27 September 2019

The World Nuclear Industry Status Report 2019 (HTML)

Foreword by

Diana Ürge-Vorsatz

Central European University (CEU)

Budapest, Hungary


Mycle Schneider

Independent Consultant, Paris, France

Project Coordinator and Lead Author

Antony Froggatt

Independent Consultant, London, U.K.

Lead Author


Julie Hazemann

Director of EnerWebWatch, Paris, France

Documentary Research, Modelling and Datavisualization

Tadahiro Katsuta

Professor, School of Law, Meiji University,

Tokyo, Japan

Contributing Author

Amory B. Lovins

Co-Founder and Chairman Emeritus, Rocky Mountain Institute, Snowmass, Colorado, U.S.

Contributing Author

M.V. Ramana

Simons Chair in Disarmament, Global and Human Security with the Liu Institute for Global Issues at the University of British Columbia, Vancouver, Canada

Contributing Author

Christian von Hirschhausen

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

Contributing Author

Ben Wealer

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

Contributing Author

Agnès Stienne

Artist, Graphic Designer, Cartographer,

Le Mans, France

Graphic Design & Layout

Friedhelm Meinass

Visual Artist, Painter, Rodgau, Germany

Cover-page Design, Painting and Layout

Paris, Budapest, September 2019
© A Mycle Schneider Consulting Project


As for so many years now, the project coordinator wishes to thank Antony Froggatt for his conceptual input, his contributions on many levels and his friendship.

At the core of the World Nuclear Industry Status Report (WNISR) is its database, designed and maintained by data manager and information engineer Julie Hazemann, who also develops most of the roughs for the graphical illustrations. She expanded her contribution significantly this year with the organization of the draft report and multi-level proofing. As ever, no WNISR without her. Thanks so much.

The WNISR project can solidly count on the regular, reliable, professional and insightful contributions from M.V. Ramana, Tadahiro Katsuta, Christian von Hirschhausen and Ben Wealer. Many thanks to all of you.

WNISR2019 has greatly profited from a new contributor with a familiar name, Amory B. Lovins. We are very grateful for his excellent contribution. A particular thank you to Diana Ürge-Vorsatz for her generous and to-the-point Foreword.

Many other people have contributed pieces of work to make this project possible and to bring it to the current standard. In particular Shaun Burnie, whose multiple contributions have been invaluable and highly appreciated. Thank you also to Caroline Peachey, Nuclear Engineering International, for providing the load factor figures quoted throughout the report.

Artist and graphic designer Agnès Stienne created the redesigned layout in 2017 and continues to improve our graphic illustrations that get a lot of praise around the world. Thank you. Nina Schneider put her excellent proof-reading and production skills to work again. Thank you.

A big thank-you to Arnaud Martin for his innovative, original and reliable work on the website
www.WorldNuclearReport.org, dedicated to the WNISR.

We owe the idea, design, original painting and realization of the artwork for the cover to Friedhelm Meinass, renowned German painter. True, he already did (LP) covers before, in the 1970s, for The Byrds, Mahalia Jackson, Nina Hagen and the likes. Thanks so much for this exceptional contribution.

This work has greatly benefitted from additional proofreading by Amory B. Lovins, Walt Patterson and Allan Jones, partial proof-reading, editing suggestions or comments by Ada Amon, Jan Haverkamp, Iryna Holovko, Daul Jang, Benedek Javor, KANG Junjie, Lutz Mez, Andras Perger, Steve Thomas and others. Thank you all.

The authors wish to thank in particular Rebecca Harms, Matthew McKinzie, Tanja Gaudian, Rainer Griesshammer, Andrea Droste, Jutta Paulus and Nils Epprecht 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 France, the Greens-EFA Group in the European Parliament, Elektrizitätswerke Schönau, Foundation Zukunftserbe and the Swiss Renewable Energy Foundation for their generous support.


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

Mycle Schneider
45, Allée des deux cèdres
91210 Draveil (Paris)
Ph: +33-1-69 83 23 79

Antony Froggatt
53a Neville Road
London N16 8SW
United Kingdom
Ph: +44-79 68 80 52 99

Table of Figures

Figure 1 | National Nuclear Power Program Startup and Phase-out

Figure 2 | Forecasted and Real Expansion of Nuclear Capacity in the World

Figure 3 | Nuclear Electricity Generation in the World... and China

Figure 4 | Nuclear Electricity Generation and Share in Global Power Generation

Figure 5 | Nuclear Power Reactor Grid Connections and Closures in the World

Figure 6 | Nuclear Power Reactor Grid Connections and Closures – The Continuing China Effect

Figure 7 | World Nuclear Reactor Fleet, 1954–2019

Figure 8 | Nuclear Reactors “Under Construction” in the World

Figure 9 | Average Annual Construction Times in the World

Figure 10 | Delays for Units Started Up 2018–2019

Figure 11 | Construction Starts in the World

Figure 12 | Construction Starts in the World/China

Figure 13 | Cancelled or Suspended Reactor Constructions

Figure 14 | Age Distribution of Operating Reactors in the World

Figure 15 | Age Distribution of Closed Nuclear Power Reactors

Figure 16 | Nuclear Reactor Closure Age 1963 – 1 July 2019

Figure 17 | The 40-Year Lifetime Projection (not including LTOs)

Figure 18 | The PLEX Projection (not including LTOs)

Figure 19 | Forty-Year Lifetime Projection versus PLEX Projection

Figure 20 | Unavailability of Belgian Nuclear Reactors in 2018 (Cumulated)

Figure 21 | Unavailability of Belgian Nuclear Reactors in 2018 (by Outage Period)

Figure 22 | The Doel-1 Case

Figure 23 | Age Distribution of Chinese Nuclear Fleet

Figure 24 | Reactor Outages in France in 2018 (in number of units and GWe)

Figure 25 | Forced and Planned Unavailability of Nuclear Reactors in France in 2018

Figure 26 | Age Distribution of French Nuclear Fleet (by Decade)

Figure 27 | Main Developments of the German Power System Between 2010 and 2018

Figure 28 | Rise and Fall of the Japanese Nuclear Program

Figure 29 | Age Distribution of Japanese Fleet

Figure 30 | Status of Japanese Reactor Fleet

Figure 31 | Age Distribution of U.K. Nuclear Fleet

Figure 32 | Age Distribution of U.S. Nuclear Fleet

Figure 33 | Timelines of Early Retirement in the United States

Figure 34 | Change in the Number of Evacuees

Figure 35 | Number of Disaster-related Deaths of the Great East Japan Earthquake

Figure 36 | Closed Reactors Worldwide by Country and Reactor Technology

Figure 37 | Overview of Completed Reactor Decommissioning Projects, 1953–2017

Figure 38 | Global Investment Decisions in Renewables and Nuclear Power 2004–2018

Figure 39 | Regional Breakdown of Nuclear and Renewable Energy Investment Decisions 2008–2018

Figure 40 | The Declining Costs of Renewables vs. Traditional Power Sources

Figure 41 | Variation of Wind, Solar and Nuclear Capacity and Electricity Production in the World

Figure 42 | Net Added Electricity Generation by Power Source 2008–2018

Figure 43 | Wind, Solar and Nuclear Capacity and Electricity Production in the World

Figure 44 | Installed Wind, Solar and Nuclear Capacity and Electricity Production in China 2000–2018

Figure 45 | Startup and Closure of Electricity Generating Capacity in the EU in 2018

Figure 46 | Changes in Electricity Generating Capacity in the EU in 2000–2018

Figure 47 | Wind, Solar and Nuclear Capacity and Electricity Production in the EU

Figure 48 | Wind, Solar and Nuclear Capacity and Electricity Production in the EU

Figure 49 | Wind, Solar and Nuclear Installed Capacity and Electricity Production in India

Figure 50 | Increases in Electricity Production from Nuclear, Solar and Wind Since 2000 in the United States

Figure 51 | Cost Evolution of New Renewables vs. Operating Nuclear

Figure 52 | Average Annual Increase of Nuclear, Wind, and Solar

Figure 53 | Average Annual Increase of Nuclear, Wind, and Solar

Figure 54 | Nuclear Reactors Startups and Closures in the EU28, 1956–1 July 2019

Figure 55 | Nuclear Reactors and Net Operating Capacity in the EU28

Figure 56 | Age Distribution of the EU28 Reactor Fleet

Figure 57 | Age Distribution of the Swiss Nuclear Fleet

Figure 58 | Age Distribution of the Russian Nuclear Fleet

Table of tables

Table 1 | Nuclear Reactors “Under Construction” (as of 1 July 2019)

Table 2 | Reactor Construction Times 2009–mid-2019

Table 3 | Belgian Nuclear Fleet (as of 1 July 2019)

Table 4 | Legal Closure Dates for German Nuclear Reactors 2011–2022

Table 5 | Official Reactor Closures Post-3/11 in Japan

Table 6 | Schedule Closure Dates for Nuclear Power Reactors in Korea 2023–2029

Table 7 | Scheduled Closure Dates for Nuclear Reactors in Taiwan 2018–2025

Table 8 | Early-Retirements for U.S. Reactors 2009-2025

Table 9 | U.S. State Emission Credits for Uneconomic Nuclear Reactors 2016–2019

Table 10 | Thyroid Cancer Statistics in Fukushima Prefecture

Table 11 | Update Decommissioning Status in Three Selected Countries

Table 12 | Current Status of Reactor Decommissioning in Spain

Table 13 | Current Status of Reactor Decommissioning in Italy

Table 14 | Current Status of Reactor Decommissioning in Lithuania

Table 15 | Overview of Reactor Decommissioning in 11 Selected Countries

Table 16 | Summary of Potential Nuclear Newcomer Countries

Table 17 | Vendor design review service agreements in force between vendors and the CNSC

Table 18 | Vendor design review service agreement between vendors and the CNSC under development

Table 19 | New-build Costs for Nuclear, Renewables and Efficiency

Table 20 | Average Nuclear Generating Costs in the United States (by Quartile)

Table 21 | Average Nuclear Generating Costs in the United States (by Category)

Table 22 | Spain’s Nuclear Phase-Out Timetable

Table 23 | Chinese Nuclear Reactors in Operation

Table 24 | Chinese Nuclear Reactors in LTO

Table 25 | Status of Japanese Nuclear Reactor Fleet

Table 26 | Status of Nuclear Power in the World

Table 27 | Nuclear Reactors in the World “Under Construction”


By Diana Ürge-Vorsatz1

There is no doubt that climate change is with us. Record temperatures around the globe, higher frequency of droughts, severe fires, storms and flooding are becoming evident even to the starkest of skeptics. The Intergovernmental Panel on Climate Change (IPCC), that I have the honor to serve on as Vice-Chair of Working Group III, made it clear in a Special Report “Global Warming of 1.5°C” that urgent action is needed, as

challenges from delayed actions to reduce greenhouse gas emissions include the risk of cost escalation, lock-in in carbon-emitting infrastructure, stranded assets, and reduced flexibility in future response options in the medium to long term.2

Therefore, time is of the essence. While climate scientists have been aware of the notion of urgency for many years, the notion of “Climate Emergency” has only hit public awareness and decision-makers’ attention recently.

The energy sector is the largest cause of global greenhouse gas emissions. The pertinence of mitigation strategy options needs to be judged, among others, according to three key criteria: feasibility, cost and speed.

The aforementioned IPCC Special Report notes that scenarios achieving the 1.5°C target “generally meet energy service demand with lower energy use, including through enhanced energy efficiency and show faster electrification of energy end use compared to 2°C”. There is no doubt that the key to successfully addressing the climate crises lies in more efficient buildings, mobility and industry, as well as a dramatic transformation in the way we use our land. The IPCC also notes that “in electricity generation, shares of nuclear and fossil fuels with carbon dioxide capture and storage (CCS) are modelled to increase in most 1.5°C pathways”, and several scenarios that reach this temperature target rely heavily on nuclear power. Similarly to other options relied heavily on by 1.5°C pathways, these scenarios raise the question whether the nuclear industry will actually be able to deliver the magnitude of new power that is required in these scenarios in a cost-effective and timely manner. This report is perhaps the most relevant publication to answer this pertinent question.

The World Nuclear Industry Status Report (WNISR) focuses on the commercial power sector. It assesses in great detail the industry’s past and present performance, following a multi-criteria analysis that looks at planning, licensing, siting issues, construction, operation, age, lifetime extensions and decommissioning. Its international reputation is beyond doubt. Already in 2011, an official USAID publication called the WNISR “the authoritative report on the status of nuclear power plants worldwide”3; the Founding Director of the Forum for the Future and former Head of the UK Sustainable Development Commission stated that “the WNISR is the single most important reference document in this space”; the World Scientific’s upcoming Encyclopedia of Climate Change4 will carry a paper on the WNISR. The former Vice-Chairman of the Japan Atomic Energy Commission recommended: “All concerned parties, including nuclear industry organizations as well as government institutions, should read the WNISR to understand the real issues the nuclear industry is facing.”

The WNISR2019 paints a picture of an international nuclear industry with substantial challenges. Remarkably, over the past two years, the largest historic nuclear builder Westinghouse and its French counterpart AREVA went bankrupt. Trend indicators in the report suggest that the nuclear industry may have reached its historic maxima: nuclear power generation peaked in 2006, the number of reactors in operation in 2002, the share of nuclear power in the electricity mix in 1996, the number of reactors under construction in 1979, construction starts in 1976. As of mid-2019, there is one unit less in operation than in 1989.

The WNISR provides the most detailed annual account of the status and outlook of the nuclear power industry based on empirical analysis of its 65-year history. If it is difficult to forecast the future, it is all the more important to understand the past and present in order to be able to design realistic, feasible, affordable strategies for the coming decades. For example, according to the WNISR, the building rate would have to roughly triple over the coming decade in order to maintain the status quo. However, after less than a decade of China-driven modest growth, building is on the decline again as the number of units under construction dropped from 68 in 2013 to 46 as of mid-2019.

The IPCC Special Report notes:

The political, economic, social and technical feasibility of solar energy, wind energy and electricity storage technologies has improved dramatically over the past few years, while that of nuclear energy and carbon dioxide capture and storage (CCS) in the electricity sector have not shown similar improvements.5

The WNISR2019 echoes these findings. In 2018, ten nuclear countries generated more power with renewable than with fission energy. In spite of its ambitious nuclear program, China produced more power from wind alone than from nuclear plants. In India, in the fiscal year to March 2019, not only wind, but for the first time solar out-generated nuclear, and new solar is now competitive with existing coal plants in the market. In the European Union, renewables accounted for 95 percent of all new electricity generating capacity added in the past year.

The WNISR is full of pieces of information that put data into perspective. The 2019-Edition also contains a new focus on Climate Change and Nuclear Power that reflects in depth about the capacity of the nuclear industry to deliver the magnitude of new power and capacity modeled in several ambitious climate scenarios—whether with new or existing plants—in a cost-effective and timely manner.

The WNISR is an excellent resource as it provides insights into the choices facing policymakers and its historic perspective is invaluable to the energy sector where investment and management decisions have decade-long effects. I would therefore recommend that decision makers and investors all read this report prior to making their decisions.

Key Insights

China Still Dominates Developments, But…

  • In 2018, nuclear power generation in the world increased by 2.4% of which 1.8% due to a 19% increase in China. Global nuclear power generation excluding China increased by 0.6% for the first time after decreasing three years in a row, but without making up for the decline since 2014.
  • Nine reactors started up in 2018 of which seven were in China and two in Russia.
  • Four units started up in the first half of 2019, of which two were in China.
  • The number of units under construction globally declined for the sixth year in a row, from 68 reactors at the end of 2013 to 46 by mid-2019, of which 10 are in China.


  • Still no construction start of any commercial reactor in China since December 2016.
  • China will by far miss its Five-Year-Plan 2020 nuclear targets of 58 GW installed and 30 GW under construction.
  • China spent a record US$146 billion on renewables in 2017—more than half of the world’s total—and saw a decline to US$91 billion in 2018, but still close to twice the U.S., the second largest investor with US$48.5 billion.

No More Reactor Restarts in Japan and Global Construction Delays

  • The nuclear share of global electricity generation has continued its slow decline from a historic peak of about 17.5 percent in 1996 to 10.15 percent in 2018.
  • Japan had restarted nine reactors by mid-2018 and none since.
  • As of mid-2019, 28 reactors—including 24 in Japan—are in Long-Term Outage (LTO).
  • At least 27 of the 46 units under construction are behind schedule, mostly by several years; 11 have reported increased delays and 3 have had documented delays for the first time over the past year.
  • Only nine of the 17 units scheduled for startup in 2018 were actually connected to the grid.

Renewables Continue to Thrive

  • A record 165 GW of renewables were added to the world’s power grids in 2018, up from 157 GW added the previous year. The nuclear operating capacity increased by 9 GW6 to reach 370 GW (excluding 25 GW in LTO), a new historic maximum, slightly exceeding the previous peak of 368 GW in 2006.
  • Globally, wind power output grew by 29% in 2018, solar by 13%, nuclear by 2.4%. Compared to a decade ago, non-hydro renewables generate over 1,900 TWh more power, exceeding coal and natural gas, while nuclear produces less.
  • Over the past decade, levelized cost estimates for utility-scale solar dropped by 88%, wind by 69%, while nuclear increased by 23%. Renewables now come in below the cost of coal and natural gas.

Climate Change and Nuclear Power

  • To protect the climate, we must abate the most carbon at the least cost and in the least time, so we must pay attention to carbon, cost, and time, not to carbon alone.
  • Non-Nuclear Options Save More Carbon Per Dollar. In many nuclear countries, new renewables can now compete economically with existing nuclear power plants. The closure of uneconomic reactors will not directly save CO2 emissions but can indirectly save more CO2 than closing a coal-fired plant, if the nuclear plant’s larger saved operating costs are reinvested in efficiency or cheap modern renewables that in turn displace more fossil-fueled generation.
  • Non-Nuclear Options Save More Carbon Per Year. While current nuclear programs are particularly slow, current renewables programs are particularly fast. New nuclear plants take 5–17 years longer to build than utility-scale solar or onshore wind power, so existing fossil-fueled plants emit far more CO2 while awaiting substitution by the nuclear option. Stabilizing the climate is urgent, nuclear power is slow.

Executive Summary and Conclusions

As its preceding editions, the World Nuclear Industry Status Report 2019 (WNISR2019) provides a comprehensive overview of nuclear power plant data, including information on age, operation, production and construction. A new chapter on Climate Change and Nuclear Power addresses the crucial question of the performance of the nuclear option in countering the increasingly obvious climate emergency. The WNISR assesses the status of new-build programs in the 31 current nuclear countries as well as in potential newcomer countries. WNISR2019 has put particular attention on 10 Focus Countries representing about two-thirds of the global fleet. The Fukushima Status Report gives an overview of the standing of onsite and offsite issues eight years after the beginning of the catastrophe. The Decommissioning Status Report for the second time provides an overview of the current state of nuclear reactors that have been permanently closed. The Nuclear Power vs. Renewable Energy chapter offers global comparative data on investment, capacity, and generation from nuclear, wind and solar energy. Finally, as usual, Annex 1 presents a country-by-country overview of the remaining countries’ operating nuclear power plants.

Reactor Startups & Closures

Startups. At the beginning of 2018, 15 reactors were scheduled for startup during the year; seven of these made it, plus two that were expected in 2019; of these nine startups, seven were in China and two in Russia.

In mid-2018, 13 reactors were scheduled for startup in 2019, of which five had been connected to the grid as of mid-2019 (including the two started up in 2018)—and four have already been officially delayed until at least 2020. One reactor that was connected to the grid in June 2019, was listed in WNISR2018 as expected to start up only in 2020. The startups in China over the 18 months to July 2019 include the long-awaited grid connections for two Framatome-Siemens designed European Pressurized Water Reactors (EPR) and four Westinghouse AP-1000s.

Closures. Three reactors were closed in 2018, two in Russia and one in the U.S., and a further reactor was closed in the U.S. in May 2019. The Wolsong-1 reactor in South Korea also ceased operation in June 2018, which was only officially confirmed later. In July 2019, Japanese utility Tokyo Electric Power Company (TEPCO) announced the closure of the four Fukushima Daini reactors, situated 15 km from the site of Fukushima Daichi subject to disastrous accidents in 2011. WNISR had already registered all four units as closed. TEPCO announced in August 2019 that it will also decommission five of its seven units at Kashiwazaki-Kariwa, leaving the company with only two of its original fleet of 17 reactors.

Operation & Construction Data 7

Reactor Operation and Production. There are 31 countries operating 417 nuclear reactors8—excluding Long-Term Outages (LTOs)—an increase of four units compared to mid-2018, but one less than in 1989 and 21 fewer than the 2002 peak of 438. The increase is partially due to the restart of 4 reactors previously in LTO.9 The total operating capacity increased over the past year by 3.4 percent to reach 370 GW,10 which is a new historic maximum, exceeding the previous peak of 368 GW in 2006. Annual nuclear electricity generation reached 2,563 TWh in 2018—a 2.4 percent increase over the previous year, mainly due to China—but remained 3.7 percent below the historic peak in 2006. After three years of decline, the world nuclear power generation outside China grew by 0.7 percent in 2018 but was still below the level of 2014. 

WNISR classifies 28 reactors around the world as being in LTO, all considered operating by the International Atomic Energy Agency (IAEA).11 These include 24 reactors in Japan, and one each in Canada, China, South Korea and Taiwan12. Four reactors have been restarted from LTO since mid-2018, two in India (Kakrapar-1 and -2) and one each in Argentina (Embalse) and France (Paluel-2). Three reactors, two in Japan (Genkai-2, Onagawa-1) and one in Taiwan (Chinshan-1), moved from LTO to closed.

As in previous years, in 2018, the “big five” nuclear generating countries—by rank, the United States, France, China, Russia and South Korea—generated 70 percent of all nuclear electricity in the world. As in 2017, two countries, the U.S. and France, accounted for 47.5 percent of 2018 global nuclear production.

Share in Electricity/Energy Mix. The nuclear share of the world’s gross power generation has continued its slow decline from a historic peak of 17.46 percent in 1996 to 10.15 percent in 2018. Nuclear power’s share of global commercial primary energy consumption has remained stable since 2014 at around 4.4 percent.

Reactor Age. In the absence of major new-build programs apart from China, the unit-weighted average age of the world operating nuclear reactor fleet continues to rise, and by mid-2019 reached 30.1 years, exceeding the figure of 30 years for the first time. A total of 272 reactors, two-thirds of the world fleet, have operated for 31 or more years, including 80 (19 percent) that have reached 41 years or more.

Lifetime Projections. If all currently operating reactors were closed at the end of a 40-year lifetime—with the exception of the 85 that are already operating for more than 40 years—with all units under construction scheduled to have started up, installed nuclear capacity would still decrease by 9.5 GW by 2020. In total, 14 additional reactors (compared to the end-of-2018 status) would have to be started up or restarted prior to the end of 2020 in order to maintain the status quo of operating units. In the following decade to 2030, 188 units (165.5 GW) would have to be replaced—3.2 times the number of startups achieved over the past decade. In the meantime, construction starts are on a declining trend since 2010.

Construction. Sixteen countries are currently building nuclear power plants, one more than in mid-2018, as the United Kingdom officially started building the first unit of Hinkley Point C. As of 1 July 2019, 46 reactors were under construction—4 fewer than mid-2018 and 22 fewer than in 2013—of which 10 in China. Total capacity under construction is 44.6 GW, 3.9 GW less than one year earlier.

  • The current average time since work started at the 46 units under construction is 6.7 years, on the rise for the past two years from an average of 6.2 years as of mid-2017. Many units are still years away from completion.
  • All reactors under construction in at least half of the 16 countries have experienced delays, mostly several years long. At least 27 (59 percent) of the building projects are delayed.
  • Of 27 reactors behind schedule, at least eleven have reported increased delays and three more have documented delays for the first time over the past year since WNISR2018.
  • Two reactors have been listed as “under construction” for more than 34 years, Mochovce-3 and -4 in Slovakia, and their startup has been further delayed, currently to 2020–21.
  • Six additional reactors have been listed as “under construction” for a decade or more: the two “swimming reactors” Akademik Lomonosov-1 and -2 in Russia, the Prototype Fast Breeder Reactor (PFBR) in India, the Olkiluoto-3 reactor project in Finland, Shimane-3 in Japan and the French Flamanville-3 unit. The Finnish, French and Indian projects have been further delayed over the past year while the Japanese one does not even have a provisional startup date.
  • The average construction time of the latest 63 units in nine countries (of which 37 in China) that started up since 2009 was 9.8 years—the first time in years to slip just below ten years—with a very large range from 4.1 to 43.5 years.

Construction Starts & New-Build Issues

Construction Starts. In 2018, construction began on 5 reactors and in the first half of 2019 on one (in Russia). This compares to 15 construction starts in 2010 and 10 in 2013. There has been no construction start of any commercial reactor in China since December 2016. Analysis shows that construction starts in the world peaked in 1976 at 44.

Construction Cancellations. Between 1970 and mid-2019, a total of 94 (12 percent or one in eight) of all construction projects were abandoned or suspended in 20 countries at various stages of advancement.

Potential Newcomer Countries - Program Delays & Cancellations

Construction Ongoing. Four newcomer countries are actually building reactors—Bangladesh, Belarus, Turkey and United Arab Emirates (UAE). The first reactor startup in UAE is at least three years behind schedule. The first unit in Belarus is at least one year delayed. At the Turkish Akkuyu site, cracks were identified in the foundation of the reactor building, leading to replacement work and likely to delays. The project in Bangladesh only started recently and it is therefore difficult to assess potential delays.

