre-requisite engagement for Lithuania to join the European Union. Both reactor cores are defueled and in May  2021, the last spent fuel assemblies were removed from the pool of Unit  1 and transported to an interim dry storage facility. The complete removal of the spent fuel from Unit  2 was achieved in April  2022.739 The targeted decommissioning end-date was delayed repeatedly, and in 2011, it was postponed by a further nine years from 2029 to 2038. It is planned to decommission Ignalina to “brownfield” status.740 (For more details on decommissioning in Lithuania, see  WNISR2019.)

   South Korea

   South Korea is running a large nuclear program, including 24  operating reactors, one reactor in LTO, and three units under construction. As of mid-2022, two commercial reactors had been closed: South Korea’s oldest unit Kori-1, a 576  MW PWR, and Wolsong-1, a 661  MW Pressurized Heavy-Water Reactor  (PHWR). Wolsong-1 ceased generating power in May  2017 but was officially closed only in December  2019.741 In May  2020, the operator Korea Hydro  &  Nuclear Power (KHNP), applied for a license to dismantle Kori-1.742 No decommissioning progress was reported as of mid-2022.

   Canada

   In Canada, no commercial reactor has been decommissioned thus far. By mid-2022, six reactors (2.1  GW), of which five CANDU (CANadian Deuterium Uranium) reactors and one Heavy-Water Moderated Boiling Light-Water Reactor (HWBLWR) have been closed. Although some parts of the closed facilities have been dismantled, decommissioning has not even started on a single CANDU reactor. (For more details on the Canadian decommissioning process, see  WNISR2018.)

   Russia

   As of mid-2022, Russia has ten closed reactors with a combined capacity of 4  GW consisting of two different reactor types: seven first-generation Light-Water Gas-cooled Reactors (LWGR)—among them three RBMK Chernobyl-type reactors)—and three Soviet-style PWRs.

   In Russia, there was only little tangible progress in reactor decommissioning in recent years. At the most recently closed site, Kursk-1, which was closed in December  2021, decommissioning is still to commence.743 Considering the long-anticipated decommissioning duration of 50  years and unclear decommissioning strategies, WNISR considers the Russian reactors in LTE as long as there is no documented evidence of decommissioning progress or announcement indicative of another strategy being prepared. (See WNISR2019 for details on decommissioning in Russia.)

   Conclusion on Reactor Decommissioning

   Assuming a 40-year average operational lifetime—the current average age is 31  years—a further 158  reactors will have been closed by 2030 (reactors connected to the grid between 1982 and 1990); and an additional 143 will be closed by 2062. This does not even account for 110  reactors which started operating before 1982, additional 29  reactors in Long-term Outage (LTO) and 53  reactors under construction as of mid-2022. As was shown in previous issues of WNISR, financial and technical challenges of reactor decommissioning are often underestimated. With more and more reactors reaching the end of their lifetimes, this underestimation will likely bring costly consequences.

   “204 reactors have been closed. Of these, 172 are in some state of decommissioning and 22 have been fully decommissioned, although some are still awaiting release from regulatory control, and only 10 have been returned to greenfield conditions”

   Since WNISR2021, eight reactors have been closed. Of these, six are in Europe (three in Germany, two in the U.K. and one in Russia). The others are the KANUPP-1 reactor in Pakistan and Palisades in the U.S. At most of these sites, preparations for decommissioning work are still underway.

   Worldwide, as of July 2022, 204 reactors have been closed. Of these, 172 are in some state of decommissioning and 22 have been fully decommissioned, although some are still awaiting release from regulatory control, and only 10 have been returned to greenfield conditions, meaning they are available for unrestricted use.

   In Europe, the 123  closed reactors represent 60  percent of the world’s total and decommissioning efforts are advancing sporadically. The U.K. has changed its strategy and is slowly removing its legacy fleet from LTE status but estimates the return to unrestricted use for all sites to last well into the 22nd  century. France is also currently assessing the initially chosen strategy for its eight GCR reactors, further delaying progress possibly into the next century.

   The only countries to have fully decommissioned any commercial power reactors are the U.S.  (17), Germany  (4), and Japan  (1). The latest addition to the list is the 63-MW BWR at Humboldt  Bay, Illinois. This reactor was connected to the grid in 1963, closed in 1976 and has since then been undergoing decommissioning that was completed only in 2021. The machine generated power for 13  years, with decommissioning only accomplished 45  years after closure.