Cancellations and Delays. New-build plans have been cancelled including in Turkey with the second Japanese shareholder Mitsubishi pulling out of the Sinop project in late 2018. The perennial Polish nuclear projects have been postponed again with first power generation now envisaged by 2033. In Egypt, a site permit was issued, but nuclear electricity is not expected before 2026–27. In Jordan and Indonesia, after the cancellation of large nuclear projects, nuclear proponents are back to the drawing board, with Small Modular Reactors this time. In Kazakhstan, after years of talks, the Deputy Energy Minister stated that there was no “concrete decision” to build a nuclear plant. Saudi Arabia ploughs ahead with its nuclear plans, however, “at a slower pace than originally expected”, as Reuters put it. Thailand’s largest private power company prefers to invest in a nuclear plant in China rather than at home. Vietnam’s national energy company EVN does not even mention nuclear anymore.

Small Modular Reactors (SMRs)

Following assessments of the development status and prospects of Small Modular Reactors (SMRs) in WNISR2015 and WNISR2017, this year’s update does not reveal great changes.

Argentina. The CAREM-25 project under construction since 2014 is at least three years late.

Canada. A massive lobbying effort is underway to promote SMRs for remote communities and mining operations. Development is in the design stage.

China. A high-temperature reactor under development since the 1970s has been under construction since 2012. It is currently at least three years behind schedule.

India. An Advanced Heavy Water Reactor (AHWR) design has been under development since the 1990s, and its construction start is getting continuously delayed.

Russia. Two “floating reactors” have been built. The first one went critical, with construction starting in 2007, it took at least four times as long as planned.

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 nobody wants to build it in the country, because it is not cost-competitive.

United Kingdom. Rolls-Royce is the only company interested in participating in the government’s SMR competition but has requested significant subsidies that he government is apparently resisting. The Rolls-Royce design is at a very early stage but, at 450 MW, it is not really small.

United States. The Department of Energy (DOE) has generously funded companies promoting SMR development. A single design by NuScale is currently undergoing the design certification process.

Overall, there is no sign of any major breakthroughs for SMRs, either with regard to the technology or with regard to the commercial side.

Focus Countries – Widespread Extended Outages

The following nine Focus Countries plus Taiwan, covered in depth in this report, represent one-third of the nuclear countries hosting about two-thirds of the global reactor fleet and six of the world’s ten largest nuclear power producers. Key facts for year 2018:

Belgium. Nuclear provided a third less power than in 2017 and represented only 34 percent of the country’s electricity, and little more than half of the peak in 1986. Reactors were shut down for repair and upgrading for half of the year on average.

China. Nuclear power generation grew by 19 percent in 2018 and contributed 4.2 percent of all electricity generated in China, up from 3.9 percent in 2017.

Finland. Nuclear generation was stable compared to previous years. The Olkiluoto-3 EPR project was delayed again, and grid connection might take until April 2020 at least, due to pressurizer vibration problems.

France. Nuclear plants generated 3.7 percent more power than in 2017, representing 71.7 percent of the country’s electricity, just 0.1 percentage points better than in the previous year, which is the lowest share since 1988. Outages at zero capacity cumulated over 5,000 reactor-days or almost three months per reactor on average. The Flamanville-3 EPR project was delayed until at least the end of 2022. The target date to reduce the nuclear share to 50 percent was pushed back from 2025 to 2035 in the draft energy bill.

Germany. Germany’s remaining seven nuclear reactors’ generation remained almost stable (–0.4 percent) at 71.9 TWh net in 2018, about half of record year 2001. They provided a stable 11.7 percent of Germany’s electricity generation, little more than one-third of the historic maximum two decades ago (30.8 percent in 1997). In the meantime, renewables have generated close to twice as much more power (+113 TWh) than was lost through the fading nuclear production (–64 TWh) since 2010. In 2018, renewables provided 16.7 percent of final energy in Germany (in comparison, nuclear provided 17.4 percent of French final energy).

Japan. Nuclear plants provided 6.2 percent of the electricity in Japan in 2018, a significant increase over the 3.6 percent in 2017 (36 percent in 1998). As of mid-2019, nine reactors had restarted—no restart since mid-2018—and 24 remained in LTO (two were moved from LTO to closed).

South Korea. Nuclear power output dropped by another 10 percent leading to a decline of 19 percent since 2015, and supplied 23.7 percent of the country’s electricity, significantly less than half of the maximum 30 years ago (53.3 percent in 1987).

United Kingdom. Nuclear generation decreased by a further 7.5 percent and provided only 17.7 percent of the power in the country, down from the maximum of 26.9 in 1997. While construction officially started at Hinkley Point C, prospects for other new-build projects have receded with further potential investors pulling out (Japan’s Toshiba, Hitachi, Korea’s KEPCO).

United States. Nuclear power plants generated a historic maximum of 808 TWh (+3 TWh), while their share in the electricity mix dropped below 20 percent (19.3 percent), 3.2 percentage points below the record level of 22.5 percent in 1995. State subsidies have been granted to four uneconomic nuclear plants to avoid their “early closure”, four more are likely, and several others are under negotiation. However, many units remain threatened with early closure because they cannot compete in the market.

Fukushima Status Report

Over eight years have passed since the Fukushima Daiichi nuclear power plant accident (Fukushima accident) began, triggered by the East Japan Great Earthquake on 11 March 2011 (also referred to as 3/11 throughout the report) and subsequent events.

Onsite Challenges

Spent Fuel Removal from the pool of Unit 3 finally started in April 2019. Target dates for the start of the operation for Units 1 and 2 are “around FY 2023”. Debris removal from the pool of Unit 1 was completed in February 2019. For Unit 2 work has not begun, as the spent fuel removal process has been redesigned.

A Fuel Debris Removal method was supposed to be designed by FY 2019. However, as of mid-year, no announcement has been made. Removal from the first unit was supposed to start by 2021, which does not seem credible at this point.

Contaminated Water Management. Large quantities of water are still continuously being injected to cool the fuel debris of Units 1–3. The 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. The commissioning of a dedicated bypass system and the pumping of groundwater has reduced the influx of water from around 400 m3/day to about 170 m3/day. An equivalent amount of water is partially decontaminated and stored in 1,000-m3 tanks. Thus, a new tank is needed every six days. The storage capacity onsite has been increased to over 1.1 million m3 and will be enlarged to 1.4 million m3 by the end of 2020. The ocean release of the water remains widely contested, especially since it was revealed that a large share of the water does not even meet the safety regulations for release.

Worker Health. As of February 2019, there were almost 7,300 workers involved in decommissioning work on-site, 87 percent of whom were subcontractors of Tokyo Electric Power Company (TEPCO). A Health Ministry investigation showed that over half of 290 involved companies were in violation of some kind of labor legislation. In 2018, two additional workers’ illnesses were recognized as radiation-induced, bringing to six the number of acknowledged occupational diseases due to work at Fukushima.

Offsite Challenges

Amongst the main offsite issues are the future of tens of thousands of evacuees, the assessment of health consequences of the disaster, the management of decontamination wastes and the costs involved.

Evacuees. As of April 2019, almost 40,000 Fukushima Prefecture residents—not including “self-evacuees”—are still officially designated evacuees of whom about 7,200 are living in the prefecture. According to the Prefecture, the number peaked just under 165,000 in May 2012. The government has continued to lift restriction orders for affected municipalities. However, according to a recent survey by the Reconstruction Agency, e.g. only 5 percent of the people returned to Namie Town, while half of the former residents already decided not to return. Others remain undecided. The treatment of voluntary evacuees13 is worsening. Fukushima Prefecture stopped providing free housing in March 2017 and terminated rent assistance for low-income households in March 2019. Once the free housing offer is terminated, they are no longer considered voluntary evacuees and disappear from the statistics. The Special Rapporteurs from the UN Human Rights Commission repeatedly raised concerns about the Japanese policies concerning evacuees and human rights violations linked to families and workers.

Health Issues. Officially, as of April 2019, a total of 212 people have been diagnosed with a malignant tumor or suspected of having a malignant tumor and 169 people underwent surgery. While the cause-effect relationship between Fukushima-related radiation exposure and illnesses has not been established, questions have been raised about the examination procedure itself and the processing of information.

Food Contamination. According to official statistics, among 300,000 samples taken in FY 2018 a total of 313 food items were identified in excess of the legal limits (a significant increase over the 200 items found in FY 2017). As of April 2019, in 23 countries post-3/11 import restrictions remain in place.

Decontamination. Decontamination activities in the Special Decontamination Area ended in March 2018 and generated 16.5 million m3 of contaminated soil. Outside Fukushima Prefecture, contaminated soil is stored in more than 28,000 places (333,000 m3). As of April 2019, only about 20 percent of the soil had been moved to dedicated storage areas.

Decommissioning Status Report – Soaring Costs

As an increasing number of nuclear facilities either reaches the end of their pre-determined operational lifetimes or closes due to deteriorating economic conditions, the challenges of reactor decommissioning are coming to the fore.

  • As of mid-2019, 162 of the 181 closed reactors in the world (eight more than a year earlier) are awaiting or are in various stages of decommissioning.
  • Only 19 units have been fully decommissioned: 13 in the U.S., five in Germany, and one in Japan. Of these, only 10 have been returned to greenfield sites. No change over the year since WNISR2018.
  • Case Studies: In France, decommissioning of the small 80 MW Brennilis reactor will be further delayed, with the earliest possible completion in 2038. In Germany, Neckarwestheim-1 and Philippsburg-1 were defueled. In Italy, decommissioning cost estimates for the four reactors that used to be operated have almost doubled since 2004 to US$8.1 billion. In Lithuania, decommissioning cost estimates for two Soviet, Chernobyl-type reactors increased by two-thirds in five years to US$3.7 billion. If waste management and disposal was included, costs would increase to US$6.8 billion, leaving an estimated funding gap of US$4.7 billion. In Spain, decommissioning cost estimates for the first 240-MW unit to close in 2006 have doubled since to US$292 million. In the U.S., sales of closed reactors and transfers of decommissioning funds to private waste management companies is spreading. Of ten units undergoing decommissioning, six were sold to such commercial decommissioning companies. The practice raises obvious liability questions in case the available funds run out.

Nuclear Power vs. Renewable Energy Deployment

Cost. Levelized Cost of Energy (LCOE) analysis for the U.S. shows that the total costs of renewables are now below of coal and combined cycle gas. Between 2009 and 2018, utility-scale solar costs came down 88 percent and wind 69 percent, while new nuclear costs increased by 23 percent.

Investment. In 2018, the reported global investment decisions for the construction of nuclear power totaled around US$33 billion for 6.2 GW, which is less than a quarter of the investment in wind and solar individually, with over US$134 billion investment in wind power and US$139 billion in solar, and this year’s investment was higher than previous years, but skewed by the start of construction of the extremely expensive Hinkley Point C in the U.K. China remains the top investor in renewables, spending US$91 billion in 2018; however, this was significantly lower than the record US$146 billion invested in 201714, due to dropping prices and to policy changes over the year.

Installed Capacity. In 2018, the 165 GW of renewables added to the world’s power grids, up from 157 GW added the previous year, set a new record. Wind added 49.2 GW and solar-photovoltaics (PV) 96 GW, both slightly below the 2017-levels. These numbers compare to a net 8.8 GW increase for nuclear power.

Electricity Generation. Ten of the 31 nuclear countries, Brazil, China, Germany, India, Japan, Mexico, Netherlands, Spain, South Africa and U.K.—a list that includes three of the world’s four largest economies—generated more electricity in 2018 from non-hydro renewables than from nuclear power. That is one more, South Africa, than in 2017.

In 2018, annual growth for global electricity generation from solar was 29 percent, for wind power about 13 percent. Both growth rates are down compared to 2017, from 38 percent and 18 percent respectively. Nuclear power increased output by 2.4 percent in 2018, mainly due to China, versus +1 percent in 2017.

Compared to 1997, when the Kyoto Protocol on climate change was signed, in 2018 an additional 1,259 TWh of wind power was produced globally and 584 TWh of solar PV electricity, compared to nuclear’s additional 299 TWh. Over the past decade, non-hydro renewables have added more kilowatt-hours than coal or gas and twice as many as hydropower, while nuclear plants generated less power in 2018 than in 2008.

In China, as in the previous six years, in 2018, electricity production from wind alone (366 TWh) by far exceeded that from nuclear (277 TWh), with solar power catching up quickly (178 TWh).

The same phenomenon is seen in India, where wind power (60 TWh) outpaced nuclear—stagnating at 35 TWh—for the third year in a row. At the same time, solar power soared from 11 TWh in 2016 to 31 TWh in 2018, now hot on nuclear’s tail.

In the U.S., in 2018, 211 GW of existing coal capacity, or 74 percent of the national fleet, was at risk from local wind or solar that could provide the same amount of electricity more cheaply. In April 2019, for the first time ever, renewables (hydro, biomass, wind, solar and geothermal) generated more electricity than coal-fired plants across the U.S. Wind and solar generation topped coal’s output in Texas in the first quarter of 2019, the first time that this has happened on a quarterly basis.

In the European Union virtually all new capacity added in 2018 was renewable (95 percent wind, solar and biomass). Wind alone supplied 11.6 percent of the EU’s total power in 2018, led by Denmark at a remarkable 41 percent, Portugal and Ireland at 28 percent, and Germany at 21 percent with Spain and the U.K. at 19 percent (up from 13.5 percent in 2017). Compared to 1997, in 2018, EU wind turbines produced an additional 371 TWh and solar 128 TWh, while nuclear power generation declined by 94 TWh.

Climate Change and Nuclear Power

The Stakes. To protect the climate, we must abate the most carbon at the least cost—and in the least time—so we must pay attention to carbon, cost, and time, not to carbon alone.

Nuclear Power vs. Climate Protection Options. If existing nuclear generation (one-tenth of global commercial electricity) displaced an average mix of fossil-fueled power generation, it would offset the equivalent of 4 percent of total global CO2 emissions. Expanding nuclear power could displace other generators—fossil-fueled or renewable. Renewables and efficiency can “bolster energy security” at least as well as nuclear power can. The nuclear industry has become one of the most potent obstacles to renewables’ further progress by diverting demand and capital to itself. New operating subsidies for uneconomic reactors in the U.S. or preferential dispatch like the “nuclear-must-run” rule in Japan lead to uncompetitive generation to serve demand for which efficiency and renewables are not allowed to compete.

Non-Nuclear Options Save More Carbon Per Dollar. Nuclear new-build costs have been on the rise for many years (see previous WNISR editions). Just in the past five years, U.S. solar and wind prices fell by two-thirds, putting new nuclear power out of the money by about 5–10-fold (see Nuclear Power vs. Renewable Energy Deployment). Nuclear new-build costs many times more per kWh, so it buys many times less climate solution per dollar than major low-carbon competitors—efficiency, wind and solar. Newer technologies do not change this: in the latest nuclear designs, so-called Gen-III+ reactors, ~78–87 percent of total costs is for the non-nuclear part. Thus, if the other ~13–22 percent, the “nuclear island”, were free, the rest of the plant would still be grossly uncompetitive with renewables or efficiency. That is, even free steam from any kind of fuel or fission is not good enough, because the rest of the plant costs too much. The business case for modern renewables is so convincing to investors that the latest official U.S. forecast foresees 45 GW of renewable additions from mid-2019 to mid-2022, vs. net retirements of 7 GW for nuclear and 17 GW for coal.

In many nuclear countries, new renewables can now compete with existing nuclear power plants and their operating, maintenance and fuel costs. While reactor-by-reactor data is not available, published information illustrates that many nuclear plants are not competitive anymore. Their closure will not directly save CO2 emissions but can indirectly save more CO2 than closing a coal-fired plant, if the nuclear plant’s larger saved operating costs are reinvested in efficiency or cheap modern renewables that in turn displace more fossil-fueled generation.

Substitution for Closed Nuclear Plants. Four cases from four different states in the U.S. illustrate that the combination of strong efficiency and renewables policies could not only make up for the loss of nuclear production but allowed for the decrease of coal-based power generation and led to overall CO2 emissions reductions.

Non-Nuclear Options Save More Carbon Per Year. While some nuclear countries had a particularly fast buildup in the 1970s and 1980s (Belgium, France, Sweden, U.S.), many nuclear countries show faster buildup of renewables than in their nuclear program (China, Germany, Italy, India, Spain, U.K., and Scotland individually). A key point is that while current nuclear programs are particularly slow, current renewables programs are particularly fast (as WNISR has documented over the past decade). According to a recent assessment, new nuclear plants take 5–17 years longer to build than utility-scale solar or onshore wind power, so existing fossil-fueled plants emit far more CO2 while awaiting substitution by the nuclear option. In 2018, non-hydro renewables outpaced the world’s most aggressive nuclear program, in China, by a factor of two, in India by a factor of three.

Stabilizing the climate is urgent, nuclear power is slow. It meets no technical or operational need that these low-carbon competitors cannot meet better, cheaper, and faster. Even sustaining economically distressed reactors saves less carbon per dollar and per year than reinvesting its avoidable operating cost (let alone its avoidable new subsidies) into cheaper efficiency and renewables.


The first word in the introduction to the 2018-edition of the World Nuclear Industry Status Report (WNISR) was “Heat”. Since then, many registered temperature records around the world were broken and the Intergovernmental Panel on Climate Change (IPCC) issued its most urgent report to date. Over the past year, more than 900 local governments in 18 countries representing over 200 million people have “declared a climate emergency and committed to action to drive down emissions at emergency speed”, a movement spreading rapidly.15

As the greenhouse gas emissions generated by the construction and operation of nuclear power systems are relatively low16—depending on the systems providing the energy necessary to provide mining and milling services, construction materials, transport, waste processing and storage, and, especially, uranium enrichment—some voices have been increasingly audible pushing for lifetime extensions of existing nuclear power plants or the construction of new ones “to address Climate Change”.

WNISR2019 devotes a substantial new chapter (see Climate Change and Nuclear Power) to the question whether the use of nuclear power represents an effective tool to fight the rapidly worsening Climate Emergency. The question raises a complex mix of economic, industrial and systemic issues. However, the outcome of the analysis is surprisingly clear. The underlying challenge of any potential tool to combat Climate Change is making the best use of every invested dollar, euro or yuan in order to reduce greenhouse gas emissions as quickly as possible. Nuclear new-build turns out to be not only the most expensive, but also the slowest option to bring results. And while other electricity generating technologies are experiencing dramatically declining costs—system costs for utility-scale solar photovoltaics dropped by 88 percent in a decade—the price tag of new nuclear power increased (by 23 percent).17 Even existing, amortized operating nuclear plants are less and less in a position to compete with other options like energy efficiency and renewables, not taking into account system effects like their role as powerful barriers to innovation, investment and effective energy transition measures. We are not assessing here specific technical issues, including the fact that nuclear power is the most water-consuming way to generate electricity and the multiple threats that Climate Change pose to nuclear facilities. It comes as no surprise that in the summer of 2019 a number of reactors again had to reduce output or shut down entirely in several European countries, as water levels were low in rivers and sea temperatures were heating up. Rising sea levels and the increasing frequency of droughts, flooding, severe storms and wildfires raise the risk levels. Operators and regulators only recently began to develop specific programs to address these issues. They could be the subject of a future WNISR focus.

With WNISR2018, we started to assess the performance of the French nuclear sector reactor-by-reactor and this edition presents the complementary analysis to get a full picture of the year 2018. The outcome might come as a big surprise to many readers. The average outage (at zero power, not including reduced output) per unit for the 58 French reactors was almost three months (87.6 days) per year, totaling over 5,000 reactor-days (see France Focus). A new, equivalent analysis on Belgium shows that the seven units in the country were down half of the year on average (see Belgium Focus). There are multiple reasons for this poor performance, with systematically extended maintenance and refurbishment outages at these aging facilities being the principal cause.

The past year since the release of WNISR2018 has seen China completing the commissioning of the first Generation-III reactors, designed by western companies Framatome-Siemens (two EPRs at Taishan) and Westinghouse (four AP-1000 with two each at Sanmen and Haiyang). Questions remain about the pace at which China will continue to expand its nuclear program. Another year went by without any new commercial reactor construction being launched in China, with the latest one started in December 2016 (see China Focus). There were press reports about three new government authorizations but any new project has yet to officially begin (pouring of concrete for the base slab of the reactor building).

While the first foreign Generation III reactors went into commercial operation in China, the European EPR projects in France and Finland continue their erratic path towards completion. The French regulator requires the costly, time-consuming repair of welding defects in the main steam line of the Flamanville-3 project, delaying startup to at least end of 2022. Meanwhile, builder AREVA-Siemens is struggling with so-far-unresolved pressurizer vibration issues at the Olkiluoto-3 unit in Finland, delaying grid connection at least to April 2020 (see Finland Focus).

In Japan, no new units have been restarted since mid-2018—four restarted in the first half of 2018—and there are still only nine operating reactors in the country. Two additional reactors have been slated for decommissioning, bringing the total of units abandoned since 3/11—the beginning of the Fukushima disaster—to 17. In addition, in July 2019, operator Tokyo Electric Power Company (TEPCO) announced its decision to decommission the four Fukushima Daini reactors (15 km from the Fukushima Daichi site). WNISR has for years considered the Fukushima Daini units as closed. As of mid-2019, 24 reactors remain in Long-Term Outage (LTO) with uncertain prospects for restart, still highly controversial amongst the Japanese public (see Japan Focus).

On 28 June 2019, the EPR project at Hinkley Point C project in the U.K. was finally officially declared as “under construction”, almost seven months after the beginning of the concreting of the foundations for the reactor building—the usual international setpoint for construction start. Other new-build projects in the U.K. continue to run into trouble. After the pullout of various English, French, German and Spanish utilities from the U.K. “market”, the Japanese Hitachi Group abandoned the Wylfa and Oldbury projects, writing off a ¥300 billion (US$2.75 billion) impairment (see United Kingdom Focus).

In the U.S., there has been little change in the outlook. Many reactors remain threatened with closure long before their licenses expire because they cannot compete in the market. In some cases, the nuclear industry has been lobbying successfully for subsidies at state level, to help avoiding “early closures” of uneconomic reactors. Five reactors in three states have thus been “saved” for a few years, a mere postponement of closure in an economic environment that is likely to only get worse. The only active new-build project in the U.S., at the Vogtle plant in Georgia, is accumulating cost and time overruns. Unlike in other states, Georgia Power was authorized to charge its customers for increasing construction costs. It was estimated that by 2018 each 1,000 kWh/month Georgia Power customer would pay US$10 every month towards the project, currently scheduled to bring the first of two units online by November 2021. Tennessee Valley Authority (TVA), the public utility that started up the last nuclear reactors ever commissioned in the U.S. in 1996 (Watts Bar-1) and 2016 (Watts Bar-2), stated in its latest Integrated Resource Plan that, while new capacity would be necessary, it would not add any “baseload resources” capacity such as nuclear or coal over the next 20 years “except in the case where Small Modular Reactors are promoted for resiliency”.18

Small Modular Reactors or SMRs have made little progress since the WNISR2017 assessment as this edition’s update concludes “it has become evident that they will be even less capable of competing economically than large nuclear plants, which have themselves been increasingly uncompetitive” (see Small Modular Reactors).

The WNISR’s overview of the status of decommissioning of closed reactors identifies few major developments, except the consolidation of a trend in the U.S. where utilities sell their closed reactors and transfer decommissioning funds to commercial waste management companies. While eight additional reactors are closed, no new decommissioning project has been completed, and the gap between the two indicators keeps widening.

The traditional Nuclear Power vs. Renewable Energy chapter shows that it has become increasingly clear: non-hydro renewables are no longer just cheaper than new-build nuclear but they are now broadly competitive with new-coal—and increasingly with operating nuclear and coal plants whose construction costs have been paid off (amortized). Coal is the largest source of electricity globally, with almost four times the output share of nuclear power. Therefore, outcompeting coal will open up new opportunities for renewable energy, which will further drive down their production costs and increase system integration experience, further speeding up their deployment.

General Overview Worldwide

The Historic Expansion of Nuclear Power – Forecasting vs. Reality

The use of nuclear energy remains limited to a small part of the world, with only 31 countries or 16 percent of the 193 members of the United Nations, operating nuclear power plants. That number has remained stable since Iran started up its first reactor in 2011. When the Nuclear Non-Proliferation Treaty (NPT) was signed in 1968, ten countries had operating nuclear power reactors (grid connected) and twenty additional countries generated nuclear electricity by 1985. But only four countries (Mexico, China, Romania, Iran) started up commercial reactors over the past 30 years, while three countries (Italy, Kazakhstan, Lithuania) abandoned their programs. Nine of the current 31 nuclear countries have either nuclear phase-out, no-new-build >or no-program-extension policies in place. Eleven countries with operating plants are currently building new reactors; another eleven countries with operating plants currently have no active construction ongoing (see Figure 1). In addition, there are four newcomer countries (Bangladesh, Belarus, Turkey, United Arab Emirates) that are building reactors for the first time.