   Most of these decommissioned reactors have low power ratings, many of them are first generation designs, with an average capacity below 360  MW. On average, decommissioning work lasted for 20  years, sometimes years longer than operation.

   Since WNISR2021, a large number of reactors has entered the Hot-Zone Stage (15 in 2021 vs. 30 in 2022). Many of these reactors (9) are in the U.K. where decommissioning efforts have been accelerated after a strategy change. Germany is also conducting hot-zone operations at nine reactors. Other countries with reactors in the hot-zone are France  (2), Italy  (1), the U.S.  (3), Slovakia  (2), and Sweden  (4).

   Over the past year, many reactors have moved from Long-Term Enclosure (LTE) to the warm-up-stage. This results in 78  reactors currently in the warm-up stage, 26 of which are in Japan, followed by 13 in the U.K. For the time being, 52  reactors remain in LTE including 12 in the U.S., nine in Russia, eight in France, and eight in the U.K. Table 10 provides an overview of reactor decommissioning worldwide.

   Potential Newcomer Countries

   Bangladesh

   

   Construction of the twin VVER-1200 nuclear reactors is ongoing at Rooppur, which began in November  2017 and July  2018, respectively.744 As of October 2021, fuel loading of the first reactor was scheduled in the fourth quarter of 2023; Unit  1 is scheduled for grid connection the same year, and Unit  2 for 2024.745 The dates announced in July  2018 for commencement of commercial operations were 2023 and 2024 respectively.746

   There is, however, concern about the implications of the financial sanctions on Russia and the war in Ukraine, although Rosatom says “it does not see disruption in any of the commitments and work schedules in the project”.747 According to Rosatom executives, Russia has continued to ship equipment for constructing the plant without interruptions.748

   The Bangladeshi Government remains prudent. Nasrul  Hamid, State Minister of Power, Energy and Mineral Resources, has said that the government estimates demand in 2030 to be 40,000  MW of electricity and that the government was “working to ensure that we get the 40,000  MW [by] 2030 assuming that we may not get the 2,400  MW from the Rooppur nuclear power plant... If construction of the Rooppur nuclear power plant is hampered, possibly we will not see any problem in getting power from other backup coal projects and some renewable sources”.749

   There is widespread concern about the safety and security of the plant. In a survey conducted “across the country from October to December  2020” and published in December  2021, a majority of the respondents (54  percent) “expressed concerns over the safety, security, and sustainability” of nuclear power plants.750 The survey also found that only 28  percent felt that the “regulatory body of Bangladesh is competent and independent”, while 77  percent felt that construction will not be free from corruption. There have been media reports about corruption.751

   Even before the first two reactor units have been fully constructed, and the full costs ascertained, Bangladesh’s Prime Minister, Sheik  Hasina, has called for building a second nuclear power plant.752 There is already considerable over-capacity in the country, and the “capacity cost” payments—each year government pays power plant operators for installed capacity even if no electricity is generated—have reportedly increased by nearly 400  percent between 2010–11 and 2019–20.753 Much of the generation is based on fossil fuels, and renewables have not been prioritized.754 As of June  2022, the capacity of renewables was only 789  MW, mostly solar (555  MW of which 63  percent was in the form of off-grid systems) and hydro (230  MW).755 In 2021, according to BP, solar power contributed 450  GWh, wind energy contributed 5  GWh, and other renewables contributed 3  GWh; hydro (including large hydro) contributed 680  GWh.756

   Egypt

   On 29  June  2022, Russian state company Rosatom secured a construction permit for the first nuclear power reactor in Egypt,757 and on 20  July  2022, in spite of the ongoing war in Ukraine, construction was officially launched.758

   The Egyptian nuclear vision began in the mid-1950s with the establishment of the Egyptian Atomic Energy Commission (currently known as the Atomic Energy Authority). Egypt started to explore the possibilities of building nuclear power reactors in the mid-1960s and established the Nuclear Power Plants Authority  (NPPA) in the mid-1970s. Initial plans envisioned 10  reactors being operational by the end of the century.

   Despite discussions with Chinese, French, German, and Russian suppliers, little development occurred for several decades except for selecting, in 1984, Dabaa on Egypt’s Mediterranean coastline to host Egypt’s first nuclear power plant.759 Nuclear plans were suspended indefinitely after the 1986 Chernobyl disaster and only in 2006, under former President Hosni  Mubarak, came the announcement that plans were to be revived.

   Finally, in February  2015, Rosatom and Egypt’s NPPA signed a cooperation agreement, followed in November  2015 by an intergovernmental agreement for the construction of four VVER-1200 reactors at Dabaa, for a total installed capacity of 4.8  GW.760

   In May 2016 it was announced that Egypt had concluded a US$25  billion loan with Russia for nuclear construction, at three percent interest for 85  percent of the construction cost, to be paid back, starting on 15  October  2029, through the sale of electricity.761 In December  2017, the construction cost of the project was generally reported to be around US$30  billion. However, one Egyptian newspaper published an estimate as high as US$45  billion.762 Three other deals were signed to cover the supply of nuclear fuel for 60  years, operation and maintenance for the first 10  years of operation, and training of personnel.763

   The site chosen for construction lies about 300  km from Cairo at El-Dabaa city in the Governorate of Matrouh on the north-west coast of Egypt on the Mediterranean Sea. In March  2019, the NPPA was granted a site permit for the reactors, the first step toward getting a construction permit.764

   In 2018, AAEM—a joint venture of Atomenergomash and GE  Power—was set to supply the basic design of the four nuclear turbine islands, the turbine generators, including the Arabelle steam turbines, and technical expertise for installation and commissioning.765 In December  2019, Australian energy group Worley Limited was awarded a consultant contract to advise Egypt in the building process.766 In February  2020, Atomstroyexport, a subsidiary of Rosatom, announced that three Egyptian firms—Petrojet, Hassan  Allam, and The Arab  Contractors—had won a tender for the first phase of work on the plant, expected to begin in the summer of 2020 and continue through 2022.767

   In March  2021, Korea Hydro & Nuclear Power (KHNP) signed a cooperation agreement with Petrojet to provide support in “training of local technicians and experts in Egypt”,768 and was pre-authorized in January  2022, as sole bidder for the supply of some of the equipment of the turbine islands of the four units, consisting in the construction of main and auxiliary infrastructure and the procurement of equipment and materials.769 At the time, an agreement was to be reached by the end of April  2022,770 but there have been no updates since.

   In 2018, the Egyptian Government had projected that Dabaa Unit  1 would be commercially operating as of 2026 and subsequent units in 2028. This schedule was based on construction start in 2020, with the last unit entering its construction phase in July  2022.771 In compliance with the set targets, Anatolos  Kovatnov, head of engineering work at the El  Dabaa project, stated in December  2018 that Rosatom hoped to obtain the permits to start construction at the first unit of the Dabaa plant in July  2020.772 Abdel Hamid al-Desouky, Deputy Chair of NPPA, also suggested a construction permit could be issued by mid-2020.773

   However, the construction license application for Dabaa Unit  1 and Unit  2 was submitted to the regulator more than two years behind schedule, on 30  June  2021,774 while that of Units  3  and  4 was filed only on  30  December  2021.775 In early February  2021, TASS had indeed reported that both countries had agreed on an updated schedule in December  2020 since the pandemic “slowed down the preparation at the site” according to Russia’s Ambassador in Cairo, yet without providing any detail on the new timeline.776 The Egyptian Government later dismissed the idea that COVID-19 ever impacted the project.

   Contradictory statements on the potential impact of the pandemic continued and on 14  July  2021, the Egyptian Nuclear and Radiological Regulatory Authority  (ENRRA) was reported as stating that Dabaa will not be completed before 2030 due to the disruption caused by the coronavirus pandemic.777 Despite this, Electricity and Renewable Energy Minister Mohammed  Shaker stated two days later that the plant was not facing any obstacles and would begin operation in 2026, as planned.778 A four-year construction schedule is highly unrealistic, especially in a newcomer country, and indeed, on 28  July  2021, the postponement of full operation to 2030 was confirmed, with an expected licensing to occur mid-2022 and operation start of Unit  1 by 2028,779 which is coherent with information provided on NPPA’s website, anticipating a construction phase of five years and half—that would still be a remarkable achievement.780

   Mid-2021, media reports stated that the revised schedule reflected a halt in the implementation of the project caused by political tensions between the two countries.781 Both Rosatom and NPPA were prompt in putting out statements to deny the project suffered any difficulties or interruption.782 Just as fast, a delegation headed by Egyptian Minister of Electricity and Renewable Energy met with a Russian delegation providing Minister Mohammed  Shaker the opportunity to assure that the project had “full support of the political leadership of Egypt” and for the Head of Rosatom to “emphasise the importance of this project for Rosatom and Russia as a whole”.783