Sources: WNISR, with IAEA-PRIS, 2019

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

The NPT was meant to stimulate the development of nuclear energy programs around the world while limiting the spread of military explosives applications to the five historic nuclear weapon states. In 1974, the International Atomic Energy Agency’s (IAEA) “most likely” scenario envisaged an installed capacity of over 3,500 GW19 by year 2000, while the high scenario imagined more than 5,000 GW. It is these forecasts that triggered the launch of massive plutonium separation programs, as the fear of a rapid natural uranium shortage led many nuclear organizations, in particular the French Atomic Energy Commission (CEA), to push for the early, large-scale introduction of plutonium-fueled fast breeder reactors. The U.S. Atomic Energy Commission (AEC), the Organisation for Economic Co-operation and Development (OECD) and other organizations all considered levels above 1,500 GW operating nuclear capacity plausible by 2000. In reality, the expansion of nuclear power remained far below expectations. In 2000, a total capacity of 350 GW was operating in the world, just one tenth of the IAEA’s “most likely” scenario of 1974 (see Figure 2). As of mid-2019, total operating capacity has barely grown to its historic peak of 370 GW, a net addition of little more than 1 GW per year over the past two decades.

Source: Klaus Gufler, “Short and Mid-term Trends of the Development of Nuclear Energy”, June 2013

Production and Role of Nuclear Power

The world nuclear fleet generated 2,563 net terawatt-hours (TWh or billion kilowatt-hours) of electricity in 201820, a 2.4 percent increase over the previous year—essentially due to China’s nuclear output increasing by 44 TWh (+19 percent)—but still 4 percent below the historic peak of 2006 (see Figure 3). For the first time in four years, without China, global nuclear power generation has slightly increased again (+0.7 percent) in 2018 but remained below the level of 2014. In other words, world nuclear production outside China dropped more in the period 2015–17 than it added in 2018. The numbers illustrate that China continues to dominate the upwards-leaning indicators in nuclear statistics.

Nuclear energy’s share of global commercial gross electricity generation continues its slow but steady decline from a peak of 17.5 percent in 1996 to 10.15 percent in 2018 (10.28 percent in 2017). The nuclear contribution to commercial primary energy remained stable at 4.4 percent. It has been at this level since 2014 and constitutes a 30-year low.21

In 2018, nuclear generation increased in 14 countries, declined in 12, and remained stable in five.22 Six countries (China, Hungary, Mexico, Pakistan, Russia, U.S.) achieved their greatest ever nuclear production in 2018.

The following remarkable developments for the year 2018 illustrate the volatile operational situation of the individual national reactor fleets (see country-specific sections for details):

  • Armenia’s only operating reactor dropped generation by 21 percent. The output will likely decline further in 2019 as the unit was shut down in mid-year for extensive repair and upgrade.
  • Belgium’s output plunged by 32 percent due to the extension of outages for maintenance, repair and upgrade. On average, Belgium’s seven units have each been down for half of the year (see Belgium Focus).
  • China started up seven new nuclear reactors during the year, a remarkable achievement, and contributed 44 TWh of the total increase of 60 TWh worldwide (see China Focus).
  • France increased output by 14 TWh (+3.7 percent), remaining however well below expectations (see France Focus).
  • Japan restarted four more units bringing the total of operating reactors to nine and boosting production by 20 TWh (+68.4 percent) (see Japan Focus).
  • South Korea’s nuclear production dropped by 10 percent (–14 TWh) due to extended outages for inspection and repair. One of the specific issues that has led to delays in restarts of reactors has been the discovery in 2017 of Containment Liner Plate (CLP) corrosion in various reactors (see South Korea Focus).
  • Switzerland’s generation increased by 25 percent after the restart of one of the five-reactor fleet that had been down for years following the discovery of numerous crack indications in its pressure vessel (see Switzerland section).
  • Taiwan increased output by 24 percent after the restart of two reactors following long outages. However, generation remained below the level of 2016 (see Taiwan Focus).
  • The U.S. registered its all-time highest nuclear electricity generation. While the increase over the previous record in 2010 (+1 TWh) remains marginal, it is noteworthy that the country operated six fewer reactors in 2018 than in 2010 (97/103). Even the installed capacity was slightly lower in 2018 than in 2010 (98.7 GW/100.4 GW), a clear indication that operational efficiency has continued to improve (see U.S. Focus).
  1. Figure 3 | Nuclear Electricity Generation in the World... and China23

Sources: WNISR, with BP, IAEA-PRIS, 2019

As in previous years, in 2018, the “big five” nuclear generating countries—by rank, the U.S., France, China, Russia and South Korea—generated 70 percent of all nuclear electricity in the world (see Figure 4, left side). In 2002, China held position 15, in 2007 it was tenth, before reaching third place in 2016. Two countries, the U.S. and France, with 47 percent accounted again for nearly half of global nuclear production in 2018.

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 4, right side). It is therefore remarkable that, in 2018, there were 20 countries that maintained their nuclear share at a constant level (change of less than 1 percentage point) while seven decreased their nuclear shares. Only four countries increased the role of nuclear power in their electricity mix by more than 1 point (Czech Republic, Japan, Switzerland and Taiwan), all of them mainly through restarts of units after prolonged outages. Only two countries (China and Pakistan) reached new historic peak shares of nuclear in their respective power mix, both at marginal increases getting to still very modest levels, +0.3 percentage points for China (reaching a share of 4.2 percent) and +0.6 percentage points for Pakistan (attaining 6.8 percent.)

Source: IAEA-PRIS, 2019

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 closures24 outweighed the number of startups. The 1991–2000 decade produced far more startups than closures (52/30), while in the decade 2001–2010, startups did not match closures (32/35). Furthermore, after 2000, it took a whole decade to connect as many units as in a single year in the middle of the 1980s. Between 2011 and mid-2019, the startup of 56 reactors—of which 35 (almost two thirds) in China alone—outpaced by six the closure of 50 units over the same period. As there were no closures in China over the period, the 50 closures outside China were only met by 21 startups, a startling decline by 29 units over the period. (See Figure 5).

Sources: WNISR, with IAEA-PRIS, 2019

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.)

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 one each in Russia and South Korea, while three units were closed, of which two in Russia and one in the U.S. (See Figure 6).

Sources: WNISR, with IAEA-PRIS, 2019

In the first half of 2019, four reactors started up in the world, two of which were in China (Taishan-2, Yangjiang-6) and one each in Russia (Novovoronezh 2-2) and South Korea (Shin-Kori-4), while one unit was closed in the U.S. (Pilgrim-1).

As of mid-August 2019, the International Atomic Energy Agency (IAEA) continues to count 37 units in Japan (five less than in mid-2018) in its total number of 451 reactors “in operation” in the world (two less than mid-2018)25; yet no nuclear electricity was generated in Japan between September 2013 and August 2015, and as of 1 July 2019, only nine reactors were operating (see Japan Focus). Nuclear plants provided only 6.2 percent of the electricity in Japan in 2018.

The WNISR reiterates its call for an appropriate reflection in world nuclear statistics of the unique situation in Japan. The attitude taken by the IAEA, the Japanese government, utilities, industry and many research bodies as well as other governments and organizations to continue considering the entire stranded reactor fleet in the country as “in operation” or “operational” is misleading.

The IAEA actually 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 zero reactors anywhere in the LTS category.

The IAEA criteria are vague and hence subject to arbitrary 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 2019, leads to classifying 28 units in LTO—all considered “in operation” by the IAEA—four fewer than in WNISR2018, of which 24 in Japan, and one each in Canada, China, South Korea and Taiwan. Four reactors restarted from LTO since mid-2018, two in India (Kakrapar-1 and -2) and one each in Argentina (Embalse) and France (Paluel-2). Three reactors, two in Japan (Genkai-2, Onagawa-1) and one in Taiwan (Chinshan-1), moved from LTO to closed.

For years, WNISR has considered all ten Fukushima reactors closed. In July 2019, operator Tokyo Electric Power Company (TEPCO) finally officialized the closure and announced plans to decommission the four Fukushima Daini reactors (see Table 5 and Annex 3 for a detailed overview of the status of the Japanese nuclear fleet).

As of 1 July 2019, a total of 417 nuclear reactors were operating in 31 countries, up four units from the situation in July 201827. The current world fleet has a total nominal electric net capacity of 370 GW, up by 6.7 GW (+1.9 percent) from one year earlier (see Figure 7). While the number of operating reactors remains below the figure reached in 1989 and nuclear electricity generation is still a few percent below the 2006 peak, this is a new historic maximum for operating capacity.

Sources: WNISR, with IAEA-PRIS, 2019

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.

For many years, the net installed capacity has continued to increase more than the net number of operating reactors. In 1989, the average size of an operational nuclear reactor was about 740 MW, while that number has increased to almost 890 MW in 2019. This is a result of the combined effects of larger units replacing smaller ones and technical alterations to raise capacity at existing plants resulting in larger electricity output, a process known as uprating.28 In the United States alone, the Nuclear Regulatory Commission (NRC) has approved 164 uprates since 1977. The cumulative approved uprates in the U.S. total 7.9 GW, the equivalent of eight large reactors.29 No additional uprates were approved since April 2018 and there are no pending applications as of mid-2019. However, four additional applications are expected during the rest of the year.

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.

Overview of Current New-Build

As of 1 July 2019, 46 reactors are considered here as under construction, the lowest number in a decade, falling for the sixth year in a row—four fewer than WNISR reported a year ago, and 22 fewer than in 2013 (five of these units have already subsequently been abandoned). Three in four reactors are built in Asia and Eastern Europe. In total, 16 countries are building nuclear plants, one more (U.K.) than reported in WNISR2018 (see Table 1).

Five building projects were launched in 2018, one each in Bangladesh, Russia, South Korea, Turkey and the U.K. In the first half of 2019, only one project started construction in the world, in Russia. Russian companies are also building the reactors in Bangladesh and Turkey, Russia is therefore involved in four of these six projects launched since the beginning of 2018.

The figure of 46 reactors listed as under construction by mid-2019 compares 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). The year 2005, with 26 units under construction, marked a record low since the early nuclear age in the 1950s. Compared to the situation described a year ago, the total capacity of units now under construction in the world dropped again, by 3.9 GW to 44.6 GW, with a rather stable average unit size of 969 MW (see Annex 7 for details).

Sources: WNISR, with IAEA-PRIS, 2019

Table 1 | Nuclear Reactors “Under Construction” (as of 1 July 2019) 30



(MW net)





Units Behind Schedule



8 800

2012 - 2017

2020 - 2023




4 824

2004 - 2017

2019 - 2023




3 379

2007 - 2019

2019 - 2023




5 380

2012 - 2015

2020 - 2023


South Korea


5 360

2012 - 2018

2019 - 2024




2 218

2013 - 2014

2019 - 2020




2 160

2017 - 2018

2023 - 2024






2020 - 2021




2 234


2021 - 2022




2 028

2015 - 2016

2020 - 2021




1 325












1 630






1 600






1 600






1 114






44 557

1985 - 2019

2019 - 2025


Sources: Compiled by WNISR. 2019


This table does not contain suspended or abandoned constructions.

Construction Times

Construction Times of Reactors Currently Under Construction

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

  • As of 1 July 2019, the 46 reactors being built have been under construction for an average of 6.7 years, and many remain far from completion.
  • All reactors under construction in at least half of the 16 countries have experienced mostly year-long delays. At least 27 (59 percent) of the building projects are delayed. Most of the units which are nominally being built on-time were begun within the past three years or have not yet reached projected startup dates, making it difficult to assess whether or not they are on schedule. Particular uncertainty remains over construction sites in Belarus, China and UAE.
  • Of the 27 reactors clearly documented as behind schedule, at least eleven have reported increased delays and five have reported new delays over the past year since WNISR2018.
  • WNISR2017 noted a total of 19 reactors scheduled for startup in 2018, one of these started up already in 2017. At the beginning of 2018, 15 reactors were still scheduled for startup during the year, but only nine made it, while the others were delayed at least into 2019.
  • Construction on two projects started over 30 years ago, Mochovce-3 and -4 in Slovakia, and their startup has been further delayed, currently to 2020–21.
  • Four reactors have been listed as under construction for a decade or more: the Prototype Fast Breeder Reactor (PFBR) in India, the Olkiluoto-3 reactor project in Finland, Shimane-3 in Japan and the French Flamanville-3 unit. The Finnish, French and Indian projects have been further delayed this year, and the Japanese one 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. As the U.K.’s Hinkley Point C project illustrates, a significant share of investment and work was carried out before even entering the official construction phase (see United Kingdom Focus).

Construction Times of Past and Currently Operating Reactors

There has been a clear global trend towards increasing construction times. National building programs were faster in the early years of nuclear power. As Figure 9 illustrates, construction times of reactors completed in the 1970s and 1980s were quite homogenous, while in the past two decades they have varied widely.

Sources: WNISR, with IAEA-PRIS, 2019

The seven units completed in 2018 by the Chinese nuclear industry averaged 7.7 years of construction time, while the two Russian projects took a mean 22.3 years to connect to the grid, with Rostov-4 taking 35 years to finally generate power (see The Construction Saga of Rostov Reactors 3 and 4) and Leningrad 2-1 close to 10 years. The mean construction time for the nine reactors started up in 2018 was 10.9 years.

Sources: WNISR with IAEA-PRIS, 2019


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.

There is only one unit that in the past 18 months started up on time, and that is Tianwan-4 in China, a Russian-designed but mainly Chinese-built VVER-1000 (model V-428M), that the designers claim to belong to Gen-III, but few details are known. The two Chinese units Yangjiang-5 and -6 were completed with minor delays in 4.7 and 5.5 years respectively. These are ACPR-1000 reactors, designed by China General Nuclear Corp. (CGN) that it claims contain at least ten improvements making them a Gen-III design.31 Leaving the epic Rostov-4 case aside, the other six units that started up in China (four AP-1000s, two EPRs), the two in Russia and the one in South Korea all experienced years-long delays and roughly doubled their respective planned construction time to 8.3–9.8 years (see Figure 10).

The longer-term perspective confirms that short construction times remain the exceptions. Nine countries completed 63 reactors over the past decade—of which 37 in China alone—after an average construction time of 9.8 years (see Table 2), a slight improvement over the decade 2008–mid-2018 with 10.1 years.

Table 2 | Reactor Construction Times 2009–mid-2019

Construction Times of 63 Units Started-up 2009-7/2019



Construction Time (in Years)

Mean Time













South Korea




































Sources: Compiled by WNISR. 2019

Construction Starts and Cancellations

The number of annual construction starts32 in the world peaked in 1976 at 44, of which 12 projects were later abandoned. In 2010, there were 15 construction starts—including 10 in China alone—the highest level since 1985 (see Figure 11). That number dropped to five in 2017 and five in 2018. The construction starts in 2018 were unusually diverse as one each took place in Bangladesh, Russia, South Korea, Turkey and U.K. Also, with Bangladesh and Turkey, the list contains two newcomer countries. In both countries, the projects are implemented by the Russian nuclear industry. In Turkey work started at the Akkuyu site, a project that has been proposed since the 1970s. As of mid-2019, only one project got officially underway in the world so far this year, Kursk 2-2 in Russia.

Sources: WNISR, with IAEA-PRIS, 2019

Seriously affected by the Fukushima events, China did not start any construction in 2011 and 2014 and began work only on seven units in between. 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 and none in 2019 as of mid-year (see Figure 12). In other words, since December 2016, China has not started building any new commercial reactors. According to media reports, three construction starts got government approval and could take place later in 2019. While this development would mean a restart of commercial reactor building in China, for the time being, the level remains 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 mid-2019, China had 45.5 GW operating and 9 GW under construction, far from the original target.

Over the decade 2009–2018, construction began on 71 reactors in the world (of which five have been cancelled). That is more than in the decade 1999–2008, when work started on 45 units (of which three have been abandoned). With 49 units China holds the lion’s share of the 116 building starts over the past two decades (see Figure 12).

In addition, past experience shows that simply 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 abandonment of the two V.C. Summer units at the end of July 2017 after four years of construction and following multi-billion-dollar investment is only the latest example in a long list of failed nuclear power plant projects.

Sources: WNISR, with IAEA-PRIS, 2019

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. The United States alone accounted for 138 of these order cancellations.33

Of the 766 reactor constructions launched since 1951, at least 94 units—12 percent or one in eight—in 20 countries had been abandoned as of 1 July 2019. The past decade shows an abandoning rate of one-in-fourteen—as five in 71 building sites officially started during that period were later given up at various stages of advancement (see also Figure 13).

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 actually 100 percent completed—including Kalkar in Germany and Zwentendorf in Austria—before the decision was taken not to operate them.

Sources: WNISR, with IAEA-PRIS, 2019

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

Operating Age

In the absence of significant new-build and grid connection over many years, the average age (from grid connection) of operating nuclear power plants has been increasing steadily and at mid-2019, for the first time, is exceeding 30 years (30.1 years), up from 29.9 a year ago (see Figure 14).34 A total of 272 reactors, two-thirds of the world fleet, have operated for 31 or more years, including 80 (19 percent) reaching 41 years or more.

Sources: WNISR, with IAEA-PRIS, 2019

Some nuclear utilities envisage average reactor lifetimes of beyond 40 years up to 60 and even 80 years. In the United States, 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.

As of 4 May 2018, 85 of the then 99 operating U.S. units had received an extension, with another four applications for five reactors under NRC review. Since WNISR2018, four license renewals for five reactors were granted, one expected submission (Perry-1) was cancelled, two units with renewed licenses were closed, and two additional applications for three reactors are expected in 2021–22.35

In the U.S., only four of the 36 units—one in nine—that have been closed had reached 40 years on the grid—Vermont Yankee was closed in December 2014 at the age of 42; Fort Calhoun in October 2016 after 43 years of operation; Oyster Creek, the oldest U.S. reactor, in September 2018 at 49 years; and Pilgrim in May 2019 at 47 years. All four 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 reactors connected to the grid in the U.S. never reached their initial design lifetime of 40 years. On the other hand, of the 97 currently operating plants, 46 units have operated for 41 years or more; thus, half of the units with license renewals have already entered the life extension period, and that share is growing rapidly with the mid-2019 mean age of the U.S. operational fleet at 38.9 years (see United States Focus).

Many countries have no specific time limits on operating licenses. In France, where the country’s first operating Pressurized Water Reactor (PWR) started up in 1977, reactors must undergo in-depth inspection and testing every decade against reinforced safety requirements. The French reactors have operated for 34.4 years on average, and most of them have completed the process with the French Nuclear Safety Authority (ASN) evaluating each reactor allowing them to operate for up to 40 years, which is the limit of their initial design age. However, the ASN assessments are years behind schedule. For economic reasons, the French utility Électricité de France (EDF) clearly prioritizes lifetime extension to 50 years over large-scale new-build. EDF’s approach to lifetime extension is still under review by ASN’s Technical Support Organization. ASN plans to provide its opinion on the general assessment outline by 2020. This is particularly critical for Tricastin-1, the first unit to undergo the fourth decennial review scheduled to begin in 2019. In addition, lifetime extension beyond 40 years requires site-specific 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 a 60-year license for its 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 those that have already closed (see Figure 14 and Figure 15). The age structure of the 181 units already closed (eight more than one year ago) completes the picture. In total, 66 of these units operated for 31 years or more, and of those, 24 reactors operated for 41 years or more. Many units of the first-generation designs only operated for a few years. Considering that the average age of the

Sources: WNISR, with IAEA-PRIS, 2019

closed units is 25.8 years, plans to stretch the operational lifetime of large numbers of units to 40 years and far beyond seemed rather optimistic.

To be sure, the operating time prior to closure has clearly increased continuously. But while the average age of reactors closed in the world in a given year got close to 40 years, it passed it only twice so far: in 2016, with two reactors shutting down at ages 43 (Fort Calhoun, U.S.) and 45 (Novovoronezh, Russia) respectively and in 2018 with Oyster Creek, the oldest U.S. reactor closing at 49 years, as well as Leningrad-1 at 45 and Bilibino at 44 in Russia (see Figure 16).

Sources: WNISR, with IAEA-PRIS, 2019

As a result of the Fukushima nuclear disaster, questions have been raised about 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, a 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 it is clear that the 3/11 events had an impact on previously assumed extended lifetimes in other countries as well, including in Belgium, Switzerland and Taiwan. Some of the main nuclear countries closed their respective oldest unit long before age 50, including Germany at age 33, South Korea at 40, Sweden at 46 and the U.S. at 49. France has scheduled to close its two oldest units in spring 2020 at age 43.

Lifetime Projections

Many countries continue to implement or prepare for lifetime extensions. As in previous years, WNISR has therefore created two lifetime projections. A first scenario (40-Year Lifetime Projection, see Figure 17), assumes a general lifetime of 40 years for worldwide operating reactors—not including reactors in Long-Term Outage (LTO). The 40-year number corresponds to the design lifetimes of most operating reactors. Some countries have legislation or policy (Belgium, South Korea, Taiwan) in place that limit operating lifetime to for all or part of the fleet to 40 or 50 years.

For the 85 reactors that have passed the 40-year lifetime, 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 18) takes into account all already-authorized lifetime extensions.

Sources: Various sources, compiled by WNISR, 2019

Notes pertaining to Figures 17–19:

The number of startups in 2019 includes two reactors in LTO that were restarted during the first half-year 2019. Restart and closure of 28 reactors in LTO as of 1 July 2019 are not represented here.

The 60-year license for six APR1400 reactors in South Korea, of which two, Shin-Kori-3 & -4, are already in operation, and four under construction, is not represented here. The Figures do not take into account either the expected closure at age 30 of the three remaining Wolsong reactors (see South Korea Focus, Table 6).

The Figures take into account “early retirements” of 10 reactors, while some of them are likely to be cancelled (see United States Focus, Table 8) and others might be added.

In the case of French reactors that have reached 40 years of operation prior to 2019, we use the limit date for their 4th periodic safety review (visite décennale) as closing date in the 40-year projection. For those that will reach 40 years of operation in 2019 or 2020, the date of their 4th periodic safety review is used in the PLEX Projection.

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 capacity. With all units under construction scheduled to have started up, installed nuclear capacity would still decrease by 9.5 GW by 2020. In total, 14 additional reactors (compared to the end of 2018 status) would have to be started up or restarted prior to the end of 2020 in order to maintain the status quo of operating units. Compared to the situation in 2014, the number of additional units necessary to break even by 2020 shrank by 16. In fact, construction started on 25 units between 2014 and mid-2019, and Japan restarted nine reactors (none were operating in 2014). The additional capacity needed to maintain the status quo by 2020 increased though by 2 GW.

In the following decade to 2030, 188 additional new reactors (165.5 GW) would have to be connected to the grid to maintain the status quo, 3.2 times the rate achieved over the past decade (59 startups between 2009 and 2018). The situation is identical to 2014, when the corresponding projections for 2021–2030 indicated a need for an equal number of additional reactors, though with a higher total capacity of 178 GW.

The potential stabilization of the situation by 2020 will depend on the number of Japanese and other reactors currently in LTO coming back online, as it is technically impossible to start and complete construction of any additional new plant in a year.

As a result, the number of reactors in operation will probably more or less stagnate at best, unless—beyond restarts—lifetime extensions far beyond 40 years become widespread. Such generalized lifetime extensions are the objective of the nuclear power industry, and, especially in the U.S., there are numerous more or less successful attempts to obtain subsidies for uneconomic nuclear plants (see detailed analysis in United States Focus).

Sources: Various sources, compiled by WNISR, 2019

Developments in Asia, and particularly in China, do not fundamentally change the global picture. Reported figures for China’s 2020 target for installed nuclear capacity have fluctuated between 40 GW and 120 GW in the past. The freezes of construction initiation for almost two years and of new siting authorizations for four years have significantly reduced Chinese ambitions.

Every year, we also model a scenario in which all currently licensed lifetime extensions and license renewals (mainly in the United States) 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 2020, the net number of operating reactors would increase by five units, and the installed capacity would grow by 7 GW.

In the following decade to 2030, another 153 new reactors (125 GW) would have to start up to replace closures. The PLEX-Projection would still mean, in the coming decade, a need to multiply the number of units built over the past decade by 2.6 (see Figure 17, Figure 18, and the cumulated effect in Figure 19). In the meantime, construction starts have been on a declining trend for a decade.

Sources: WNISR, with IAEA-PRIS, 2019

Note: All reactors in LTO are shown until they reach age 40, unless they have a license to operate to 60 years, (see Table 27).

Focus Countries

The following chapter provides an in-depth assessment of ten countries: Belgium, China, France, Finland, Germany, Japan, South Korea, Taiwan, United Kingdom (U.K.) and the United States (U.S.). They represent about two thirds of the global reactor fleet (65 percent of the units and 73 percent of the installed capacity) and six of the world’s ten largest nuclear power producers. For other countries’ details, see Annex 1.

Unless otherwise noted, data on the numbers of reactors operating and under construction and their capacity (as of mid-2019) and nuclear’s share in electricity generation are from the International Atomic Energy Agency’s Power Reactor Information System (PRIS) online database.36 Historical maximum figures indicate the year that the nuclear share in the power generation of a given country was the highest since 1986, the year of the Chernobyl disaster. Unless otherwise noted, the load factor figures are from Nuclear Engineering International (NEI).37

Belgium Focus

  • Operating 7
  • Closed 1
Number of Reactors
Mean Age of Reactor Fleet
Annual Load Factor

Belgium operates seven pressurized-water reactors that have generated 27.3 TWh in 2018, almost one-third less than the 40.2 TWh in 2017 and a maximum of 46.7 TWh in 1999. Nuclear power contributed 34 percent of Belgium’s electricity in 2018, while the maximum was almost double with 67.2 percent in 1986.