   While rumors of tensions between the two countries seemed to fade, it was announced in November  2021, that ENRRA had signed a US$1  million–contract with ÚJV  Rež, a Czech R&D company, for assistance in the licensing of Unit  1, with ÚJV  Rež describing the services to be provided as “mainly [focused] on independent control of documents and services supplied by the Russian side and on support activities for Egyptian supervision in a number of other areas  (...).”784

   As analysts and experts have emphasized, it is highly likely that the wider consequences of Russia’s ongoing war on Ukraine will impact the El-Dabaa project. Paul Sullivan, Senior Fellow with the Global Energy Center at U.S. Think Tank Atlantic Council wrote: “The strength of the constraints on this project (at Dabaa) by the sanctions is yet to be seen, but it could be considerable. This could slow down the project completion for many years. The sanctions will likely make the project even more expensive to accomplish. Inflation and supply chain issues will do this anyway.”785

   Yet, the political will to move forward appears intact as both countries have reaffirmed their commitment to the project and its timeline on numerous occasions. In fact, on the day following the Russian invasion of Ukraine on 24  February  2022, Egyptian ministerial sources were quoted as saying work on-site was going on “as usual”, and on 3  March  2022, the Egyptian Minister of Electricity and Renewable Energy expressed his confidence that the project would suffer no disruption.786

   On 9  March  2022, Presidents El-Sisi and Putin discussed the implementation of joint nuclear projects during a phone-call.787 On 3  April  2022, NPPA republished quotes from a TV-interview with the head of Rosatom, indicating that all construction projects the company was leading abroad were maintained, and the state company was currently assessing potential risks caused by the reconfiguration of global logistics.788 In late May–early June  2022, a delegation of NPPA and ENRRA officials went on an official visit to Russia, to attend a ceremony celebrating the manufacturing of the reactor vessel in presence of their Rosatom counterparts.789

   Beyond the eagerness of both parties to display their continuous cooperation, the joint efforts attained some significant milestones since the beginning of the invasion. Four days after the attack on Ukraine started, ENRRA granted the site permit for the spent fuel storage facility on site,790 Rosatom secured a construction permit for Unit  1 on 29  June  2022,791 and on 20  July  2022, construction was officially launched.792 Meanwhile, the license applications for the remaining three units are still pending.

   As previously mentioned, the likelihood of the project suffering impacts from sanctions following the war on Ukraine remains high, despite reassuring statements like former NPPA Deputy Head Ali  Abdel  Nabi indicating that “The sanctions on Moscow will not affect the course of the project because months ago [the Russian side] began manufacturing equipment for the nuclear plant, such as the reactor core catcher for nuclear units”.793 The bombing and near-destruction by Russia of a Rosatom-subsidiary Atomenergomash plant that manufactures key components like steam generator forgings for Rosatom’s export projects (including El-Dabaa) in May  2022 offers a blunt example of a different kind of potential, yet unpredictable, disruption in the supply chain: Russia destroying its own assets in Ukraine.794

   Questions have been raised as to whether ENRRA, established by law in 2010 and formed in  2012, has the capacity and political independence to effectively oversee the project.795 Additionally, while Egyptian officials estimate that the project will bring the country US$246  billion in revenues over 60  years, some experts have raised concerns that the project will lead to a substantial increase in Egypt’s foreign debt.796 The NGO Egyptian Initiative for Personal Rights also criticized that “the process of public participation (…) was not satisfactorily done”.797 For example, the latest IAEA assessment of Egypt’s regulatory competence, the Integrated Nuclear Infrastructure Review  (INIR), was completed and handed over to the government on 24  September  2020, 798 but was not made public until much later.799

   From a nuclear security perspective, Egypt’s nuclear program poses several challenges. In 2018 independent experts have stressed that in recent years, “the rate, impact and sophistication of jihadi attacks in Egypt increased significantly and it is not unthinkable for Egypt’s nuclear facilities to be targeted”.800

   The Government’s Sustainable Development Strategy  (SDS) “Egypt Vision 2030” developed in alignment with the UN’s Sustainable Development Goals and launched in 2016 indicates that by 2030, 9  percent of the country’s electricity generation would be covered by nuclear power, but does not mention any further projects than that of El-Dabaa.801 It has been known since January  2021 that an updated version of “Egypt Vision  2030” was in the making,802 and in July  2021 NPPA executive, Husham  Hegazy, revealed during a panel discussion that Egypt plans to build “several” other reactors “in various regions” to provide at least 8  percent of the country’s electricity from nuclear power by 2030.803 According to Al-Monitor, NPPA refused to provide further details following Husham  Hegazy’s comments, saying that “such information will only be revealed when the time is right”.804 As of July  2022, the time apparently is not right yet. However, considering the known long lead and construction times, likely no electricity will be generated by any nuclear power plant in Egypt by 2030.