Due to continuous technical issues and extended outages, the average load factor of the Belgian fleet plunged to 48.6 percent in 2018, the second lowest in the world behind Argentina. The average age of the Belgian fleet is 39.3 years. On average, the seven Belgian units were down half of the year (see details hereafter) and in October 2018 power prices reached record levels (€205/MWh or US$231/MWh). The “Belgian nuclear crisis” is the title of an Argus White Paper describing that the lack of power from nuclear reactors led not only to the need for coordinated solidarity by neighboring countries to help Belgium with power exports through the winter, but also to strategic reinforcement of energy cooperation, in particular with Germany.38

Engie-Electrabel, which operates all of the Belgian reactors, stated in January 2019 that 4 GW of nuclear capacity (Doel-3 and -4, Tihange-2 and -3) will be available in winter 2019–20, and thus the situation should be less constrained.39

The nuclear capacity constraints in the winter 2018–19 were also seen as a test case, as legally the country is bound to a nuclear phase-out target of 2025. In January 2003, legislation was passed that requires the closure of all of Belgium’s nuclear plants after 40 years of operation, so based on their startup dates, plants would be closed progressively between 2015 and 2025 (see Table 3). Practically, however, after lifetime extension to 50 years was granted for three reactors, five of the seven reactors would go offline in the single year of 2025. This represents a challenging policy goal.

In November 2017, the Belgian transmission system operator Elia published a study urging the construction of “at least 3.6 GW of new-build adjustable (thermal) capacity” to “cope with the shock of the nuclear exit in 2025”40. The Belgian government confirmed the nuclear phase-out date, when, on 30 March 2018, it presented the Federal Energy Strategy.

Table 3 | Belgian Nuclear Fleet (as of 1 July 2019)


Net Capacity



Operating Age
(as of 1 July 2019)

End of License
(Latest Closure Date)

Load Factor







10-year lifetime extension

to 15 February 2025







10-year lifetime extension

to 1 December 2025




1 006



1 October 2022




1 038



1 July 2025







10-year lifetime extension

to 1 October 2025




1 008



1 February 2023




1 038



1 September 2025



Sources: WNISR, NEI, 2019; Belgian Law of 28 June 2015; Electrabel/GDF-Suez, 201541

Hydrogen Crack Indications and Legal Issues

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

The Belgian government did not wait for the outcome of the Doel-3/Tihange-2 issue and decided in March 2015 to draft legislation to extend the lifetime of Doel-1 and Doel-2 by ten years to 2025. The law went into effect on 6 July 2015. The government signed an agreement with Electrabel on 30 November 2015 that stipulates that the operator will invest €700 million (US$741.2 million) into upgrading of the two units and an annual fee of €20 million (US$21.2 million), which will be paid into the national Energy Transition Fund, set up by the law of 28 June 2015. On 22 December 2015, FANC authorized the lifetime extension and restart of Doel-1 and -2.

On 6 January 2016, two Belgian NGOs filed a complaint against the 28 June 2015 law with the Belgian Constitutional Court, arguing in particular that the lifetime extension had been authorized without a legally binding public enquiry. In a 22 June 2017 pre-ruling decision, the Court addressed a series of questions to the European Court of Justice (ECJ), in particular concerning the interpretation of the Espoo and Aarhus Conventions, as well as the European legislation. On 29 November 2018, the ECJ’s Advocate General presented its advice on the request of the Belgian Constitutional Court concerning the applicability of the EU-Aarhus/Espoo with regards to the Plant Life Extension or PLEX of Doel-1 and -2 and Tihange-1. In her advice, the Advocate General clearly states that

the definition of ‘project’ under Article 1(2)(a) of Directive 2011/92 [Environmental Impact Assessment Directive] includes the extension by 10 years of the period of industrial production of electricity by a nuclear power station

and that

public participation must take place in accordance with Article 6(4) of Directive 2011/92 as early as possible, when all options are open, that is to say, before the decision on the extension is taken.42

The ECJ is not bound by, but generally follows, the advice of the Advocate General; however, so far, the ECJ did not send a formal opinion to the Belgian Constitutional Court. Should the ECJ rule in accordance with the Advocate General’s recommendations, this could have major implications also for past or planned lifetime extensions in other countries.

Already in November 2015, Greenpeace Belgium had filed a case at the State Council (Conseil d’État) on similar grounds. As of mid 2019, both cases are still pending.

In May 2017, FANC announced that a series of ultrasonic inspections on the pressure vessel of Tihange-2 did not show any evolution of the hydrogen flakes, nor any new defects. On the basis of these results, FANC authorized the restart of the reactor. FANC later admitted that over 300 additional flaw indications at Doel-3 and 70 additional flaw indications at Tihange-2 exceeded the recording threshold for the first time during re-inspections carried out in 2016 and 2017 respectively. However, FANC concluded that the results were due to evolving complex inspection techniques rather than physical changes.

The technical assessment of the safety implications of the flaw indications remains the subject of intense controversy. Several independent safety analysis reports are highly critical of the restart authorizations. In April 2018, the International Nuclear Risk Assessment Group (INRAG) stated on Tihange-2 that “the risk of failure of the reactor pressure vessel is not practically excluded” and requested that “the reactor must therefore be temporarily shut down”.43 INRAG is currently in contact with the German government about the safety assessment of Tihange-2, which will likely turn into an expert opinion exchange in the near future.

A complaint was filed at the Belgian State Council against the restart of Tihange-2 by the City Region (Städteregion) Aachen cities in February 2016, joined by some 80 other Dutch, German and Luxemburg cities. Both cases are still pending. It is unclear when to expect rulings. The legal consequences of a ruling in favor of the plaintiffs are also uncertain.

Serious Flaws in Reinforced Concrete

In October 2017, Electrabel identified serious flaws in the concrete of a building adjacent to the reactor buildings of Doel-3. These bunkered buildings contain backup systems for the safety of the facilities and are supposed to withstand impact from outside like an airplane crash. According to Engie, some of these “anomalies at the reinforcements of the reinforced concrete [were] present since the construction of the building”.44 Doel-3 was originally expected to be off-line for scheduled maintenance for 45 days, however, the outage lasted 302 days.

Similar problems, to varying degrees, have been identified at Tihange-2 and -3, as well as Doel-4. Engie first announced that Tihange-3, which was shut down on 30 March 2018 for planned maintenance and refueling, would restart by 14 May 2018. It suffered subsequent delays, and on 21 September 2018, Engie stated that the Tihange-3 outage was extended to 2 March 2019, and that the restart of Tihange-2—which was shut down on 19 August 2018—would be delayed from 31 October 2018 to 1 June 2019.

However, some work at Tihange-3 has been moved to the next scheduled outage and the unit went back on-line on 1 January 2019, two months earlier than previously announced. The entire roof of the bunkered building is now scheduled to be replaced during the outage planned for summer 2020, which will significantly extend the shutdown.

On the other hand, while the regulator gave the green light on 11 June 201945, the restart of Tihange-2 was delayed and had been rescheduled several times before finally taking place on 3 July 2019.46

Performance Assessment

The cumulation of planned outages that were extended repeatedly, plus unexpected outages, led to an unprecedented annual record. In 2018, the seven Belgian nuclear reactors cumulated a total of 1,265 outage days, representing an average of six months (181 days) per reactor (see Figure 20), or twice as many as France over the same period (see France Focus). All of the seven units were offline at some point, with cumulated outages reaching between 31 days (Tihange-1) and 276 days (Tihange-3) per reactor.

Sources: ENTSO-E and Engie Transparency Platforms, 2019


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

“Planned” and “Forced” unavailability as published by ENTSO-E. The Doel-1 unavailability, presented here as forced (according to ENTSO-E) during its whole duration, is listed as “planned” by ENGIE for 248 days in 2018. See Figure 21 and Figure 22.

Sources: ENTSO-E and Engie Transparency Platforms, 2019


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

“Planned” and “Forced” unavailability as published by ENTSO-E. The Doel-1 unavailability, presented here as forced (according to ENTSO-E) during its whole duration, is listed as “planned” by ENGIE for 248 days in 2018. See Figure 22.

Lifetime Extensions = Extended Outages?

The Federal Agency for Nuclear Control (FANC) notes in its March 2019 national progress report on the stress tests of nuclear power plants that review and assessment “progresses slightly slower than expected”. The reasons indicated are workload related, for both licensee and regulator, triggered by the “safety events that occurred in 2018” and “by other safety projects (Long Term Operation of Tihange-1 or Doel-1 and -2) that are resource-intensive for both organizations.”47 While only three of 365 upgrading actions by the operator were still outstanding by the end of 2018, the regulator still had to approve and confirm one quarter of the global action plan.

On 23 April 2018, Doel-1 was closed following a leak in a back-up pipe on its primary cooling circuit. This unplanned outage was at first expected to last around 1.5 days, then 6.5 days. But the damage was worse than anticipated and on 27 April 2018, it was decided to bring forward an outage originally scheduled to start at the end of May 2018. The outage was to last 154 days, to 1 October 2018, one month longer than initially predicted. In August 2018, Engie declared that “Doel-1 and -2 are currently in a planned overhaul. This long overhaul was planned in order to extend the exploitation of the units for ten more years.”48 The Doel-1 outage turned from “unplanned” to “planned” and was extended progressively to 318 days (see Figure 22).

Source: Engie Transparency Platform, 2019


Overview of subsequent versions of unavailability messages for the Doel-1 “Unplanned Outage” after the discovery of a leak in the emergency cooling water circuit and the following “Overhaul Outage”. “Planned” and “Forced” outages as declared by ENGIE.

Doel-2 was shut down on 22 May 2018 for backfitting/upgrading for lifetime extension with a planned restart on 8 October 2018. In reality, the unit went back on-line only on 4 February 2019.

In most cases it is virtually impossible to identify the precise reasons for extended outages, as unexpected events interact with regular maintenance, post-3/11 upgrading and measures aimed at lifetime extensions. Beyond the repair work, additional monitoring is requested by the regulator on parts that have turned out to be damaged beyond expectation (in both recent cases, the concrete flaws and emergency cooling circuit leaks).

Compliance Issue Solved

As reported in WNISR2018, on 7 June 2018, the European Commission had decided to send a reasoned opinion to Belgium “for not having notified transposition measures required under the Nuclear Safety Directive (Council Directive 2014/87/Euratom)”.49 Belgium was given two months’ time to reply to the reasoned opinion, as well as to adopt and communicate all the necessary measures to ensure full and correct transposition of the Directive into national law. As the Commission considered the elements communicated by Belgium satisfactory, it closed the case on 7 March 2019.

China Focus

  • Under Construction 10
  • Operating 47
  • Long-Term Outage 1
Number of Reactors
Mean Age of Reactor Fleet

China continues to expand its nuclear power sector and now operates the third largest reactor fleet, behind the United States and France. As of 1 July 2019, China had 47 operating reactors with a total net capacity of 44.5 GW, and one reactor in Long-Term Outage or LTO. The Chinese nuclear fleet is very young with an average age of 7.2 years (see Figure 23 and Table 23). In 2018, nuclear power contributed 277 TWh, which constituted 4.2 percent of all electricity generated in China, a slight increase from 3.9 percent in 2017. This compares with wind power that injected 366 TWh and solar 177.5 TWh into the grid respectively.50 In other words, electricity generated by wind energy alone continues to exceed the nuclear contribution, and solar energy is rapidly catching up. Wind and solar combined now outproduce nuclear by almost a factor of two. (For more details, see the Nuclear Power vs. Renewable Energy chapter).

In general, the outlook for nuclear power in China appears to be significantly dimmer than it was just a few years ago. Nuclear Intelligence Weekly (NIW) reports that since 2015,

capital investment in the nuclear sector has been in steady decline and last year [2018] registered a total of 43.7 billion yuan (US$6.5 billion), down 3.8% from 2017. Investment in nuclear has been less than in most other power sectors due to the lack of newbuilds.51

Sources: WNISR, with IAEA-PRIS, 2019

A key reason is the high costs. A former head of the Energy Research Institute (ERI) of the National Development and Reform Commission (NDRC), the key state planning agency, explains that nuclear power “has begun to face price competition, and will certainly face more competition in the future”.52

Despite this decline, China continues to be the country with the largest number of nuclear reactors under construction. There are 10 units totaling 8.8 GW under construction, nearly one quarter of a global total of 46 reactors underway as of mid-2019 (see Annex 7, Table 27). The International Atomic Energy Agency (IAEA) still does not list the CFR-600 fast neutron reactor as being under construction. However, media reports suggest that the first pour of concrete for this project occurred in December 2017, with commercial operation expected in 2023.53 Thus, WNISR considers the unit as under construction.

The figure of 10 reactors under construction is significantly below the figure of 16 one year earlier, and of 20 two years before. This new-build decline is a clear demonstration of the slowdown of the Chinese nuclear power program.

At least three of the 10 reactors under construction are delayed: the first two Hualong One (HPR-1000) reactors being built at Fuqing, and the High Temperature Gas Cooled Reactor at Shidaowan (more on the latter in the chapter on Small Modular Reactors). Progress on the HPR-1000 design is especially interesting, because its timely completion will have a bearing on the attractiveness of China as a source of nuclear reactors, since it is this specific design that China is planning to export to other countries.

When pouring of concrete commenced for the second HPR-1000 at Fuqing (Fuqing-6) in December 2015, China National Nuclear Corporation (CNNC) stated that Fuqing-5 and -6 were “scheduled to be completed in 2019 and 2020, respectively”.54 Even last year, one article on nuclear power in China reported “CNNC says it will have one reactor operating in 2019, ahead of schedule”.55 The “ahead of schedule” claim has been repeated, including by CNNC in April 2019 when it began cold hydrostatic testing of Unit 5 of the Fuqing nuclear power plant.56 However, if one looks at past examples, the time it has taken to go from cold testing to grid connection ranges from 16 months (Hongyanhe-1) to 10 months (Ningde-3), suggesting that it is unlikely that Fuqing-5 will be connected to the grid before 2020.

China connected seven reactors to the grid in five months (between May and October 2018), and two in June 2019. These included two EPRs (Taishan-1 and -2), four AP-1000s (Sanmen-1 and -2, and Haiyang-1 and -2) and one ACPR-1000 (Yangjiang-6). The EPRs and the AP-1000s were both high-profile flagship projects for these two designs and much rested on the success of these projects. The Sanmen project was touted as “the biggest energy cooperation project between China and the United States” by the head of the National Energy Administration in 2009.57

As previous issues of the WNISR have documented in detail, eight of those nine reactors were delayed, and for most of them completion took about twice as long as predicted at the time of construction start (see Figure 10). The delays were largely a result of the designs not being finalized, quality problems during constructions and safety concerns.

Whatever those causes, the net result is that the market for AP-1000 reactors and EPRs in China has all but evaporated. An example is the Zhagzhou site in Fujian, which some news sources have identified as having been earmarked for AP-1000 reactors earlier,58 but is now likely to be the next site for the construction of another Hualong power plant.59 CNNC’s decision to construct a Hualong reactor there was explained by the dean of the College of Energy at Xiamen University: “The problem with AP1000—the delays, the design changes, the supply chain issues and then the trade problems—has forced their hand, and it has become Hualong”.60

The problems with imported reactor construction have also affected the prospects for the domestically designed Hualong. While the latter is clearly the preferred choice for new construction, the Chinese government has not been granting the requisite permissions for a rapid buildup. In February 2017, China’s National Energy Administration (NEA) reportedly approved the construction start of eight new reactors.61 But more than two years later, none of those have actually started construction. Again, in February 2019, the State Council was reportedly “close to formally approving two twin-unit Hualong-One projects, in Zhangzhou and Huizhou”.62 As of the time of writing, none of them had come through. This is not to say that no new projects will be approved. But it is clear that nuclear power construction has slowed down and at this point, there is no sign that this will not stay that way.

The repeated delays have finally led Chinese officials to admit to what previous issues of the WNISR had already established—that is China will not meet its declared target of an installed capacity of 58 GW of nuclear power by 2020. In April 2019, China Electricity Council Vice Chairman Wei Shaofeng told the China Nuclear Energy Sustainable Development Forum in Beijing that “total nuclear capacity is expected to reach 53 GW next year”.63 The other, less often talked about, target of having 30 GW of nuclear power capacity under construction as of 2020 is also virtually impossible at this point.

China continues to be on the lookout for opportunities to export the HPR-1000. The only reactors of the design under construction outside China are at the Karachi Nuclear Power Plant (KANUPP) in Pakistan, and those are reportedly still on schedule for commercial operation in 2021 and 2022.64 Over “80 percent of the estimated project cost is being financed through a loan from China’s state-owned Export-Import (Exim) Bank”.65

There are reports of China being close to signing a deal with Argentina to export one HPR-1000 reactor, which has been valued at US$8 billion66 to US$10 billion.67 The two countries have been exploring reactor construction for many years now, but as of mid-2019, a final agreement had not been reached. A key reason for the progress of the deal appears to be China’s willingness to offer a “loan from the Industrial and Commercial Bank of China (ICBC), which will cover 85% of the plant’s construction costs”.68

Finally, the other major hope of exports for China is in the U.K., where China’s strategy has revolved around first getting a toehold in the market by collaborating with EDF on its Hinkley Point project, and then, if that project proceeds, a significant role in the Sizewell C nuclear power station project.69 The Hualong reactor design is being assessed by the regulatory authority with proposals to build it at Bradwell (see U.K. Focus for more information).

Finland Focus

  • Under Construction 1
  • Operating 4
Number of Reactors
Mean Age of Reactor Fleet
Annual Load Factor

Finland operates four units that in 2018 supplied 21.9 TWh of electricity, compared to 21.6 TWh in 2017 and the maximum of 22.7 TWh in 2013. The nuclear share represented 32.4 percent of the nation’s electricity in 2018, compared to 33.2 percent in 2017 and the highest share of 38.4 percent in 1986. On 7 March 2019, the Cabinet approved the operating license for Finland’s fifth reactor, the 1.6 GW EPR at Olkiluoto (OL3), which has been under construction since August 2005.70 The reactor has had multiple revised startup dates; in March 2019, the target date for grid connection was April 2020, 15 years after construction start and 11 years later than originally planned.71

Finland has already adopted different nuclear technologies and suppliers, as two of its operating reactors are VVERs (Vodo-Vodianoï Energuetitcheski Reaktor) 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. The average age of the four operating reactors is 40.3 years. In January 2017, operator TVO (Teollisuuden Voima’s) filed an application for a 20-year license extension for the respectively 39 and 37-year old units Olkiluoto-1 and -2.72 On 20 September 2018, the Cabinet approved the lifetime extension for Teollisuuden Voima’s (TVO) Olkiluoto1 and 2 to operate until 2038.73

There are improved prospects for additional lifetime extension of nuclear reactors in Finland following the announcement on 4 June 2019 of the coalition government’s carbon neutral 2035 objective. The government program states: “We view extended permits for existing nuclear power plants positively, provided that the Radiation and Nuclear Safety Authority is in favour of them”.74 Analysis of the scenario of a fossil free energy system is predicated on 36 TWh of nuclear generation, 64 percent higher than in 2018.75 While the operation of OL3 could make up part of this added generation, lifetime extensions would be required also for the Soviet designed Loviisa1 and 2. The Loviisa reactors began operation in February 1977 and November 1980 and are licensed to operate until 2027 and 2030, respectively. Alternatively, the production goal would mean the completion and operation of the 1200 MW AES-2006 Hanhikivi-1, not yet under construction, but scheduled to begin operation in 2028.

Olkiluoto-3 (OL3)

In December 2003, Finland became the first country to order a new nuclear reactor in Western Europe since 1988. AREVA NP, then a joint venture owned 66 percent by AREVA and 34 percent by Siemens,76 was contracted to build the EPR at Olkiluoto (OL3) under a fixedprice turnkey contract with the utility TVO. After the 2015 technical bankruptcy of 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 majorityowned by state utility EDF. However, EDF made it clear that it will not take over the billions of euros’ liabilities linked to the costly Finnish AREVA adventure.77 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$2.3 billion) capital increase, most of which was to cover the costs to AREVA of the OL3 project.78

The OL3 project was financed essentially on the balance sheets of the Finland’s leading firms and heavy energy users as well as a number of 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 “takeorpay 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, as that date—and other dates—passed, in its 2015 Annual Report, TVO stated: “According to the schedule updated by the Supplier, regular electricity production at OL3 will commence at the end of 2018”.79

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 October 2017 that it had again delayed planned commercial operation from November 2018 to May 2019, with grid connection planned for December 2018.80 TVO then announced in April 2018 that fuel loading was delayed until autumn 2018 (prior to this it had been scheduled for April 2018).81 A further delay was announced in June 2018, with grid connection planned for May 2019, and “regular electricity generation” in September 2019.82 That target has now been missed as well. In April 2019 fuel loading was pushed further to August 2019. However, given the need to verify the effectiveness of the measures implemented by TVO to counter vibration in the pressurizer surge line (see hereunder), it is likely that fuel loading will be further delayed.

TVO’s claims of grid connection in October 2019 and electricity generation by January 2020 were considered by WNISR as highly optimistic.83 On 17 July 2019, TVO confirmed further delays to OL3. The revised schedule provided by plant supplier AREVA/Siemens to TVO reported that nuclear fuel loading is now planned from January 2020, with grid connection in April 2020 and commercial operation from July 2020. TVO Director of the OL3 project, Jouni Silvennoinen, stated thatAlthough, the completion of the plant unit will be further delayed, we are currently working to reach the fuel loading phase and to take over the OL3 EPR unit.”84

OL3 was cited by the nuclear industry as a showcase for next-generation reactor technology with TVO and AREVA predicting 56 months to completion. However, WNISR predicted nearly a decade ago that the project would lead to a crisis,85 which has turned out to be correct as its total construction time to operation on the current schedule of January 2020, will be 188 months, and operation more than ten years behind schedule.

OL3 Pressurizer Vibration

A major factor that has contributed to the delays in the OL3 project during the past 12 months has been a significant technical safety issue. During hot functional testing (HFT) of OL3, which was completed in May 2018,86 excessive vibration was detected in the pressurizer surge-line which contains high temperature and radioactive reactor coolant under high pressure. The vibrations were outside the permitted safety margin.87

The pressurizer surge-line is a Category 1 component (nuclear class I) and seismic category I. It is one of the most important components in maintaining the integrity of the primary pressure boundary. The pressurizer controls the Reactor Coolant System (RCS) pressure by maintaining the temperature of the pressurizer liquid at the saturation temperature corresponding to the desired system pressure with heaters and spray. TVO, at completion of HFT, reported in June 2018 that “the pressurizer surge line vibrations that delayed the hot functional tests will be corrected before fuel loading.”88

Vibration outside operational license and design base conditions can be considered a major safety issue, since it could lead, in the worst case, to significant internal pipe damage, including the break of the pressurizer surge-line. A likely cause of the vibration is thermal stratification in the surge line which is greatest during heat-up and cooldown because the temperature difference between the pressurizer and hot leg is then the largest.89

The Finnish safety regulator STUK, while reporting to the Government in February 2019 that operation of the OL3 would be safe, noted that before fuel loading could be authorized, technical solutions needed to be applied to suppress the pressurizer surge-line vibration of the primary circuit. STUK would “supervise the work and verify before the loading of fuel that the alteration works have been performed and the operability of the solution has been tested.”90

On 23 May 2019, TVO announced that it had “resolved” the surge-line vibrations.91 In practice, TVO has begun the installation of viscous bitumen liquid absorbers with the aim of dampening the vibration effects, with a target of completing installation in late spring. As of 1 July 2019, work was ongoing. Interestingly, a vibration problem has been confirmed also in the Taishan1 EPR in China, where a “muffler” system has been installed. TVO chose the bitumen/viscous system “because there is more vibration at Olkiluoto-3 than at Taishan and the viscous system seemed to work better.”92

OL3 Costs

As WNISR has documented over the years, the EPR has been a financial disaster. In March 2018, TVO and AREVA announced that they had reached agreement on the completion of OL3, settling all related disputes.93 In relation to costs and losses caused by the delays, financial compensation of €450 million was to be paid by AREVA to TVO in two installments. There was also a commitment by AREVA that there were sufficient funds for completion of OL3 and that they will cover all applicable guarantee periods, including setting up a trust mechanism funded by AREVA to secure the financing of the costs of completion of the project. The settlement agreement also stipulated that in the event that AREVA fails to complete the project by the end of 2019, they will pay a penalty to TVO that may not exceed €400 million (US$450 million).

With the confirmation of the settlement and TVO disclosing its total investment, it is possible to indicate the cost of the Finnish EPR. TVO’s current capital expenditure assumptions and the effect of the settlement agreement estimates its total investment to be around €5.5 billion (US$6.42 billion); on top of this AREVA had losses of €5.5 billion, for a total of €11 billion (US$12.4 billion) compared with the initial estimate cost in 2003 of “around €3 billion”.

Rather prematurely, the International Atomic Energy Agency (IAEA) in 2005 proclaimed that “The EPR becomes reality at Finland’s Olkiluoto3”.94 Fifteen years later, it is possible that by the time of WNISR2020 the OL3 reactor will be operating. But the multiple failures and enormous cost overruns during the past 14 years of construction have had a major impact on the prospects for nuclear power in Europe and beyond. Touted as spearheading a nuclear renaissance,95 it has instead exposed the implementation difficulties of even a single reactor project.

In Finland there is no more talk of a second EPR as OL4, as originally planned. Nearly a decade ago, Steve Thomas, energy economist and past contributing author to the WNISR, wrote:

The promise for Generation III+ plants that they would: ‘have the advantage of combining technology familiar to operators of current plants with vastly improved safety features and significant simplification is expected to result in lower and more predictable construction and operating costs’ has clearly not been fulfilled... As early as 1995 and again in 1997, there were concerns about the cost of the EPR then expected to be US$2000/kW.... At US$6000/kW or more, it seems unlikely that the EPR will be affordable except where huge public subsidies are offered and/or there is a strong likelihood of full cost recovery from consumers, no matter what the cost is.96

And as WNISR reported already in 2009: “The flagship EPR project at Olkiluoto in Finland, managed by the largest nuclear builder in the world, AREVA NP, has turned into a financial fiasco.”97

In the ten years since then, the experience of the OL3 project has only further confirmed these analyses.


In addition to OL3, in January 2009, the company Fennovoima Oy applied to the Ministry of Employment and the Economy for a decision-in-principle on a new nuclear plant at one of three locations—Ruotsinpyhtää, Simo, or Pyhäjoki. This was narrowed down to the latter site. Fennovoima Oy was established by a consortium of Finnish power and industrial companies. As with OL3, there was an unrealistic startup date given for 2020. In March 2014, Rosatom, through a subsidiary company RAOS Voima Oy, completed the purchase of 34 percent of Fennovoima for an undisclosed price,98 and then in April 2014 a “binding decision to construct” a 1200 MW AES2006 reactor was announced.

In December 2014, the Finnish Parliament voted in favor of a supplement to the decision-in-principle to include Rosatom’s reactor design.99 A construction license application was submitted at the end of June 2015. In September 2015, the Finnish Nuclear Safety Authority STUK began assessing the project called Hanhikivi1, which at the time was reported would take until the end of 2017.100

However, site-preparation work and rock blasting reportedly already began in January 2016.101 Actual construction was scheduled to start some time in 2018, with completion expected in 2024.102 However, as WNISR2018 reported, the schedule was not credible—just like in many other Rosatom projects—as the “first batch of documentation” for the construction license application was only transmitted to the Finnish safety authorities on 1 November 2016.103 Subsequently, in November 2017, Fennovoima Oy was instructed by STUK to “improve their operations before they are in a position to start the construction work.”104 STUK warned that “among other things, Fennovoima must improve the supervision of the organizations involved in the planning and construction of the nuclear power plant. The safety culture of RAOS Project, which is the plant supplier, and the main contractor Titan 2 currently does not fulfill the Finnish expectations”.105

A 2013 assessment of the AES-2006 reactor concluded that a “long list of safety issues shows that a sufficient level of protection against external and internal impacts as well as the functionally [functionality] of the safety systems had not been demonstrated in a sufficient manner to allow STUK to conclude a positive review. Up to now, a severe accident cannot be excluded due to the design of the AES2006.”106 The STUK review process is ongoing. In December 2018, Fennovoima Oy announced that they had a received a new revised schedule from the plant supplier RAOS Project.107 This projected that a construction license would be secured in 2021 and construction begun in the same year, with operation of the plant pushed back to 2028. With construction not yet started, the Hanhikivi1 project is already eight years behind the original schedule.

France Focus

  • Under Construction 1
  • Operating 58
  • Closed 12
Number of Reactors
Mean Age of Reactor Fleet
Annual Load Factor

Multi Annual Energy Plan and The Energy Bill

In April 2019, the French Government tabled a bill at the National Assembly on the basis of the draft Multi Annual Energy Plan (PPE). The PPE is a planning tool introduced in the 2015 Energy Transition Law that will define the framework of the French energy landscape to 2023 and beyond. The PPE sets the priorities of action for public authorities concerning all forms of energy generation as well as energy efficiency. It will also determine the near-term future of nuclear power in setting targets for installed capacity and therefore the potential closure of a number of reactors. The bill has passed both chambers in the first reading and on 19 July 2019 a mixed commission was appointed to elaborate compromise solutions to outstanding issues under an accelerated procedure.108

WNISR2018 stated:

The state-controlled utility Électricité de France (EDF) seems to live in a different world and stated in its contribution to the PPE consultation that it “envisages certain closures” of nuclear reactors “starting 2029”.109 The startling suggestion simply ignores the current legislation that stipulates a reduction of the nuclear share in the French power mix to 50 percent by 2025 and the context of the entire debate.

In fact, EDF got its way to some extent, and the government’s draft bill, while maintaining the 50percent target, moves it from 2025 to 2035. According to the government, maintaining the 2025 deadline would have meant the construction of new gas-fired power plants, “in contradiction with our climate objectives”110, a position contested by its own Energy Management Agency ADEME.111 At the same time, it raises the stakes on the phase-out of fossil fuels, increasing the 2030 target from –30 percent to –40 percent (baseline 1990) and thus reducing the overall 2050-greenhouse-gas emissions by a factor of more than six rather than four. The last coal-fired power plant is to be closed by 2022. However, this could be delayed as the Flamanville3 EPR will not be in operation until then (see hereunder).

According to the government model, achieving a reduction to 50 percent of the nuclear share in the electricity mix would lead to the closure of 14 reactors by 2035, including the two oldest units at Fessenheim in spring 2020, and two to four additional units by 2028. Achieving the 2025 target would have meant the closure of 24 reactors over a shorter time span.

The draft law does not mention spent fuel management, but the PPE—citing jobs, reduction in natural uranium use and spent fuel generation, as well as “a better containment for the final waste”—stipulates that the “spent fuel-reprocessing and -recycling policy must be maintained”.112

French Nuclear Power Performance Remains Poor

In 2018, 58 operating reactors113 in France produced 395.91 TWh, a significant improvement (+14.1 TWh or +3.7 percent) over the previous year. However, it is the third year in a row that generation remained below 400 TWh. In 2005, nuclear generation peaked at 431.2 TWh.

Nuclear plants provided 71.7 percent of the country’s electricity, only 0.1 percentage point better than in 2017, which was the lowest share since 1988. The share stabilized after declining four years in a row at almost 7 percentage points below the peak year of 2005 (78.5 percent).

France’s load factor at 69.6 percent was still poor in 2018 but improved since a record low of 55.6 percent in 2016, then second lowest in the world behind Argentina. The lifetime load factor remains constant below 70 percent (69.3 percent). According to operator EDF:

In 2018, generation performance was affected by exceptional damages and large generation incidents (costing around 12.5 TWh), longer-than-expected outages (costing around 5 TWh) and environmental constraints (costing around 2 TWh). The outage extensions experienced in 2018 were caused in equal measure by maintenance and operational quality issues, technical failures and project management deficiencies. Performance losses related to unplanned outages rose from a rate of 3.26% in 2017 to 3.7% in 2018 because of several exceptional incidents.114

Environmental constraints refer to operating restrictions for several nuclear plants because of lack of cooling water or excess water temperatures. The heat wave in the summer of 2019 led again to the closure or output reduction of several reactors, including the two Golfech units and the two SaintAlban units.

Power Trade

For many years, France was Europe’s largest electricity exporter, but in 2016, net exports dropped by 36.6 percent to 39.1 TWh, while Germany’s net power exports hit a new record at 53.7 TWh. For the first time, Germany overtook France and became the biggest net power exporter in Europe.115 In 2017, this trend was reinforced, with France’s net exports shrinking again to 38 TWh net,116 while Germany’s net exports increased again to some 55 TWh,117 with France being the second largest net importer from Germany with 13.7 TWh.118 In January 2018, France imported just under 1 TWh net, “a level that had never been reached”, according to RTE.119 However, over the year 2018 with particularly high output of its hydro plants due to favorable climatic conditions, France exported 60.2 TWh net and recovered its position as the largest net exporter in the EU,120 with Germany exporting 51.2 TWh net. At the same time, France fell back to the third largest net importer from Germany with 8.9 TWh, but keeps importing from Germany more than from any other country. 121

Nuclear Unavailability Review 2018

The analysis of the unavailability of French nuclear reactors in 2018 shows:

  • A minimum of four French reactors have been down (zero capacity) at the same time.
  • A maximum of 27 of the 58 units were down at the same time.
  • On 38 occasions, 18 units were down during the same day.
  • One 50 occasions, 16 units were down during the same day.

The total number of zero output days of the French reactor fleet exceeded 5,000 days in 2018, an average of 87.6 days per reactor or an outage ratio of a quarter of the time, not including load following or other operational situations with reduced but above-zero output e.g. as during the heat wave (see Figure 24 and Figure 25).

Sources: RTE and EDF, “List of outages”, 2019122


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.

Some of the longest outages include:

  • Cattenom-2 (182 days): The unavailability included 141 days for the third decennial review (VD3)123, preceded by 41 days for “maintenance” work.
  • Dampierre-4 (193 days in 2018): The outage was mainly due to the VD3 that progressively increased from an expected 50 days to 191 days.
  • Gravelines-6 (210 days in 2018): The shutdown was essentially due to the VD3 that was progressively extended from a scheduled 164 days, when it started, to 208 days. This is even more remarkable as the VD3 was originally to include the replacement of the reactor’s three steam generators, an operation delayed to 2020 because the Nuclear Safety Authority (ASN) did not deliver the necessary quality certificates for the new equipment. This means another long outage is to be expected for 2020.

Sources: Compilation from RTE, 2019


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.

Lifetime Extension, ASN and the Fourth Decennial Reviews

The average age of France’s 58 power reactors was 34.4 years by mid-2019 (see Figure 26). In the absence of new reactor commissioning and any closure, the fleet is aging by one year every year.

Lifetime extension beyond 40 years of some reactors—47 operating units are now over 31 years old—would require significant additional upgrades. Also, relicensing will be subject to public inquiries reactor by reactor.

Operating costs have increased substantially over the past years. Investments for lifetime extensions will need to be balanced against the already excessive nuclear share in the power mix, the stagnating or decreasing electricity consumption in France—it has been roughly stable for the past decade—and in the European Union (EU) as a whole, the shrinking client base, successful competitors, and the energy efficiency and renewable energy production targets set at both the EU and the French levels. EDF claims that the power generating costs for existing reactors would be €32/MWh (US$38/MWh), including nuclear operating and maintenance costs (€22/MWh including fuel at €5/MWh) and all anticipated upgrading costs for plant life extension to 50 years (10 €/MWh) remain more economic than “any new alternative”.124 However, there are serious questions about these numbers. Michèle Pappalardo, former Ecology Minister Nicolas Hulot’s Chief of Staff and former senior representative of the Court of Accounts, remarked during the hearings of the Inquiry Committee that EDF’s calculation stopped mid-way in 2025, and recalled that the Court had calculated a total cost of €100 billion (US$117 billion) for the period 2014–2030.125

Sources: WNISR, with IAEA-PRIS, 2019

Apart from the two oldest French reactors at Fessenheim, now planned to be definitively closed in spring 2020, EDF will seek lifetime extension beyond the 4th Decennial Safety Review (VD4) for most if not all of its remaining reactors. This is in line with the Government’s Multi Annual Energy Plan, which plans for no further reactor closures until 2023 (the end of the current presidential term) and only a limited number in the following years. This program will be limited to 900 MWe reactors, the oldest segment of the French nuclear fleet. The first reactors to undergo the VD4 are scheduled to include Tricastin1 in 2019, Bugey-2 and -4 in 2020, and Tricastin-2, Dampierre-1, Bugey-5 and Gravelines-1 in 2021.

EDF expects these VD4 outages to last six months, longer than the average of three to four months experienced through VD2 and VD3 outages. However, as illustrated by the recent outage history, many factors could lead to significantly longer outages.

Detailed generic requirements for plant life extension have not been issued yet by the Nuclear Safety Authority (ASN). Originally, these requirements were to be issued in 2016 but their release has been postponed a number of times, due to the need for extended and often unprecedented technical discussions. The general objective of ASN has been to bring the reactors “as close as possible” to the safety level required in new reactor designs, such as the EPR under construction in Flamanville. This is strikingly different from other countries, and notably the U.S., where safety authorities merely request to maintain a given safety level.

ASN now plans to issue its generic order by 2020, which is particularly critical for Tricastin-1, the first unit scheduled to undergo the VD4, starting in 2019. The case will be particularly sensitive to unexpected difficulties. For example, the requirement to introduce a kind of core-catcher126 would be a first in an existing reactor.

It is clearly expected that the amount of work to be completed as part of the VD4 will be much more important than for VD3, and EDF might have underestimated the resulting workload, or overestimated its capacity to deliver on it. 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 VD4.127

The timely delivery of this work is likely to stretch the industrial capacity of EDF and its subcontractors beyond its current limits. ASN has recently pointed to the need for the operator to restore its level of industrial control as a top priority for nuclear safety.128

The Ongoing Flamanville-3 EPR Saga

At this stage, commissioning cannot be expected before end of 2022.

EDF, 25 July 2019129

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. In December 2007, EDF started construction on FL3 with a scheduled startup date of 2012. The project has been plagued with detailed-design issues and quality-control problems, including basic concrete and welding similar to those at the Olkiluoto (OL3) project in Finland, which started two-and-a-half years earlier. These problems never stopped and 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.”130 In fact, the delay will be several years, and the startup of FL3 is now not expected before the end of 2022.

In a letter of 19 June 2019, ASN informed EDF that “in the light of the numerous deviations in the production of the Flamanville EPR penetration welds, they would have to be repaired”131. ASN pointed out in the letter, signed by the Chairman:

ASN considers that, given the number and nature of the deviations affecting these welds, their break can no longer be considered as highly improbable and that a break preclusion approach can no longer be applied to them. [Bold font in the original.]132

ASN explains on its website:

In 2018, EDF had proposed an approach aiming to justify maintaining these welds as they were. ASN then considered that the outcome of such an approach was uncertain and had asked EDF to begin preparatory operations prior to repair of the welds located between the two walls of the reactor containment [consult information notice published on 03/10/2018].

EDF’s approach was reviewed by ASN, with technical support from IRSN [French Institute for Radiation Protection and Nuclear Safety], including consultation of the Advisory Committee for Nuclear Pressure Equipment (GP ESPN) [consult information notice published on 11/04/2019].

Until the latest discovery, FL3 was expected to start generating power in May 2019, reaching full capacity in November 2019. 133 The official cost estimate for FL3 stood at €10.5 billion (US$12.3 billion) as of 2015134. After a series of additional mishaps and delays, in July 2018, the owner-builder stated: “The EDF group has therefore adjusted the Flamanville EPR schedule and construction costs accordingly. The loading of nuclear fuel is now scheduled for the 4th quarter in 2019 and the target construction costs have been revised from €10.5 billion [US$12.3 billion] to €10.9 billion [US$12.7 billion]”.135 EDF revised its position in July 2019 and announced that, concerning the FL3 steam line repair work, it “expects to communicate the schedule and cost implications of the selected scenario in the next few months”, already certain that “commissioning cannot be expected before the end of 2022”.136

This latest delay raises another legal problem. The construction license, which had already been extended in 2017, will run out on 10 April 2020.137 On 23 July 2019, EDF filed a new application to amend the construction license.138 This time, it will likely entail a new public enquiry.

FL3 is now at least a decade behind schedule.

Other Ongoing Quality Issues

In April 2015, the French Nuclear Safety Authority (ASN) revealed that the bottom piece and the lid of the FL3 pressure vessel had “very serious” defects.139 Chemical and mechanical tests “revealed the presence of a zone in which there was a high carbon concentration, leading to lower than expected mechanical toughness values”.140 Both pieces were fabricated and assembled by AREVA in France, while the center piece was forged by Japan Steel Works (JSW) in Japan. ASN stated then that the same fabrication procedure by AREVA’s Creusot Forge was applied to “certain calottes” (also called bottom heads and closure heads) of the two pressure vessels made for the two EPRs under construction at Taishan in China, while the EPR under construction in Finland was entirely manufactured in Japan. AREVA’s challenge was to prove that, although clearly below technical specifications, the EPR pressure vessels could withstand any major transient. After a lengthy and controversial re-qualification procedure (see WNISR2017 for details), ASN released its official judgement on the issue considering the “mechanical characteristics” of vessel cover and bottom “adequate”. However, ASN “considers that the use of the closure head must be limited in time” and as a new closure head could be available by 2024, the current piece “shall not be operated beyond that date”.141

In a more recent development, ASN investigations at the Framatome subcontractor JSW’s factory in Muroran, Japan, that manufactures the replacement vessel head for FL3 and components for replacement steam generators for French 1300 MW reactors, revealed some serious flaws, including:

  • The incapacity to prove a constant temperature during the forging process;
  • The use of pencils in process documentation;
  • Hand-written, unsigned, undated corrections on quality documentation.142

    Ongoing Fallout from Creusot Forge Affair

Meanwhile, the finding of carbon segregations in the pressure vessel of FL3 had raised concerns about the possibility that other components could have been fabricated below technical specifications due to poor quality processes at Creusot Forge.143 On 25 April 2016, AREVA informed ASN that “irregularities in the manufacturing checks”, the quality-control procedures, were detected at about 400 pieces fabricated since 1969, about 50 of which would be installed in the French currently operating reactor fleet. The “irregularities” included “inconsistencies, modifications or omissions in the production files, concerning manufacturing parameters or test results”.144 The most serious regulatory violation led ASN to withdraw the certificate of a replacement steam generator introduced in Fessenheim-2 in 2012, because the forging process of its central part did not comply with qualified methods, and this was covered in the documentation submitted to ASN and EDF, leaving the reactor shut down between June 2016145 and April 2018. According to EDF, in total, it has detected 1,775 “anomalies” in parts that were integrated into 46 reactors.146 According to EDF, as of the end of January 2019, 54 reactors had obtained ASN’s green light for restart “confirming the operational safety of the concerned components”.147 This means that in the case of the remaining four units ASN still has not confirmed the safety of the respective incriminated parts.

The Ongoing Tricastin Canal Embankment Case

The Tricastin Nuclear Power Plant

Photo: www.asn.fr

On 27 September 2017, ASN required that “EDF temporarily shut down the four reactors of the Tricastin nuclear power plant as rapidly as possible”, because of the “risk of failure of a part of the embankment of the Donzère-Mondragon canal with regard to the most severe earthquakes studied in the nuclear safety case.”148 ASN’s technical backup Institute for Radiation Protection and Nuclear Safety (IRSN) released a briefing that stated that the plant had not been designed to withstand flooding from the canal. Such an event would “lead to the total loss of cooling of the fuel in the core and in the spent fuel pool of every reactor leading to the meltdown of that fuel”.149

On 5 December 2017, ASN validated the embankment repair work carried out by EDF and granted permission for restart of the Tricastin reactors.150 On 25 June 2019, ASN requested additional work to reinforce the embankment to be carried out by the end of 2022 at the latest. Until then, the ASN requests EDF to implement increased embankment surveillance and guarantee the availability of human and material means to repair potential damage stemming from an earthquake.151

Germany Focus

  • Abandoned Constructions 6
  • Operating 7
  • Closed 29
Number of Reactors
Mean Age of Reactor Fleet
Annual Load Factor

Germany’s remaining seven nuclear reactors generated 71.9 TWh net in 2018, almost matching the 72.2 TWh of 2017, but less than half of the generation of 162.4 TWh in record year 2001. Nuclear plants provided a stable 11.7 percent of Germany’s electricity generation, representing little more than one-third of the historic maximum of 30.8 percent in 1997. One more reactor (Philippsburg-2) will be closed at the end of 2019, according to the nuclear phase-out legislation that will see all reactors closed by the end of 2022 (see Table 4 for details). The average load factor remained stable at 86.7 percent, allowing Germany to keep its third rank in the world (behind Romania and Finland). Three German reactors are still among the ten best lifetime load factors. All seven units that generated power in 2018 are in the Top Ten lifetime electricity generators in the world, five of which are holding positions one to five. (Only three U.S. reactors made it into the Top Ten alongside the German units).152

Renewables cover 16.7% of final energy in Germany, nuclear covers 17.4% of final energy in France.

Germany decided immediately after 3/11 to close eight of the oldest153 of its 17 operating reactors and to phase out the remaining nine until 2022, effectively reactivating a “consensus agreement” negotiated a decade earlier. 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, which makes it virtually irreversible under any political constellation. On 6 June 2011, the 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).

Table 4 | Legal Closure Dates for German Nuclear Reactors 2011–2022

Reactor Name
(Type, Net Capacity)


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)



KKW Brunsbüttela


KKW Krümmelb












6 August 2011

Grafenrheinfeld (PWR, 1275 MW)



31 December 2015

(closed 27 June 2015)

Gundremmingen-B (BWR, 1284 MW)

KKW Gundremmingenc


31 December 2017

Philippsburg-2 (PWR, 1402 MW)



31 December 2019

Brokdorf (PWR, 1410 MW)

Grohnde (PWR, 1360 MW)

Gundremmingen-C (BWR, 1288 MW)



KKW Gundremmingen




31 December 2021

Isar-2 (PWR, 1410 MW)

Emsland (PWR, 1329 MW)

Neckarwestheim-2 (PWR, 1310 MW)


KKW Lippe-Emse





31 December 2022

Sources: Atomgesetz, 31 July 2011, Atomforum Kernenergie May 2011; IAEA-PRIS 2012


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; RWE= Rheinisch-Westfälisches Elektrizitätswerk Power 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%.

Renewables generated 226 TWh representing 35 percent of gross national electricity generation or 38 percent of gross national power consumption in 2018, about half of it from onshore/offshore wind power, which alone, since 2017, by far outgenerates nuclear power. In 2017, renewables covered 15.9 percent of Germany’s total final energy consumption.154 To put this into perspective, in France, nuclear power covered 17 percent of final energy in 2017.155 Provisional figures for 2018 show respective shares of 16.7 percent for German renewables156 and 17.4 percent for French nuclear.157 As renewables accelerate their expansion beyond the power sector throughout the German economy, their share in final energy has increased by more than 5 percentage points since 2010, while the French nuclear share remained about stable (16.9 percent in 2010).

Fossil-fuel-based generation in Germany continued to drop in 2018—hard coal by 10.4 percent, lignite by 2 percent and natural gas by 3.8 percent. Renewables were again by far the largest contributor to the power mix (gross) and supplied more than lignite (22.5 percent) and hard coal (12.9 percent) together, while natural gas also contributed 12.9 percent.158

In 2017, Germany’s net power exports hit a new record at 55 TWh. In 2018, the net exports stood at 51.2 TWh, the fourth year in a row that the trade surplus exceeded 50 TWh.

Figure 27 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 2018.

Source: WNISR based on AGEB, 2019159

It shows that the remarkable increase of renewable electricity generation (+120.9 TWh) and the reduction in domestic consumption (–20.3 TWh) were far more than sufficient to compensate for the reduction of nuclear generation (64.6 TWh), enabling also a reduction in power generation from fossil fuels (–43.5 TWh) and a threefold increase in net exports (+33.5 TWh) (without which the fossil-fueled generation would have been even lower). Within the fossil-fuel generating segment, for the first time in 2018, all primary fuel-uses decreased compared to the previous year and remained below the 2010 level:

  • Lignite peaked in 2013 and then declined to just below the 2010 level (–0.4 TWh);
  • Hard coal also peaked in 2013 then dropped significantly (–33.8 TWh or –28.9 percent below 2010);
  • Natural gas peaked in 2010 and then fluctuated to remain on the lower end (–5.9 TWh or 6.6 percent below 2010)
  • Oil was relatively insignificant and dropped further (–3.5 TWh or 40.2 percent since 2010).

Greenhouse gas emissions from the power sector dropped again by 3.7 percent in 2018, while carbon intensity decreased from 489 gCO2/kWh to 472 gCO2/kWh.160

Japan Focus

  • Abandoned Constructions 1
  • Under Construction 1
  • Operating 9
  • Long-Term Outage 24
  • Closed 27
Number of Reactors
Mean Age of Reactor Fleet
Annual Load Factor

A total of nine reactors are currently operating in Japan. No additional reactors restarted since WNISR2018 under the revised Nuclear Regulatory Authority’s (NRA) safety guidelines, whereas four had done so in the year to May 2018.

One reactor, PWR Ikata-3, which restarted in 2016 and had been in operation until October 2017, was shut down for nearly one year following a first of its kind high court ruling in December 2017 (see WNISR2018). Scheduled to return to operation in January 2018, the Hiroshima High Court issued a citizens-sought injunction against the operation of the reactor on the grounds of seismic and volcano risks. The plant is at risk from the massive Nankai Trough and the Median Tectonic Line fault belt—Japan’s largest-class and longest fault zone, which runs near the Ikata plant site. On 25 September 2018, the Hiroshima High Court reversed its decision,161 lifted the injunction, and permitted the Ikata plant to resume operation on 27 October 2018.162

Two reactors were announced for permanent closure since WNISR2018. Tohoku Electric Power Company announced on 25 October 2018 that the BWR Onagawa-1, that had not produced power since 2011, was to remain permanently off grid.163 Kyushu Electric Power Company on 9 April 2019 issued a formal notification of the closure of its Pressurized Water Reactor (PWR) Genkai-2.164 The Ikata-2 PWR moved to formal closure in October 2018 when the utility, Shikoku Electric Power Company, notified the NRA.165 In March 2018, the utility had announced the Board of Directors’ decision for the permanent closure of the 36-year-old unit.166

As of 1 July 2019, utilities have declared 17 commercial reactors to be decommissioned since the Fukushima Daiichi accident began in March 2011, together with the Prototype Monju Fast Breeder Reactor (FBR). This means that as of 1 July 2019, 24 reactors remain in Long-Term Outage (LTO) since none of these have generated electricity during recent years. WNISR has considered for years that the four reactors at Fukushima Daini will never restart. (See Figure 30 and Annex 3 for a detailed overview of the Japanese Reactor Program).