   The country’s revised NDC report released in early June  2022, still mentions the “2035  Integrated Sustainable Energy Strategy” established in 2016 as reference on its renewable energy targets, and forecasts that by 2030 renewables will make up 40  percent of installed capacity.805 In parallel, the Egyptian Government has launched a series of energy reforms such as a feed-in-tariff that incentivized private sector to get involved in the country’s electricity sector, providing new financing pathways.806

   Egypt is also making strides in the development of a domestic and regional natural gas market. Besides being host to Zohr, the largest gas field in the Eastern Mediterranean,807 Egypt has invested in gas import and export infrastructure to position itself as regional hub, and in the process, become self-sufficient. (See WNISR2020 – Middle East Focus). These developments will have a great impact on Egypt’s electricity supply security as well as the future steps the country may take in shaping its energy policy.

   Nigeria

   In Nigeria, in November  2019, the Senate called on the Government to consider including nuclear power in the power mix to give a mandate to the Atomic Energy Commission to negotiate with international nuclear vendors. Nigeria has previously sought the support of the IAEA to develop plans for up to 4  GW of nuclear capacity by 2025, which are obviously not achievable in the originally envisaged timeframe.808 In March  2022, the Director General of the Nigerian Nuclear Regulatory Authority  (NNRA), Yau  Idris, said that “Nigeria is trying to deliver 4,000  MW of electricity through nuclear power. We are planning to construct four units and currently we are at the bidding phase of the nuclear power program in Nigeria”. He added that agreements relating to the power plant project had been signed with South  Korea, France, Russia, and India, and that the NNRA also had agreements on cooperation and training with regulators in the U.S., Pakistan, South  Korea, and Russia.809

   A conference organized in July  2022 by the Heinrich Böll Foundation and the Electricity Hub in Abuja, Nigeria,810 saw the former Chairman of the Nigerian Electricity Regulatory Commission  (NERC) pointing to the lack of adequate transmission infrastructure to receive even existing generation power and posed the question “whether the government should be more concerned with expanding capacity or increasing investments to ensure that the current generated capacity gets reliably distributed”. The Co-founder/CTO of the Clean Technology Hub Nigeria suggested that the country did not appear ready for nuclear power generation “given the challenges around the existing electricity generation and supply network”.811

   In continental Africa, only South Africa has an operating nuclear power plant (see section on South  Africa in Annex  1). This is despite sporadic support from national governments and encouragement from international vendors, more recently particularly China and Russia.

   Across the continent, electricity generation increased from 672  TWh in 2010 to just under 900  TWh in 2021, with nuclear providing 1.2  percent in 2021. Africa does however have a significant role for the global nuclear industry with Namibia and Niger being the world’s fourth- and fifth-largest uranium producers.

   According to the World Nuclear Association  (WNA), China has agreements with—but no plants under construction—Kenya, Sudan, and Uganda, while Russia signed agreements with Algeria, Congo, Egypt, Ethiopia, Ghana, Morocco, Nigeria, Sudan, Rwanda, Tunisia, and Zambia.812

   In September  2020, Russia signed a Memorandum of Understanding (MoU) for cooperation with the African Commission on Nuclear Energy  (AFCONE), to establish a basis for Russia to help African countries with various projects related to nuclear energy.813 The vast majority of these are little more than political statements of support designed to increase diplomatic links with key infrastructure providers and recipients.

   Rwanda in October  2019 signed an agreement with Rosatom to build a nuclear science center with the intention of developing an interest in Small Modular Reactors  (SMRs).814

   Few developments on nuclear activities in Africa reflect some significance on the ground.

   Poland

   Poland planned the development of a series of nuclear power stations in the 1980s and started construction of two VVER1000/320  reactors in Żarnowiec on the Baltic coast, but both construction and further plans were halted following the Chernobyl accident. Since then, there has been a long, expensive, and time-consuming series of