Sources: WNISR, with IAEA-PRIS, 2019


This Figure takes into account LTO status for Kashiwazaki Kariwa Units 1, 5, 6 and 7 in the wake of the Niigata Earthquake, not shown in previous versions of this graph.

In 2018, nuclear power produced 49.3 TWh, contributing 6.2 percent of the nation’s annual output compared to 29.3 TWh and 3.6 percent electricity share in 2017, and 17.5 TWh and 2.2 percent respectively in 2016 (see Figure 28). This is by far the largest share of nuclear generated electricity in Japan since 2011 (18 percent), compared with 29 percent in 2010 and the historic high of 36 percent in 1998.

As WNISR 2018 reported, restart of additional reactors was not expected in the year to July 2019 and there are now further delays in the restart program. Reactors that were planned for restart in the second quarter of 2019, specifically Takahama-1 and -2, have now been delayed into 2020 and 2021 respectively, while upgrading work at Mihama-3 will not be completed until July 2020, with restart now slated for August 2020, though further delays to all these are possible.167

The industry during the past year has been making important progress in creating favorable electricity market conditions that if implemented will provide significant financial incentives for extending reactor operations beyond 40 years. Specifically, a capacity market will operate in Japan from 2020. The principal beneficiaries of this will be the utilities operating nuclear power plants and coal generation plants.168 At the same time, an unexpected development arose in April 2019 when the Nuclear Regulatory Authority (NRA) voted to impose a strict operational condition on reactors that could lead to the closure of multiple reactors starting in 2020.169 The decision was due to utilities notifying the NRA that they would not meet the deadline for completion of anti-terrorist measures created post-Fukushima. Thus, while Japanese reactors are currently generating the most electricity since 2011, the industry faces the prospect of extended shutdown of these reactors from 2020. As in previous years, a consistent majority of Japanese citizens, when polled, continue to oppose the sustained reliance on nuclear power, support its early phase-out, and remain opposed to the restart of reactors.170

With retail market liberalization, there has been a noticeable loss of market share by nuclear utilities. The alternative to shutting down this capacity (reactor closures) was to create the capacity market where they will sell the surplus kilowatts to the wholesale electricity market. It is expected that a separate capacity market will be created in each of the regions where nine nuclear utilities plus Okinawa operate.171 With longterm contracts and payments, the effect will be to provide additional long-term revenue and incentivize continued reactor operation, including lifetime extensions.172 On the other hand, economic headwind from renewable energy competition and efficient uses of electricity could increase (see Climate Change and Nuclear Power).

Reactor Closures

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 14.7 percent of Japan’s operating nuclear capacity as of March 2011.173 Together with the ten Fukushima units, the total rises to 21 reactors and 15.2 GW or 34.8 percent of operating nuclear capacity prior to 3/11 that has now been permanently removed from operations (see Table 5).

Table 5 | Official Reactor Closures Post-3/11 in Japan






Closure Dateb





Fukushima Daiichi-1 (BWR)







Fukushima Daiichi-2 (BWR)







Fukushima Daiichi-3 (BWR)







Fukushima Daiichi-4 (BWR)







Fukushima Daiichi-5 (BWR)







Fukushima Daiichi-6 (BWR)

1 067







Mihama-1 (PWR)







Mihama-2 (PWR)







Ohi-1 (PWR)

1 120






Ohi-2 (PWR)

1 120







Genkai-1 (PWR)







Genkai-2 (PWR)








Ikata-1 (PWR)







Ikata- 2 (PWR)








Monju (FBR)





LTSf since 1995



Tsuruga -1 (BWR)








Shimane-1 (PWR)








Onagawa-1 (BWR)







TOTAL: 18 Reactors /11.2 GWe

Sources: JAIF, Japan Nuclear Safety Institute, compiled by WNISR, 2019


a - Unless otherwise specified, all announcement dates from Japan Nuclear Safety Institute, “Licensing status for the Japanese nuclear facilities”, 12 February 2019, see http://www.genanshin.jp/english/facility/map/, accessed 30 May 2019.

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 30 May 2019.

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,
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,
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.

g – The decision to close the reactor was announced in October 2018, but not followed by an official closure announcement. However, IAEA-PRIS lists the reactors as closed on 21 December 2018. The JAIF website does not provide a closure date for the reactor.

The revision opened the way for utilities to calculate their decommissioning costs in installments over a period of ten years.

In October 2017, the Federation of Electric Power Companies (FEPC) reported a year-on-year increase of ¥500 billion (US$4.4 billion) to a total of ¥4 trillion ($US35 billion) spent or assigned by nuclear utilities to cover the costs of safety retrofits to their reactor fleet.174

WNISR 2018 projected that the 38-year-old 529 MW Genkai-2 and the 35-year-old 498 MW Onagawa-1 units would be likely next candidates for decommissioning.

A senior manager for Genkai-2 owner Kyushu Electric stated in February 2019 that they were “now considering whether to restart or decommission the reactor from an economic and technical view point”.175 This was followed in April 2019 by the decision for permanent closure.176 The utility had not submitted the reactor for review by the NRA, concentrating on approval and restart of its two newer and larger units Genkai-3 and -4, as well as Sendai-1 and -2. While the host prefecture for the Genkai plant has been generally supportive of nuclear power, an official for Saga Prefecture was cited by Platts as stating that “Kyushu Electric should recognize our policy”, which was “reduce reliance on nuclear power generation as much as possible,” in line with the central government plan for the power mix.177

In the case of Onagawa-1, Tohoku Electric officials had stated in 2017, that they “intend to restart it” but “haven’t reached a conclusion, whether we can do so, because we have to evaluate safety costs and a return from that investment.”178 The utility cited the costs of post-Fukushima safety measures and the relatively small output of the reactor that made a decision to restart unprofitable. On 25 October 2018, Tohoku Electric President Hiroya Harada informed the Miyagi Prefecture Governor Yoshihiro Murai of their decision to close Onagawa-1, which was based on “consideration [of] technical restrictions associated with additional safety measures, output and the years in use.”179

Sources: WNISR, with IAEA-PRIS, 2019

Future announcements on formal decommissioning are expected in 2019. In mid-June 2018, more than seven years after the triple reactor meltdown at the Fukushima Daiichi (1) nuclear plant, Tokyo Electric Power Company Holdings Inc (TEPCO) finally bowed to the inevitable and announced it was considering the decommissioning of the four reactors at Fukushima Daini (2).180 While WNISR over the past years has classified the four reactors as closed, it is only on 31 July 2019 that TEPCO formally announced the final decision to decommission the plant.181

Sources: Various, Compiled by WNISR, 2019

In the case of TEPCO’s last remaining nuclear plant at Kashiwazaki Kariwa in Niigata Prefecture, it is expected that a decision on the future and possible decommissioning of one or more of the seven reactors will be made in 2019. On 1 January 2017, Mayor Masahiro Sakurai of Kashiwazaki City announced that as a condition for allowing restart of Units 6 and 7, TEPCO must propose a decommissioning plan by 2019 for at least one reactor from Units 1–5 (with no upward limit on the number of these reactors to be permanently shuttered).182 The mayor suggested it is inevitable to scale down the plant: “Considering the Fukushima nuclear accident, seven reactors are too many.”183 The mayor extended his position dramatically when on 25 July 2017 he agreed to the restart of Kashiwazaki Kariwa Units 6 and 7 reactors but on the condition that TEPCO “presents a plan to decommission the remaining five in two years.”184 The demand was made in the mayor’s first meeting with TEPCO’s new president, Tomoaki Kobayakawa, where June 2019 was set as a date when TEPCO would provide a plan. In response, TEPCO’s President Kobayakawa said: “We should exchange opinions further.”185 In July 2018, President Kobayakawa noted that he was “aware that this is a problem in which some kind of reply is needed.”186 And without clarifying, according to Nikkei, he stated that “he understands that Sakurai is not asking to decommission every reactor or scrap them immediately.”187 In March 2019, TEPCO reported that they were still aiming for a June 2019 date to submit a report on decommissioning but were struggling with the “complexity”.188 In early June 2019, TEPCO informed Sakurai that they were aiming for a plan to be presented in “early July”.189 On 1 July 2019, however, the mayor cancelled his meeting with TEPCO following a miscommunication by TEPCO during the night of 17 June 2019 when a 6.7 magnitude earthquake occurred off the coast of Niigata.190 TEPCO staff faxed local government office, including Kashiwazaki, with incorrect information indicating that there were safety problems with the electric supply to the spent fuel pools at all seven of the Kashiwazaki Kariwa’s reactors. As of 1 July 2019, it remains unclear when TEPCO will present its plans to the mayor.

There has been no clear indication from TEPCO on the number of reactors that will be offered up for decommissioning. Analysis of the reactors, including from TEPCO, suggests at least two reactors and possibly up to four might be proposed. Leading candidates for closure are Kashiwazaki-2, -3 and -4 which have not operated since 2007 when they were shut down by the Niigata Chuetsu-oki earthquake.

Other reactors that remain highly vulnerable to closure include the two Shika BWR units owned by Hokuriku Electric. The utility and the Nuclear Regulatory Authority (NRA) are in dispute over the status of three seismic fault lines at the site, with the NRA concluding in 2015 and 2016 that these may be active under the reactor of Unit 1 and just below safety-related equipment of Unit 2, which would preclude operation.191 There are no immediate prospects of the utility giving up restart plans for Unit 2, which is an Advanced Boiling Water Reator (ABWR), and has been under NRA review since 2014. The reactor was only connected to the grid in 2005, and during the past 14 years has only operated for just over five years. Hokuriku officials have stated their intention to submit Shika-1 for NRA review,192 but there are no prospects for restart.193

The Japanese nuclear fleet’s mean age now stands at 28.4 years, with 12 units over 31 years (see Figure 29).

Restart Prospects

As stated, no reactors are planned to be restarted through the remainder of FY 2019. Thereafter, planned reactor restarts in 2020 and beyond remain uncertain. All currently operating reactors in Japan are Pressurized Water Reactors (PWRs)—the destroyed Fukushima Daiichi units were BWRs. As of 1 July 2019, not counting two reactors “under construction”, 16 reactors remain under NRA safety review (out of a total of 25 that have applied since July 2013); 24 reactors remain in Long-Term Outage (LTO). Not all will restart, with many questions and disagreements over seismic issues, and many plants far back in the review and screening queue. There are officially two reactors under construction (Shimane-3 and Ohma).

Reactors most advanced in the restart process, and therefore with a possible restart in the coming 12 to 24 months, include Kansai Electric’s (KEPCO) PWR Takahama-1 and -2, and PWR Mihama-3, which have passed NRA review for their respective upgrading plans. These three reactors, which are 45, 44 and 43 years old respectively, were granted lifetime operation approval to 60 years by the NRA in 2016.194 Restart schedules of these three reactors have all been revised. In delaying restart of Takahama-1 from September 2019, Kansai Electric announced a revised date of June 2020, both for completion of engineering work and a restart date.195 It is likely that this date will slip further. In the case of Takahama-2, restart has been pushed back from April 2020 to February 2021. As for Mihama-3, restart has been postponed from February to August 2020. Again, there is a high likelihood of further delay for restart of Mihama-3. The uncertainties are such that in 2020 there could be three additional reactors operating in Japan, or—possibly more likely—one or none.

The restart delays for Takahama-1 and -2, and Mihama-3 are due to longer planned timescales for multiple engineering retrofits to safety systems that are being applied. These include emergency water injection equipment, Primary Containment Vessel (PCV) overpressure damage prevention and measures to reduce risks from hydrogen explosion.196 Assuming that all three reactors will be operating by mid-2021, Kansai Electric would have in total seven reactors in operation, with an installed capacity of 6.25 GW.

The most advanced in the NRA restart review process is the Tohoku Electric’s BWR Onagawa-2, which applied for NRA review in December 2013.197 However, the utility postponed its restart schedule several times and could do so again. In 2015, Tokhoku Electric had stated that it would complete safety related work on the reactor by April 2017.198 In January 2017, the utility disclosed to the NRA that the reactor building had sustained 1,130 cracks in the walls and “lost an estimated 70 percent of structural rigidity” in the 3/11 earthquake.199 The disclosures led Tohoku to push back restart schedule from 2018 to 2019 and then beyond 2020. The disclosures to the NRA followed an architectural investigation which identified that structural rigidity, the ability to withstand earthquakes and other stresses from outside without being distorted, was concentrated in the upper third of the reactor building with the third floor only retaining 30 percent of its integrity compared with July 1995 when the reactor began operation. It also confirmed a 25 percent loss of structural integrity in the two above-ground floors and three basement levels.

Significantly, the disclosure contrasts starkly with the assessment and conclusions of a high-profile International Atomic Energy Agency (IAEA) mission to the plant in 2012.200 The IAEA mission included a “structures team” assigned to observe and collect information on the performance of the structural elements of buildings, with different design criteria. They reported that, as far as cracks in Unit 2 are concerned, they were “less than 0.3 mm, although at some locations there were cracks of approximately 0.8 mm. These minor cracks do not affect the overall integrity of the structure.” The IAEA concluded: “The lack of any serious damage to all classes of seismically designed facilities attests to the robustness of these facilities under severe seismic ground shaking”, and that “the structural elements of the NPS [Nuclear Power Station] were remarkably undamaged given the magnitude and duration of ground motion experienced during this great earthquake.”201

The Onagawa plant is located 125 km from the source of the 3/11 earthquake, the nuclear reactor site closest to the hypocenter (Fukushima Daiichi was 180 km from the hypocenter). As such, the lack of apparent damage to the plant since 2011 has been hailed by the IAEA and others as evidence of the robustness of nuclear power plants in general. The Onagawa-2 reactor was in its startup sequence and not critical on 11 March 2011, whereas Units 1 and 3 were in operation. As of 1 July 2019, the utility had not applied for NRA review of Unit 3 which began operation in May 2001. Tokoku Electric’s President stated in November 2018 that they were in preparation for submitting a safety review application to the NRA for the reactor, without specifying a date.202 There are suspicions that damage sustained at Unit 3 is more significant than reported. On 28 March 2019, the utility announced that total projected costs for retrofits at Onagawa-2 were ¥340 billion (US$3.1 billion).203

In polling conducted in 2018 in Miyagi Prefecture, 70 percent of the public are reported to be opposed to the restart of the Onagawa plant.204 In March 2019, the Miyagi assembly voted down legislation for a prefecture-wide referendum on whether Onagawa should restart.205 The draft legislation followed the submission of a petition with 111,743 signatures from prefectural residents. Tohoku Electric is aiming to complete its NRA safety review for Unit 2 in July 2019 and thereafter seek local approval for restart.206

Tohoku Electric’s other reactor, Higashidori-1 in Aomori Prefecture, remains under investigation seven years after the NRA concluded in December 2012 that two seismic fault lines are active.207 Tohoku initiated further seismic surveys in March 2019 carried out through September with the aim of convincing the NRA that the faults are not active.208 Under Japanese regulations, a reactor is not permitted to operate or be constructed if an active fault exists at a nuclear site. One of Japan’s leading seismologists, who resigned from the government panel that drafted the revised Japan’s seismic guidelines, has warned that “a strong earthquake of up to about 7.3 magnitude could directly hit an area where even perfect seismic research could not discover an active fault line”.209

The utility Chugoku Electric is moving forward with NRA approval for restart of its Shimane unit 2 BWR. In May 2019, the NRA summarized the status of review for the reactor, with seismic “design basis ground motion and design basis tsunami design policy substantially complete”.210 However, there remain substantial issues still under review, including overall seismic and tsunami design policy, safety assessment for hydrogen countermeasures and containment vessel cooling, pressure overload and water injection. In March 2019 Chugoku was not able to inform investors of a target date for restart.211 At the same time, on 10 August 2018 Chugoku submitted its application to the NRA for review of its Shimane-3 Advanced Boiling Water Reactor (ABWR).212 Construction began on Shimane-3 on 12 October 2007. According to the Japan Atomic Industrial Forum (JAIF), the reactor was 93.6 percent complete as of 30 April 2011, and following the Fukushima Daiichi accident, construction was suspended, and plans revised.213 There is no operational start date for Shimane-3, and barring successful legal challenges, it can be predicted that it will be several years before operation. It would be the first new reactor to begin operation since 3/11 and the first since Tomari-3 in March 2009.

The Case of TEPCO’s Kashiwazaki Kariwa

The status of TEPCO’s Advanced Boiling Water Reactor (ABWR) Kashiwazaki Kariwa-6 and -7 reactors in Niigata Prefecture has not changed significantly in the passt year. When TEPCO submitted its first post-3/11 business plan to the Japanese government in 2012, it predicted that restart of reactors at Kashiwazaki Kariwa would begin in FY2013. This was never credible. On 27 December 2017, Nuclear Regulatory Authority (NRA) approved the initial safety assessment for TEPCO’s Kashiwazaki Kariwa Units 6 and 7,214 the first BWRs to reach this stage of NRA’s review process.215 On 13 December 2018, TEPCO submitted to the NRA a schedule for completion of its engineering work program on Unit 7, by which it aims to complete safety retrofits by December 2020.216 In its third Special Business Plan in June 2017, it projected income from the reactors with three possible restart dates of 2019, 2020 and 2021.217 As of July 2019, the earliest the reactors could restart would be 2021, but only if TEPCO were to overcome significant obstacles.

The Kashiwazaki Kariwa site has a history of major seismic activity, with repeated underestimates and non-disclosures of the seismic risks by TEPCO and resultant coverups. At the time of the licensing of the ABWRs Units 6 and 7 in 1991 TEPCO presented evidence to the regulator that the nearby fault lines were not active. This was then proven to be incorrect, with TEPCO’s own data showing that they were aware of active faults as early as 1980. None of this was made public though until after the 2007 Niigata Chuetsu-oki quake.218

There are multiple seismic fault lines in the area of the Kashiwazaki Kariwa site, including through the site.219 There are large-scale submarine active faults offshore with four main ones, three of which run along either edge of the Sado Basin, a depression between Sado Island and mainland Kashiwazaki.220 Seismologists have long warned about the threat from major earthquakes leading to a severe nuclear accident at Kashiwazaki Kariwa.221 Independent seismologists and citizens’ groups continue to oppose restart of the reactors, including based on evidence that TEPCO has relied on flawed seismic assessments;222 meanwhile, legal challenges seeking permanent closure are ongoing.

The Niigata governor election of 10 June 2018 led to the appointment of Liberal Democratic Party (LDP)-backed candidate Hideyo Hanazumi.223 This does not automatically mean any early restart for TEPCOs Kashiwazaki-Kariwa reactors. The newly elected governor, conscious that 65 percent of the Niigata population remain opposed to restart of any reactors at the plant, stated, “as long as the people of Niigata remain unconvinced, (the reactors) won’t be restarted.”224

Niigata has a long history of opposition to the nuclear power plant, but this was exacerbated when in September 2002, following disclosures from a General Electric whistleblower, TEPCO was forced to admit that the organization had deliberately falsified data for inclusion in regulatory safety inspection reports of their reactors, a consequence of “systematic and inappropriate management of nuclear power inspections and repair work [over] a long time”.225 As a consequence, at the time, all 17 TEPCO reactors—the 7 at Kashiwazaki-Kariwa and the 10 at Fukushima—were shut down for extended periods, and TEPCO’s chairman, president, and executive vice-president all resigned. The major seismic risks at the plant were exposed by the 2007 Niigata Chuetsu-oki earthquake, which once again led to the extended shutdown of all Kashiwazaki Kariwa reactors, while Units 2, 3 and 4 have not operated since then. In February 2019, the NRA announced it was investigating TEPCO for ongoing safety violations, at Kashiwazaki-Kariwa, as well as at Fukushima.226

In the aftermath of the 2002 falsification disclosures, the then governor of Niigata established a Technical Committee of 15 experts to review nuclear safety in the prefecture. This committee is currently reviewing the Fukushima Daiichi accidents, including causes as well as ongoing assessments of the safety of the Kashiwazaki Kariwa plant. This includes meetings with NRA, where the regulator has been regularly challenged on its safety approval of the reactors.227 A second committee, established in August 2017 by then Governor Ryuichi Yoneyama, is reviewing the health impacts of the Fukushima Daiichi accident and a third committee, also established under Yoneyama, is reviewing emergency planning in Niigata in the event of a severe accident at the Kashiwazaki Kariwa plant.228 The work of the Committees was linked to the then Governor’s decision on the restart of Units 6 and 7 and are expected to conclude their investigations in mid-2020. The committees’ work is ongoing, and the new Governor has stated since his election that he will await the conclusion of their investigations prior to any decision.229

The Case of JAPC’s Tokai-2 and the “Ibaraki Method”

On 22 February 2019, Japan Atomic Power Company (JAPC) announced its intention to proceed with the restart of its 1100-MW BWR Tokai-2 reactor.230 The target date is January 2023. This followed a 7 November 2018 unanimous decision by Nuclear Regulatory Authority (NRA) commissioners to approve an additional 20 years of operation.231 On 26 September 2018, the NRA had approved the safety review of the reactor.232 It was the first BWR to pass all safety stages of the NRA review process and receive a 20-year lifetime extension. The reactor, which was connected to the grid in March 1978, has not operated since 3/11 when it underwent an emergency shutdown resulting from being affected by the magnitude 9.0 earthquake and tsunami. It is located in Ibaraki Prefecture, 70 km from Tokyo and is the closest commercial nuclear reactor to the capital. JAPC was formed in 1957 as the only power company based solely on nuclear reactor operation. The company is jointly owned by Japan’s nuclear energy utilities with TEPCO, Kansai Electric, Chubu and Hokuriku being its largest shareholders. The Tokai-2 reactor is the only reactor JAPC is advancing towards restart, given the active fault line at its other site, Tsuruga in Fukui.

There remain major challenges to the eventual restart of Tokai-2. These include the securing of financing for retrofits. JAPC originally estimated costs of ¥174 billion (US$1.54 billion) in retrofits and that the reactor would pass NRA’s pre-operational inspections by March 2021.233 By March 2019, this was revised to ¥300 billion (US$2.73 billion).234

Yet the company is in dire financial straits due to loss of revenue from electricity sales following reactor shutdowns, investment in plans for the constructions Tsuruga-3 and -4 (which were abandoned) and decommissioning costs related to Tsuruga-1 and Tokai-1.235 The NRA in November 2017, in approving the basic safety plan for Tokai-2, requested an “exceptional disclosure”, whereby JAPCO had to specify the guarantor of the loan it would be taking out in order to make the necessary safety upgrades. As shareholders of JAPC, TEPCO has agreed in principle to offer ¥190 billion (US$1.75 billion) in up-front bank loans, with Tohoku Electric, Chubu Electric Power Co., Kansai Electric Power Co. and Hokuriku Electric Power Co. also offering financial support. As of February 2019, the financing agreement had not been implemented and JAPC had insufficient funds to begin engineering retrofits.236

Local opposition in Ibaraki Prefecture to operations of Tokai-2 has grown since 3/11. The emergency shutdown due to loss of offsite power during the quake, the loss of all but one emergency generator, and a near miss in terms of tsunami flooding, threatening a meltdown of a reactor with over 960,000 people within a 30 km radius, have all contributed to significant political opposition to any restart proposal. Six municipalities near the Tokai-2 plant have argued that JAPC should gain their consent before restart. On 29 March 2018, after six years of negotiations, a unique safety agreement was reached between JAPC and the six municipalities which lie within 30 km of the plant. According to documents obtained by The Asahi Shimbun, the agreement stipulates that “when JAPC seeks to restart the Tokai No. 2 nuclear plant or extend its operation, it will effectively obtain prior approval from Tokai village and five surrounding municipalities.”237

Despite assurances from JAPC to the municipalities that the company was granting consent rights to them on restart issued prior to NRA approval, once approval was granted in autumn 2018, JAPC started to backtrack. JAPC Vice President Nobutaka Wachi stated: “The word ‘veto power’ can’t be found anywhere in the new agreement.”238 The company’s understanding of the agreement, in contrast to what the municipalities believe, is that it “is a plan to effectively obtain prior consent from the six municipalities (by continuing to talk thoroughly with them until they grant their consent).”239 Relations between JAPC and the municipalities have for obvious reasons deteriorated, and it remains unclear how or whether it will be resolved in the coming few years. A critical issue remains the ability of authorities to establish credible evacuation plans for nearly one million people within 30 km, the highest population density for any nuclear plant in Japan. Reacting to the announcement of JAPC on restart plans, Mayor Takahashi of Mito city (one of the six municipalities) warned that restart is impossible until realistic evacuation plans are made and the citizens’ understanding of them is gained.240 Citizen-led legal challenges to restart are ongoing.

A more immediate effect of the Ibaraki agreement is that the municipalities have signaled they expect JAPC to provide detailed plans for the engineering retrofits prior to the start of any work, with any delay of submission to municipalities likely to delay engineering work, potentially postponing restart, according to an official from Naka city, one of the municipalities within the 30 km area.241

The so-called “Ibaraki method”, so far unique to Ibaraki, has been exported to other communities around Japan making the case that utilities should have the same conditions in their safety agreement with municipalities. For obvious reasons, power companies are not rushing to adopt the Ibaraki method.

Other reactors within the NRA review process continue to have multiple challenges. For example, Hokkaido Electric Power Company, the owner of the PWR Tomari nuclear plant, continues to be in dispute with the NRA over the status of a seismic fault line at the site. The utility claims that the fault has not been active for 400,000 years, whereas the NRA takes the position that there is no evidence that the fault was “not active within the past 120,000 years”,242 the latter is the time period which, if confirmed, would preclude restart of the reactor. The utility has committed to submitting more evidence of their case by autumn of 2019. While all three reactors at Tomari have been under NRA review, Unit 3 is the most advanced, but has suffered multiple delays in restart plans.

The risks from major seismic events was demonstrated when on 6 September 2018 a magnitude 6.7 earthquake struck the island of Hokkaido.243 Thermal power plants shut down across the island, and the Tomari nuclear plant, including spent fuel pools, were reliant upon on-site emergency generators for a period of 10 hours.

Financing Meltdowns

In April 2019, two analysts, Eri Kanamori and Tomas Kåberger, published an assessment of the complex system of financing of the Fukushima Daiichi nuclear disaster related to the prospects for Tokyo Electric Power Company (TEPCO), and wider nuclear utilities in Japan.244 They explain that immediate payments have been made possible by direct transfers from the Japanese government, and these improvised solutions have for seven years both kept the government’s borrowing capacity intact and allowed TEPCO to avoid going bankrupt. But as the analysts explain, these payments “are not acknowledged as government spending. Instead, a complicated system of envisioned re-payments have been created.”245 As with other analysis, they predict that TEPCO’s Special Business Plan will be impossible to fulfill, and that further improvised and complicated solutions may follow. Their conclusion is that the system in place in Japan shows a lack of readiness and an absence of any plan on how to manage the economic consequences of an accident of the magnitude of 3/11, and that the repayment schemes in Japan are not compatible with a future efficient and competitive electricity market.

Multiple Reactor Shutdowns from Spring 2020?

As mentioned above, a decision by the NRA over completion of emergency engineering measures at nuclear plants on 24 April 2019 has raised the prospect of multiple reactor shutdowns starting in March 2020.246 Under post-Fukushima regulatory guidelines, nuclear plant operators are required to have completed work programs that include building a bunkered second control center comprising an emergency control room, an electricity generator, a water storage tank and multiple pumps to feed cooling water to the containment vessels. These facilities are required to protect against damage in the event of deliberate or accidental aircraft impact, malicious attack, or fire or explosions in the reactor containment. Originally set to be implemented by 2018 (five years after the adoption of the revised Guidelines), in 2015 the NRA extended the compliance period to within five years of approval of reactor Construction Plans. By voting unanimously for maintaining the deadline, and by rejecting the pleading of utilities,247 the NRA commissioners have apparently set the clock towards multiple reactor shutdowns beginning in spring 2020.

According to Kyushu Electric, Kansai Electric Power and Shikoku Electric Power, ten of their reactors will miss their deadlines. First to close, if the NRA decision remains in place, would be Sendai-1 on 18 March 2020, followed by Sendai-2 on 22 May 2020; Takahama-3 and -4 must meet the deadline of 4 August and 9 October 2020 respectively or shut down. These would be followed by Ikata-3 on 23 March 2021 and Mihama-3 on 26 October 2021; the latter, which remains in Long-Term Outage (LTO), is not scheduled to restart operations until August 2020. Genkai-3 and -4 have until 2022 to complete work; likewise for Takahama-1 and -2, both of which remain in LTO and not due to restart until 2020 and 2021 respectively. Described as a near total shutdown of Japan’s reactor fleet, the NRA decision contributed to a 19-percent plunge of the three utilities’ share value as of April 2019.248 All utilities have reported that they are behind schedule in the construction of their “contingency” facilities.249 It remains to be seen if the NRA commissioners relent under pressure from the utilities.

All of these factors contribute to the wholly uncertain prospects for nuclear power in Japan over the next few years.

South Korea Focus

  • Under Construction 4
  • Operating 23
  • Long-Term Outage 1
  • Closed 2
Number of Reactors
Mean Age of Reactor Fleet
Annual Load Factor

On the Korean Peninsula, South Korea (Republic of Korea) operates 23 reactors, with one new reactor startup and one permanent closure decision over the past year, and one reactor entering Long-Term Outage or LTO status. Shin-Kori-4 was connected to the grid on 22 April 2019, five years later than planned. In June 2018, the commercial operation of Wolsong-1 was “terminated”, long before a 2022 deadline.250 As the reactor had not generated power since May 2017, WNISR considers it closed as of that date.

South Korea’s nuclear fleet, owned by Korea Hydro & Nuclear Power Company (KHNP), is located at the Hanbit, Hanul, Kori and Wolsong sites. Nuclear power provided 127 TWh in 2018, a drop of 10 percent compared to 2017, and 19 percent below the maximum production in 2015. Nuclear power supplied 23.7 percent of the nation’s electricity in 2018, less than half of the maximum of 53.3 percent in 1987. The capacity factor for KHNP reactors was 63.8 percent; the decline in nuclear generation was mainly due to reduced availability as a result of extended reactor outages.

In April 2018, 11 reactors in Korea were shut down for maintenance and inspection;251 and on 1 July 2018, eight reactors remained shut down,252 while six remained offline on 18 December 2018.253 Hanbit-4 has been shut down in May 2017, and as it had not restarted by mid-2019, it meets the LTO criteria. One of the issues that has led to delays in restarts of reactors has been the discovery of reactor Containment Liner Plate (CLP) corrosion (see hereunder).254 As a consequence, KHNP reactor maintenance outages increased 75 percent, from 1,373 days in 2016 to 2,397 days in 2017.255

In December 2017, the government approved the 8th Basic Plan for long-term Electricity supply and demand (BPE), which marks a major shift in overall energy policy, while confirming the gradual nuclear phase-out road map announced in October 2017.256 In the period to 2030, four new reactors will begin operation, while ten reactors would be taken offline as eight reach their 40-year lifetime and two their 30-year limit (different reactor technologies). Nuclear power capacity would peak in 2022, before declining towards phase-out. Thus, under current policy, nuclear power will remain a significant source of electricity generation in South Korea well into mid-century.

The new BPE stipulates close to 12 percent nuclear in the power generating capacity as of 2030, then producing almost 24 percent of the country’s electricity. The new BPE projects an increase of installed renewables capacity (excluding large hydro and mainly solar photovoltaics and wind) from 11.3 GW in 2017 to 58.5 GW in 2030, leading to a 20 percent market share of national generation capacity—a major policy shift. Over more than three decades the energy policy of successive South Korean governments had been premised on the continued expansion of nuclear power, including for example a target of 41 percent by 2030 (2008 first National Energy Basic Plan for 2008–2030) and Korea Electric Power Corporation’s (KEPCO) 2011 proposed 43 GW of nuclear capacity for 2035.

Table 6 | Schedule Closure Dates for Nuclear Power Reactors in Korea 2023–2029















1 011










1 012







































































1 416




1 340










Sources: MOTIE, 2017

Following the closure of Wolsong-1, the seven reactors that are now planned to be closed just prior to reaching their 40-year operating lifetime total 6.6 GW of capacity and are Kori-2 in 2023, Kori-3 in 2024, Kori-4 and Hanbit-1 in 2025, and Hanbit-2 in 2026, Hanul-1 in 2027 and Hanul-2 in 2028. Three reactors are scheduled to be closed as they reach their 30-year lifetime: Wolsong-2 in 2026, Wolsong-3 in 2027 and Wolsong-4 in 2029 (see Table 6).257

The government had indicated that it would compensate KHNP for the closure of Wolsong-1, citing the company’s own data for a total of 244.1 billion won (US$230 million), whereas opposition lawmakers had cited figures as high as 995 billion won (US$920 million). However, KHNP’s own figures show that compensation may not be justified given the reactor’s poor performance. When announcing its closure in June 2018, KHNP stated that its decision was based on the “uncertain economic viability” of its continued operation and recent low operating performance. The reactor’s generating unit costs stood at 120 won (US$0.109) per kWh as of late 2017 or double the current market price of 60 won (US$0.054) per kWh. President Chung Jae-Hoon of KHNP reported that “After the 2016 earthquakes in Gyeongju, Wolsong 1’s operation rate dropped below 50 percent, and it remains suspended now [because of maintenance].(…) Wolsong 1 is already running in the red.”258

The troubled Wolsong-1 was already shut down in 2012 as its operating license expired. In 2015, the Nuclear Safety and Security Commission (NSSC), against strong local opposition, approved a ten-year extension allowing it to restart and operate until 2022.259 It generated power for only half of the granted lifetime extension before it was taken off the grid in 2017 and has remained closed ever since.

Reactor Startup

Shin-Kori-4, located at Gori in the southeast of the Republic of Korea, was connected to the grid on 22 April 2019.260 The KHNP-owned reactor is the second APR-1400 (Advanced Pressurized Reactor) to begin operation and the nation’s 26th commercial nuclear reactor. As noted, startup occurred five years later than the initial startup planned for 2014. The Nuclear Safety and Security Commission (NSSC) had granted an operational permit on 1 February 2019.261 Factors that contributed to the delays included the 5.8 magnitude Gyeongju earthquake in September 2016262—the most powerful quake to have hit the Korean peninsula since recording began in 1978— and the 5.4 magnitude Pohang quake in November 2017263, both of which occurred in the southeast of the peninsula, where the majority of the nation’s reactors are located, including the Shin-Kori site. Other causes for delay included a far-reaching scandal over falsifications of quality certificates for reactor components, as reported in WNISR2017, details of which continued to emerge in 2019;264 and policy changes after the election of President Moon Jae-In in 2017.265

In May 2015, the NSSC confirmed that there had been quality-control falsification issues within the Korean nuclear industry that lasted for a decade. Shin-Kori-3 as well as Unit 4 were found to have had falsified quality-control documents requiring the replacement of plant cabling (see WNISR17 and WNISR18). The operational license for Shin-Kori-3 was only granted by the NSSC on 29 October 2015 and the reactor was connected to the grid on 15 January 2016.266

Corruption and safety violations in the Korean nuclear program have continued to emerge in recent years, with one nuclear industry whistleblower in April 2019 stating that, “On principle, I don’t trust anything that KHNP built.”267

The NSSC in April 2019 passed a bill that ordered the KHNP to construct on-site emergency response facilities for all nuclear reactors.268 The NSSC decision was part of the post-3/11 measures to be applied in Korea. The additional base is to be secured inside the nuclear power plant site, other than the existing emergency response facility, which is currently off site, so that emergency personnel perform accident response and post-accident management. It is unknown at this stage whether or not this measure will have the same implications as the recent decision by Japan’s Nuclear Regulatory Authority (NRA) that set a five-year timeframe for completion of such facilities. Utilities in Japan are set to miss the deadline and on current trajectory will be forced to close reactors starting in March 2020.

New Reactor Construction

Four additional APR-1400 reactors remain under construction. At Shin-Kori work resumed on Unit 5 in October 2017 and construction officially started on 6 September 2018 on Unit 6 with startup scheduled for June 2024. As this would be the last nuclear plant to start up with a nominal operational lifetime of 60 years, nuclear power capacity would peak in 2022, before declining towards an “organic” phase-out expected to occur in the middle of 2080s. Construction of twin APR-1400 units, Shin-Hanul-1 and Shin-Hanul-2, continues, after starting in July 2012 and June 2013, while missing their original completion dates of 2017 and 2018.269 The latest dates provided by KHNP are November 2019 and September 2020 for commercial operation; but according to those estimates, fuel loading for Shin-Hanul-1 should have taken place in June 2019, which it did not.270

The government 2017 Basic Plan for long-term Electricity supply and demand (BPE) energy plan confirmed cancellation of six new reactor projects (all APR-1400 design): Shin-Hanul-3 and -4, Cheonji-1 and -2 (in Yeongdeok) and either Cheonji-3 and -4 or Daejin-1 and -2 (in Samcheok). The cancellation of these projects comes after successive governments had failed to secure new sites for plants, due to local opposition, including at Samcheok and Yeongdeok.271

Energy Policy Under Attack

The past year has seen an escalation of the campaign against President Moon’s energy policy by the nuclear industry and its supporters in the former government Liberty Korea Party (LKP) as well as the largely conservative print media.272 As a consequence, President Moon’s energy policy has become more contested. One reason for this is the relentless media coverage that has falsely conflated in the public’s mind Moon’s energy policy as being responsible for the severe air pollution experienced in Seoul during the past year. In March 2019 the National Assembly passed a bill on the designation of fine dust as a social disaster as Seoul and other parts of Korea face serious particle pollution.273 The reason for air pollution levels reaching such proportions is due in large part to micro-dust and yellow dust blown in from China.274 The contribution from Korea’s coal-fired plants is also a major factor. However, it was the previous conservative government that expanded coal plant use by 50 percent in the ten years prior to 2017.275

In January 2019, the LKP and the nuclear industry collected more than 300,000 signatures to oppose the long-term nuclear phase-out policies, calling for a restart of construction of the two Shin-Hanul nuclear power plants in Uljin County, North Gyeongsang Province.276 The LKP and Bareun Party aim to ultimately stop the long-term nuclear phase-out. However, the Ministry of Trade, Industry and Energy restated in February 2019 that “There is no change in the government policy to reduce the country’s heavy reliance on nuclear in power generation... The 2017 state [organized citizens’] panel recommended to scale back nuclear power generation, so the government will not revive Shin Hanul-3 and -4.”277

Despite the push back from industry and media, the government restated its commitment to its energy transition in April and June 2019. Expansion of its renewable energy target to 30–35 percent by 2040 was confirmed by the government on 19 April 2019.278 Confirming its energy transition, including electricity demand reduction by 18 percent by 2040, Joo Young-joon, Deputy Minister for Energy and Resources stated that, “South Korea will build a highly efficient and clean, but stable energy structure. […] The transition itself will create new opportunities, ranging from nuclear decommissioning to hydrogen fuel cells. The change will eventually provide the country with sustainable growth.”279

Containment Liner Plate Corrosion

As noted above, the past few years have witnessed extended outages of South Korea’s nuclear reactors. The principle reason for this has been that out of the 24 reactors South Korea operated (prior to startup of Shin-Kori-4 in 2019) 20 were found to have corrosion in the Containment Liner Plates (CLP) and/or voids in the concrete structure.280 A total of 13 units have been found to have both CLP corrosion and voids in their concrete, while seven have only void issues.

Nuclear reactor containment-buildings in Korea are insulated with a CLP of six millimeters in diameter, and then concrete 1.2 meters in diameter thick. As the U.S. Nuclear Regulatory Commission noted in 1997, “Any corrosion (metal thinning) of the liner plate could change the failure threshold of the liner plate under a challenging environmental or accident condition. Thinning changes the geometry of the liner plate, creating different transitions and strain concentration conditions. This may reduce the design margin of safety against postulated accident and environmental loads.”281

Under nuclear regulation evidence of structural deterioration that could affect the structural integrity or leak-tightness of metal and concrete containments must be corrected before the containment can be returned to service. Corrosion of a liner plate can occur at a number of places where the metal is exposed to moisture, or where moisture can condense (behind insulation) or accumulate. Corrosion damage of CLPs historically has primarily been either the result of embedded foreign material (e.g. wood) in contact with the liner resulting in corrosion or inside initiated corrosion resulting from coating failures or moisture barrier degradation. The corrosion repair has consisted of removal of the damaged liner section and embedded foreign material, grouting the resulting void, and replacing the liner plate section.282

In June of 2016, the corrosion on the liner plate of Hanbit-2 was discovered during in-service inspection. The Nuclear Safety and Safety Commission (NSSC) ordered the licensee to perform the extensive examination for liner plates of all operating Pressurized Water Reactors (PWRs). The Korea Institute of Nuclear Safety (KINS) reported that the discovery of the liner plate corrosion was confirmation of the limitations of in-service inspection.283 One example reported by the NSSC in the past year was Hanbit-1, where thickness of the CLP was found to be thinner than the standard.284

Root cause analysis of the causes of CLP corrosion reported by Korea Institute of Nuclear Safety were predominately due to exposure to moisture (environment), as well as the presence of foreign debris.285 It is unclear when the recommendations of lessons learned from the CLP issue, including and specifically, over-reliance on visual inspection rather than more extensive limited ultrasonic testing, will be applied by the NSSC. The NSSC confirmed repairs where required at Hanbit-1 and approved re-criticality of the reactor on 9 May 2019.

On 7 July 2019, Korean broadcaster MBC reported that KHNP had confirmed that 94 holes had been found between the steel plate and concrete inside the reactor building of Hanbit-3 and 96 holes in Hanbit-4. KHNP, according to MBC, explained that the holes found are up to 90 cm in size, but there would be “no problem with the structural stability of the containment.” Hanbit-3 and -4 remain shut down.286 As of 19 July 2019, the NSSC had yet to confirm these reports.

As reported, the extended shutdown of multiple reactors in Korea over the past few years has been used by those opposed to President Moon’s energy policy to criticize the NSSC for prolonging inspections. In 2018, the availability factor for reactors in Korea declined further to an average of 65.9 percent in 2018, compared with 71.2 percent in 2017, 79.7 percent in 2016 and 85 percent in 2015.287 In 2018, the NSSC responded robustly to criticism of delayed regulatory approval, noting: “When an urgent regulatory issue is found, such as the recent case of corrosion in the Containment Liner Plate, the NSSC inspects all reactor units to find out the cause of the same case and to ensure safety.”288 In May 2018, NSSC stated that in terms of reduced nuclear output over the past year, “the operation rate fell to 71% last year and 58% last January because KHNP’s facility maintenance has been prolonged due to the problems caused by their poor safety management practice [that] have been simultaneously found at all nuclear power plants.”289

Hanbit Power Surges

Safety concerns with KHNP nuclear operations were triggered after it was disclosed on 10 May 2019 that Hanbit-1 had been manually shut down following an instantaneous increase in thermal power.290 The reactor had been in maintenance outage since 2018 but authorized to return to service. The NSSC reported thermal power had exceeded the 5 percent limit set in the reactor license Technical Specifications, reaching 18 percent.291 This caused the temperature of the reactor coolant to rise rapidly, along with the steam generator level. The rising level of the steam generator tripped the main feed water pump, activating the auxiliary water pump. The NSSC reported that KHNP did not immediately shut down the reactor even though the thermal output of the reactor exceeded the limit during a test. In addition, the control rods were operated by a person who does not hold a Reactor Operator’s license (RO). The reactor was eventually shut down 12 hours after the initial event.292

The NSSC, in announcing expansion of their investigation on 20 May 2019, reported that negligence on the part of the Senior Reactor Operator (SRO) in supervising and directing the operation is suspected, and therefore there is a possibility of violation of the Nuclear Safety Act.293 Under the Act, KHNP is required to immediately shut down the reactor when thermal power exceeds the limit. For the first time, the NSSC ordered special judiciary police to investigate KHNP’s actions. The regulator ordered the suspension of operation of Hanbit-1 at least until 20 July 2019, with the NSSC stating that “Since the thermal output rose so suddenly, we’ll also have to check the integrity of the nuclear fuel. After thoroughly ensuring that the nuclear rods and nuclear fuel are both safe, we’ll take action related to nuclear power legislation.”294 On 24 June 2019, the NSSC released its interim report finding that: the dynamic control rod reactivity measurement (DCRM), which has been used for 14 years, failed, and was replaced with other test methods; that excessive withdrawal of control rods had occurred; that control rods that became stuck was a result of latch jam (malfunctioning latch), accumulation of crud, influx of foreign materials, misalignment caused by aging and other causes; and that the operator had miscalculated reactivity and therefore the reactor went from sub-critical to super-critical. The NSSC reported that the specific reactor operator responsible for calculating reactivity did not have experience related to reactor startup operations.295

Taiwan Focus

  • Abandoned Constructions 2
  • Operating 4
  • Long-Term Outage 1
  • Closed 1
Number of Reactors
Mean Age of Reactor Fleet
Annual Load Factor

Taiwan has four operating reactor units at Kuosheng (Guosheng) and Maanshan, all owned by Taipower, the state-owned utility monopoly.296 Since WNISR2018, the two reactors at Chinshan (also spelled Jinshan) were announced for closure. In December 2018, it was made official that Chinshan-1 would not restart. WNISR considers it closed as of December 2014, when it was shut down for refueling and never put back on-line.

At the same time nuclear generation increased in 2018 with the restart of two reactors after long outages. In 2018, there was 26.6 TWh of nuclear generation, compared with 21.6 TWh in 2017, but still less than 30.5 TWh in 2016. Nuclear generation provided 11.4 percent of the country’s electricity in 2018, compared with 9.3 percent in 2017 and its maximum share of 41 percent in 1988.

The government of President Tsai Ing-wen of the Democratic Progressive Party (DPP), which was elected in May 2016, remains committed to a nuclear phase-out by 2025, while transitioning the energy economy to renewables.297 Historical public opposition to nuclear power in Taiwan dramatically escalated during and in the months following the start of the Fukushima Daiichi accident and 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 of President Tsai in summer 2016, aims at establishing “a lowcarbon, sustainable, stable, high-quality and economically efficient energy system” through an energy transition and energy industry reform.298 On 12 January 2017, the Electricity Act Amendment completed and passed its third reading in the legislature, setting in place the mechanisms for Taiwan’s energy transition, including nuclear phase-out.299 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 monopoly of the state-run Taipower will also be terminated.300

The plans for ending nuclear power progressed significantly during the past year with the approval of Taipower’s decommissioning plan for the two units at Chinshan and preparations for submission of the decommissioning plan for the two units at Kuosheng, which are due to close in December 2021 and December 2023 respectively.

To reach its renewable energy goals of 20 percent of the nation’s generation by 2025, approximately 27 GW of new offshore wind and solar capacity will be required.301 In the past year, the Ministry of Economic Affairs (MOEA) awarded grid capacity to nine developers for 14 offshore wind projects, with 738 MW operating capacity by 2020 and 4,762 MW between 2021 and 2025.302 The attractive feed-in tariffs offered for offshore have attracted overseas companies,303 with Mitsubishi Heavy Industries Ltd. (MHI)-Vesta signing contracts for localized production of wind turbine towers and blades with the objective of supplying both Taiwan and the wider Asia region.304 In the case of solar PV, the target is for 20 GW by 2025, and with 2.24 GW installed as of September 2018,305 there will need to be a rapid scaling up if Taiwan is to meet its target.

Reactor Closures

On 5 December 2018, Taipower announced the closure of Chinshan-1, four years after being taken off-line.306 It had not operated since 10 December 2014. The Atomic Energy Council (AEC) had approved the reactor for restart, but lawmakers required the issue to be addressed by the national parliament prior to restart.307 Both reactors at Chinshan are Mark 1 BWRs, which began operation in 1977 and 1978 respectively. In May 2016, environmental groups launched a court case against the restart of Chinshan-1 calling it the “most dangerous reactor in the world”.308 Taipower’s decommissioning plan for both units at Chinshan had been approved by the AEC in June 2017.309

Chinshan-1 is the first commercial reactor in Taiwan to be closed for decommissioning. Chinshan-2 has remained shut down since June 2017—thus considered in Long-Term Outage (LTO) as of 1 July 2019—was officially closed on 15 July 2019, when its 40-year operating license expired. On 16 July 2019, the AEC issued the Decommissioning Permit for the Chinshan nuclear plant in accordance with the “Nuclear Reactor Facilities Regulation Act”.310 (See Table 7 for details).


An effort by pro-nuclear activists to overturn the government’s nuclear phase-out plans through a referendum has failed to change the reality that Taiwan is exiting nuclear energy. The referendum was held in November 2018, sponsored by those closely tied to the opposition Chinese Nationalist Party (Kuomintang or KMT). So-called “Referendum No. 16”, asked: “Do you agree that subparagraph 1, Article 95 of the Electricity Act, which reads: ‘Nuclear-energy-based power-generating facilities shall wholly stop running by 2025,’ should be abolished?” The referendum passed with 5.89 million “yes” votes and 4.01 million “no” votes.

However, according to Atomic Energy Council regulations, a proposal to update a nuclear power generator’s operating permit must be filed five to 15 years before the permit expires, according to AEC Deputy Minister Chiou Syh-tsong.311 The deadlines for extending operations at the Chinshan and Kuosheng nuclear power plants had already passed by the time of the referendum. The licenses for Guosheng’s two reactors expire on 27 December 2021, and 14 March 2023. Operations at the Jinshan plant’s two reactors have been suspended and, while decommissioning plans are going through an environmental impact assessment, they would remain suspended until they can be officially decommissioned, according to the AEC.312 The only licenses that could in theory be extended are for the two reactors at Maanshan as they expire on 26 July 2024 and 17 May 2025. There is no indication, though, that a license extension is to be applied for Maanshan-1, which would be due no later than 26 July 2019.

At a Chernobyl commemorative rally in Taipei in April 2019, President Tsai Ing-wen said that as long as she and her administration remain in power, she will stick to her goal of a “nuclear-free homeland.”313 Taiwan is at no risk of an electricity shortage, so its fourth nuclear power plant will not be put into operation, she said, referring to the Lungmen plant that had been under construction for 15 years (see No Future for Lungmen? for details). Critical to the orientation of energy policy in Taiwan will be whether or not Tsai Ing-wen secures re-election as President on 11 January 2020.

On 7 May 2019, as formally required following the referendum, but with no impact on plans for Taiwan’s nuclear phase-out, the Legislative Yuan abolished a provision in Article 95 of the Electricity Act stipulating that all nuclear energy generation facilities must stop operations before 2025.314

No Future for Lungmen?

On 1 February 2019, Taipower, the operator of the nation’s nuclear plants, effectively ruled out any prospects for the operation of the two Lungmen reactors, but without making a formal decision to do so.315 The two General Electric (GE) 1300 MW Advanced Boiling Water Reactors (ABWR) had been listed as “under construction” at Lungmen, near Taipei, since 1998 and 1999 respectively. According to the AEC, as of the end of March 2014, Lungmen1 was 97.7 percent complete,316 while Unit 2 was 91 percent complete. The plant was, as of 2014, estimated to have cost US$9–9.9 billion so far.317 After multiple delays, rising costs, and large-scale public and political opposition, including through local referendums, on 28 April 2014, the 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 to stop. The Democratic Progressive Party (DPP) government was elected with a pledge to halt construction of the Lungmen reactors, and with a nuclear phase-out planned for 2025, there is little prospect that they will ever operate. A formal decision on terminating the project would potentially force Taipower to file for bankruptcy as the listing of Lungmen as an investment asset would put the company in the red.318 Taipower’s February 2019 announcement of the time period required to complete Lungmen is not a formal decision to abandon Lungmen. With the official freeze of construction, WNISR took the units off the listing in 2014, where they remain as of 1 July 2019. The International Atomic Energy Agency (IAEA) continues to list the reactors as under construction.319

Any resumption of Lungmen construction would require Taiwan’s legislature and AEC approval, which, given the current government, is not going to happen. Taipower explained in February 2019 that it would not be able to replace major components installed nearly 20 years ago, including instrumentation and control as well as renegotiation with the main supplier General Electric (GE).320 Taipower stated that it could take 6–7 years to complete construction if all of these obstacles were overcome.

The announcement from Taipower was made one day after the Ministry of Economic Affairs published its revised national energy policy, according to which the Chinshan nuclear plant would be decommissioned as planned, there would be no extension for the Kuosheng and Maanshan reactors and the Lungmen plant would not be operated.321

Table 7 | Scheduled Closure Dates for Nuclear Reactors in Taiwan 2018–2025



Capacity MW

Grid Connection

Date of Cessation of Operation





05/12/ 2018a










27/12/ 2021





14/03/ 2023





26/07/ 2024





17/05/ 2025

Sources: Taipower, 2017, WNISR, 2019


a – Official closure date for Chinshan-1

On 30 May 2019, Taipower announced that it had agreed to settle a dispute out of court with GE over payment for components for the Lungmen project.322 Taipower agreed to pay GE, which designed the plant’s reactors, US$22.50 million as part of the out-of-court settlement. GE had filed two arbitration cases against the company at the International Chamber of Commerce (ICC) in September 2015. In January 2019, the ICC ruled that Taipower should pay GE NT$4.88 billion (US$158 million) under the terms of the contract.323 In the second case, yet to be ruled on, GE was seeking more than NT$2 billion (US$66 million) from the state utility firm for equipment already installed at the plant.

The only, and currently remote, prospects for Lungmen being completed and operated would be an election victory for the KMT party in the 2020 presidential elections.

United Kingdom Focus

  • Under Construction 1
  • Operating 15
  • Closed 30
Number of Reactors
Mean Age of Reactor Fleet
Annual Load Factor

In 2018, the United Kingdom operated 15 reactors, which provided 59.1 TWh (a 7.5 percent fall from 63.9 TWh in 2017, due to extended outages) or 17.7 percent of the country’s electricity, down from a maximum of 26.9 percent in 1997. The U.K.’s reactor fleet achieved an average load factor of 68.4 percent in 2018, a significant drop of 6.3 percentage points over 2017, but still better than the lifetime average of 63.2 percent. The average age of the U.K. fleet stands at 35.4 years (see Figure 31).

2018 was a remarkable year for the nuclear industry in the U.K., and historically it may well be seen as a pivotal year in the decline of the sector. Some of the key developments were: the extent of the age related cracking of the two Advanced Gas-cooled Reactors (AGR) at Hunterston, leading to their extended closure and potentially their retirement; the abandonment of both the Horizon and the NuGen new build programs; and the start of the closure of the Thermal Oxide Reprocessing Plant (THORP) at Sellafield.

A total of 30 power reactors have been permanently closed, all 26 Magnox reactors, both fast reactors, a prototype Advanced Gas-cooled Reactor (AGR) at Windscale and a prototype Steam Generating Heavy Water Reactor (SGHWR) at Winfrith. The U.K.’s seven second-generation nuclear stations, each with two AGRs, are all operating past the end of their original 25 year design lives. However, their owner EDF Energy, is planning to further extend the lifetimes of the two oldest AGR stations until 2023 (Hinkley Point B, Hunterson B). The other five stations (Dungeness B, Hartlepool, Heysham-1, Heysham-2 and Torness) are all due to complete their mandatory 10-year Periodic Safety Reviews in 2019 or 2020 and it will then become clearer how long EDF will be able to operate these plants. The country’s only Pressurized Water Reactor (PWR), at Sizewell B, is expected to operate until at least 2035.324

EDF Energy is owned largely by EDF, although Centrica has a minority share (20 percent) in EDF Energy’s U.K. nuclear subsidiary, Lake Acquisitions. However, Centrica has been trying to sell its stake since 2013 and is increasingly vocal in its desire to leave the nuclear business. In February 2018, CEO Iain Conn said that “we would hope to divest of our shareholding in U.K. nuclear power by the end of 2020”.325 In its 2018 annual report, Centrica stated that it would give an update of the “prospects for a trade sale of our Nuclear investment” in the Interim Results, to be published in July 2019.326 It has been reported that the Chinese firm CGN is interested in the deal. Uncertainty over the operational life of the AGR fleet is likely to impact on the timing, attractiveness and price of the proposed sale. EDF has also been trying to reduce its stake in Lake Acquisitions to 51 percent since 2015 but, like Centrica, with no success.

Managing reactors as they age is a constant problem for any technology design, and the AGRs are no exception. In recent years problems with the core’s graphite moderator bricks have raised concerns. In particular, keyway root cracks, exceeding the number the U.K. regulator, the Office for Nuclear Regulation (ONR) previously deemed permissible, have been found at one of the Hunterston B reactors. This is of concern as it can lead to the degradation of the keying system, a vital component as it forms the channels within the reactor, which house the fuel, the control rods and the coolant (CO2). Such cracking or distortion could affect 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 limit set by the ONR. With age, the graphite bricks also distort and may eventually compromise the operation of the safety control rods. These issues are likely to be the life-limiting factor for the AGRs, as it is not possible to replace the graphite bricks.

In March 2018, during a scheduled outage, EDF discovered a higher number of keyway root cracks in the older of the two reactors than was predicted by its computer models in 2016. Then in May that year, EDF announced that Hunterston B-1’s present shutdown would be extended for further investigation and revised modelling, with the intention of restarting the reactor before the end of 2018. In late December 2018, EDF stated that it had “observed around 100 keyway root cracks in Reactor 3. This is from the inspection of just over a quarter of the reactor. Using modelling to project the number of cracks across the whole reactor our best estimate of the current number of cracks is around 370. This takes the core over the operational limit of 350 contained in the existing safety case for that period of operation.327

In December 2018, EDF estimated that reactors would be restarted in March 2019 (B-1) and April 2019 (B-2), but this deadline passed and, as of June 2019, restarts were scheduled for later in July 2019 (B-2) and October 2019 (B-1).328 Age-related problems have also been found at similar-age reactors at Dungeness B, with Unit 2 closed for what was supposed to be a 12-week outage in August 2018 and then Unit 1 for “common statutory outage work”, with both expected to restart in April 2019. However, the outage has been extended, with current restart dates for the units being September and October 2019. In June 2019, in the Office for Nuclear Regulation’s Annual report, it was stated that Dungeness B and Hunterston B were in an “enhanced level of regulatory attention”, rather than routine. This was because assessment of the cracks was “intensive” and required “substantial additional effort.”329

The impact of the cracking on the lifetime of the AGR fleet is yet to be determined. The two reactors at Hinkley Point B, the sister station to Hunterston, are also due for statutory outages with unit 1 starting in March 2019 and then returning to service in June 2019, and unit 2 expected in April 2021.

Sources: WNISR, with IAEA-PRIS, 2019

The development of new nuclear reactors in the U.K. has been slow and will be significantly less successful than envisaged. The current development cycle was “officially launched” in 2006, when then Prime Minister Tony Blair stated that nuclear issues were “back on the agenda with a vengeance”.330 In July 2011, the Government released the National Policy Statement (NPS) for Nuclear Power Generation.331 The eight “potentially suitable” sites considered in the document for deployment “before the end of 2025” are exclusively current or past nuclear power plant sites in England or Wales, except for one new site, Moorside, adjacent to the fuel-chain facilities at Sellafield. Northern Ireland and Scotland are not included. The Scottish government is opposed to new-build and said it would not allow replacement of Scotland’s Torness and Hunterston plants once they are shut down.332

Hinkley Point C Construction Start – Not That Concrete?

EDF Energy was given planning permission to build two reactors at Hinkley Point in April 2013. In October 2015, EDF and the U.K. Government333 announced updates to the October 2013 provisional agreement of commercial terms of the deal for the £16 billion (US$20 billion) overnight cost of construction of Hinkley Point C (HPC).334 The estimated price of construction has since risen and as of 2017 stood at £201519.6 billion (US$201525.3 billion), up from the £201518bn (US$201523.2 billion) quoted in 2016; no official update has been given since. EDF says the £1.5bn (US$1.9 billion) increase announced in 2017 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”335.

EDF maintains the official construction-start target date as “mid-2019” and the “initial delivery objective for Unit 1 at the end of 2025”.336 However, EDF have acknowledged that pouring the first safety-related concrete for Hinkley Point C-1 in mid-2019 can only happen if “the final design, which is on a tight schedule, is completed by the end of 2018.”337

The International Atomic Energy Agency (IAEA) dates formal start of construction for a nuclear power plant as the pouring of first structural concrete and this occurred for the first reactor at HPC on 11 December 2018. WNISR is thus considering Hinkley Point C under construction as of that date.338 However, an EDF Energy spokesperson told WNISR in June 2018 that “the recognised ‘construction start’ has not yet been reached. In the HPC project, this date is termed ‘J0’ and is scheduled to be reached in June 2019” and “It was not the base slab of the reactor building. As I say, this is due to happen in June 2019.” [Emphasis by EDF Energy].339 This is despite, the “site construction director” stating in spring 2018 that “activity is ramping up with over 3,000 people now on-site (...) and over 100,000 tonnes of concrete has already been poured”.340 On 28 June 2019, EDF Energy announced that “Hinkley Point C has hit its biggest milestone yet on schedule. The completion of the base for the first reactor, known as ‘J-zero’, means that the construction of the nuclear buildings above ground can now begin in earnest”.341

By completing a large amount of the work before formally declaring construction began, EDF is able to claim a shortened construction timetable and be more likely to meet the construction deadline. Given the construction delays in China, Finland and France, this could be of primary importance for EDF.

The key points of the Hinkley 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 £89.5–92.5/MWh, in 2012 values (US$115–120/MWh), with annual increases linked to the retail price index. The cost of this support scheme has skyrocketed, with the U.K. National Audit Office (NAO) suggesting that the additional ‘top-up’ payments—the difference between the wholesale price (as of early 2018 at about £50/MWh) and the agreed fixed price (or Strike Price), required through the CfD—have increased from £6.1 billion (US$20139.9 billion) in October 2013 to £29.7 billion (US$201641.2 billion) in March 2016, due to falling wholesale electricity prices. This is the discounted estimate; the undiscounted estimate would be closer to £50 billion. The NAO also stated that “the [Government] Department’s deal for HPC has locked consumers into a risky and expensive project with uncertain strategic and economic benefits.”342

There was an expectation that HPC's construction would be primarily funded by debt (borrowing) backed by U.K. sovereign loan guarantees, expected to be about £17 billion (US$26.9 billion). EDF announced in November 2015 its intention to sell non-core assets worth up to €10 billion (US$11.4 billion), including a stake in Lake Acquisitions, to help finance Hinkley and other capital-intensive projects.343 This includes the partial sale of the French high voltage network (RTE) to the state bank Caisse des Dépôts in March 2017, which raised €4 billion (US$20184.6 billion),344 and in November 2017 the sale of EDF Polska assets, including electricity and combined heat and power plants to Polska Grupa Energetyczna (PGE) for about €1.4 billion (US$20181.6 billion).345

The May administration finally approved the HPC project in September 2016, with the government retaining a “special share”, that would give it a veto right over future ownership if national security concerns arose.346 The expected composition of the consortium owning the plant had changed from October 2013 to October 2015. The effective bankruptcy and dismantling of AREVA made their planned contribution impossible, the Chinese stake had fallen to 33.5 percent and the other investors had not materialized, leaving EDF with 66.5 percent. In May 2016, the China National Nuclear Corporation (CNNC) indicated it didn’t rule out participation in the 33.5 percent Chinese stake.347 However, no changes were reported as of mid-2019.

Other U.K. New-Build Projects

Chinese stakes in the mooted follow-on Sizewell C project would be limited to 20 percent, leaving EDF with 80 percent. Given the problems EDF is having financing Hinkley, this makes the Sizewell project appear implausible. However, EDF is allowing CGN to use the Bradwell site it had bought as back-up, if either the Hinkley or Sizewell sites proved not to be viable. CGN plans to build its own technology, the Hualong One (or HPR-1000) at this site, with EDF taking a 33.5 percent stake.348 In January 2017, the U.K. Government requested that the regulator begin the Generic Design Assessment (GDA) of the HPR-1000 reactor,349 and by November 2018 the Office for Nuclear Regulation (ONR) and Environment Agency had completed an initial high-level scrutiny of the design.350 Work is expected to be complete in 2021.

Of potential importance to the Bradwell project was that in March 2019, Rolls-Royce confirmed that it was reviewing its options for its civil nuclear industry. This could include selling its civilian nuclear arm, which manufactures controls and systems technologies including its supply deal with CGN for reactors in the U.K.351

Foreign ownership of critical infrastructure hasn’t had the same degree of concern as in other countries. Even for nuclear power, CGN’s proposal to build, operate and own a reactor designed in China has not been vetoed, despite growing action in the United States to stop the export of nuclear technology to China for “national security” concerns.352 However, aware of the sensitivities, CGN has indicated that it might be willing to hand over ownership of Bradwell to another operator if that might reduce concerns.353

At the beginning of 2018, there were two other consortia planning to build new nuclear power in the U.K., but these projects were both shelved over the year.


In June 2014, NuGen finalized a new ownership structure with Toshiba-Westinghouse (60 percent) and Engie (40 percent), as Iberdrola sold its shares to Toshiba-Westinghouse. The group planned to build three Toshiba-Westinghouse-designed AP-1000 reactors at the Moorside site, with units proposed to begin operating in 2024.354 However, Westinghouse, after its financial collapse, filed for Chapter 11 bankruptcy protection in the U.S. in March 2017. This had a disastrous impact on the parent company Toshiba, when the extent of Westinghouse’s problems came to light.355 The perilous state of the project also led to Engie selling its remaining 40 percent for US$138 million to Toshiba-Westinghouse, which was contractually obliged to buy them at the pre-determined price.356 In late April 2017, the national press reported that Toshiba was preparing to mothball the project, warning suppliers of spending cuts and ordering seconded staff to return to their employers.357 Amid this economic chaos, the U.K. Office of Nuclear Regulation had approved the AP-1000 reactor design on 30 March 2017.358

Toshiba was initially in talks with both Korea’s KEPCO (Korea Electric Power Corporation), a nationally owned utility and reactor vendor, and CGN of China as potential buyers of NuGen. In October 2017, the CEO of NuGen said he expected to find a buyer by early 2018,359 but KEPCO put off a decision until the autumn of 2018 and said they would only proceed if “a preliminary analysis concludes the project serves the national interests.”360 However, in November 2018 Toshiba announced that it was winding down NuGen, without finding a buyer. This might open up the opportunities for others to buy the Moorside site and build their own reactors—although this has not yet occurred. In the meantime, the Moorside site has reverted to the U.K.’s Nuclear Decommissioning Authority (NDA).

Wylfa and Oldbury

The other company that was involved in proposed nuclear new-build is Horizon Nuclear, which was bought by the Japanese company Hitachi-GE from German utilities E.ON and Rheinisch-Westfälisches Elektrizitätswerk (RWE) for an estimated price of £700 million (US$1.2 billion) in 2012. The company submitted its Advanced Boiling Water Reactor (ABWR) design for technical review, whilst at the time making it clear that its continuation in the project would depend on the outcome of the negotiations with the Government.361 The ABWR, two of which were planned for both the Wylfa and Oldbury sites, passed the justification procedure in January 2015, and the Generic Design Assessment (GDA) was completed in December 2017.362 In April 2017, Horizon Nuclear applied for a site license at the Wylfa location. If everything had gone according to plan, the reactor would have started up in 2025.363

Hitachi was looking for partners in their project, hoping to reduce its stake to 50 percent and, if no other investors could be found, the company would have to withdraw. This is because an internal review by the company had found that the cost of construction was likely to be US$27.5 billion, considered too big a risk for the company on its own.364

In order to attract a partner, Hitachi sought clarification on the financial support that the U.K. Government was willing to facilitate or the extent to which the Government would invest. One option being considered was a trilateral partnership between Hitachi and the U.K. and Japanese Governments. It was reported that the U.K. Government was prepared to make available £13.3billion (US$17.5 billion) in financial support for Hitachi.365

In June 2018, the Government formally announced that it was considering taking an equity stake in the Wylfa project, with a suggestion that the Government share could be up to one-third of the project costs and would provide all the loans needed for the project. The other two-thirds were to be taken up by Hitachi and by Japanese investors identified by the Japanese government. This highlighted the extent to which the Government, despite previous statements to the contrary, recognized that, as The Times puts it, “nuclear power in reality seems to be untenable without it [state support].”366 The Government seemed to hope that by directly investing into the project, it would drive the strike price down to £70–78/MWh (US$92–103 MWh).367 Subsequently Energy Minister Greg Clark said a strike price above £75/MWh (US$96.5/MWh) could not be justified for new nuclear.368

In January 2019, Hitachi announced that it was suspending the project and that this decision was taken “from the standpoint of economic rationality”; in doing so the company accepted a ¥300 billion (US$2.75 billion) impairment. Hitachi pointed to “significant changes in the power market environment,” including the competitiveness of renewable energies.369

The partners and potential partners for the NuGen and Horizon projects will face an uphill battle to get a level of CfD similar to that was awarded to EDF for Hinkley Point C. Criticism of the high support cost for Hinkley and other nuclear projects has intensified with the awarding of tenders for offshore wind, with 2017 support prices of £57.50–74.75 in 2012 money (US$80–101/MWh) in 2017.370 The next round of CfD announcements for offshore wind is expected in late 2019.

A New Funding Model for Nuclear?

In July 2019, the Government announced a consultation for the introduction of a new funding model to facilitate the construction of new nuclear via a Regulated Asset Base (RAB), which “in the case of a nuclear RAB, suppliers would be charged as users of the electricity system and would be able to pass these costs onto their consumers who also use the electricity system”.371 If approved by the Government, the project developer could charge consumers upfront for the construction, which would be broken down into different phases during the build process. EDF have indicated that all households would have to pay £6 (US$7.5) per year additionally for them to build the proposed reactors at Sizewell C.372

Charging upfront reduces the 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 represent a significant share of the overall construction costs. Furthermore, by breaking the construction into different phases, it is expected that this would increase certainty and therefore reduce the cost of finance. It is argued by EDF that the aim would be to reduce the weighted [annual] average cost of capital (WACC) from the 9.2 percent on Hinkley to close to 5.5–6 percent.373

For nuclear, the segmented RAB might include “initial costs of preparing to get started; the costs of laying the foundations; the installation of the reactor; and commissioning—and at each stage, with the costs agreed in advance, there would be scrutiny by the regulator and then, subject to this efficiency test, these costs would then go into the RAB and be recovered from the use of systems charges”.374

A key advantage selling point for the government is that it means that funding does not have to come from the treasury—and therefore off the Government’s balance sheet—and that it removes the need for or at least reduces the level of the Contract for Difference, which highlights the high cost of nuclear compared to all other generating sources.

However, this model is seen as transferring the financing risks to the customer, as the Financial Times reported:

What RAB financing does is transfer project risks to customers, who are least well placed to bear them,” said [the late] Martin Blaiklock, an infrastructure expert who likened the technique to “being forced to pay for a meal at a restaurant before the restaurant has even been built, let alone served any food.375

The U.K. Government has asked for comments on the proposal until October 2019 and it will then decide whether to approve this approach to project financing.

Renewables Kicking In

The constant decline in energy and electricity consumption in the U.K. does not favor the economic case for nuclear new-build. Meanwhile, renewables’ share of electricity generation reached 33 percent in 2018, largely outpacing nuclear power’s contribution of 17.7 percent. The rise in renewables is increasingly impacting the other generators. In April 2019, National Grid published a documentation on “Zero carbon operation 2025”, which makes no reference to nuclear power and states “Our ambition is that, by 2025, we will have transformed the operation of the electricity system such that we can operate it safely and securely at zero carbon whenever there is sufficient renewable generation on-line and available to meet the total national load”.376

Over the past decade the extraordinary cost of the U.K.’s proposed nuclear power program has become apparent to a wider academic community and public bodies. Even when the Government was willing to invest directly into the project, nuclear costs were prohibitive. This is perhaps most clearly demonstrated by the change in the views of the Committee on Climate Change (CCC), an independent body established to advise the Government on meeting its climate-change objectives. In 2011, it stated that “nuclear power currently appears to be the most cost-effective of the low-carbon technologies”.377 Yet in its June 2018 report, the CCC says that “if new nuclear projects were not to come forward, it is likely that renewables would be able to be deployed on shorter timescales and at lower cost”.378 Then in May 2019, in its report on “Net Zero”, the CCC states that “cost reductions in low-carbon technologies is not a universal story. Several technologies which have not been deployed at scale—such as nuclear power, carbon capture and storage (CCS) and heat pumps—have failed to come down in cost”. The Committee estimates that the cost of power in 2025 from solar PV could be £47/MWh (US$58/MWh), for wind £69/MWh (US$48/MWh) and nuclear £98/MWh (US$123/MWh).379

Plutonium – From Long-Term Resource Dream to Endless Liability

The reprocessing of spent fuel, the use of plutonium and the re-use of reprocessed uranium were at the heart of the U.K.’s nuclear industry from inception. Initially this was for military reasons, as the plutonium was for weapons, but then came the development of fast reactors, to enable a “closed fuel cycle”. However, the failure of the global deployment of nuclear power, the rising costs and technical challenges of fast breeders and the availability of uranium have undermined the justification of reprocessing. As of the start of 2017, the U.K. owned over 110 tons of unirradiated separated plutonium, looking for a use.380 Consequently, the start of the cessation of reprocessing at the Thermal Oxide Reprocessing Plant (THORP) in November 2018, with the last fuel put into the plant,381 was an important development for the nuclear industry, although it received surprising little press or political interest. While this marks the end of an era for the industry, it is not the end of activities at the Sellafield plant, which will be decommissioning the facility for decades to come and managing the plutonium for at least centuries.

United States Focus

  • Abandoned Constructions 42
  • Under Construction 2
  • Operating 97
  • Closed 36
Number of Reactors
Mean Age of Reactor Fleet
Annual Load Factor

With 97 commercial reactors operating as of 1 July 2019, the U.S. possesses the largest nuclear fleet in the world. Construction has continued on the one new nuclear plant in the U.S., the twin AP-1000 at Plant Vogtle-3 and -4, following a vote of the owners in September 2018 to continue the project.382 Further cost increases have been reported but with reportedly an improved work schedule.

Two reactors, both General Electric BWR MK 1 designs, were permanently closed in the year to 1 July 2019. The Oyster Creek-1 reactor in New Jersey generated its last kilowatthour on 17 September 2018.383 Connected to the grid in September 1969, it was the oldest operating commercial reactor in the U.S., and was required to be closed no later than December 2018 under an agreement with the state.384 On 31 May 2019, Entergy permanently shut down its Pilgrim reactor in Massachusetts, which was connected to the grid on 19 July 1972.

The fallout from the decision in July 2017385 to terminate construction of the twin V.C. Summer AP-1000 reactors continued through the past year. This included legal action over the recovery of billions of dollars of ratepayers’ money lost to the abandoned project,386 ongoing disclosures of the failure of the project and culpability of utility executives,387 including criminal investigations, and the takeover of the V.C. Summer owner, South Carolina Electric & Gas (SCG&E) and its parent SCANA, by Dominion.388

During the past year, 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 2019, subsidies will be provided to eight nuclear plants in the U.S., in the form of Zero Emission Credits (ZEC): Nine Mile Point, FitzPatrick and Ginna in New York; Clinton and Quad Cities in Illinois; Salem and Hope Creek in New Jersey; and Palisades in Michigan.389 Legal challenges against ZEC nuclear legislation from consumers, NGOs and energy companies are ongoing in all of these states.

The Nuclear Energy Institute (NEI), the advocacy organization for the U.S. nuclear industry, has continued to lobby for financial support for nuclear plants,390 while the Department of Energy (DOE) provided a further loan guarantee of US$3.7 billion to Plant Vogtle construction, the first and only loan guarantee issued under the Trump administration so far.391 This brings the total loan guarantees provided by the DOE for nuclear new-build projects to US$12.03 billion.392

In a further measure to reduce costs for reactor operators, the Nuclear Regulatory Commission’s (NRC) commissioners on 24 January 2019 voted by majority to remove safety requirements proposed in a draft rule making issued in 2016, that, if applied, would have forced utilities to take measures to upgrade their plants to protect against such hazards as flooding and major seismic events.393 The draft NRC rulemaking had already rejected stricter measures proposed by the “Near Term Taskforce Review of Insights from the Fukushima Daiichi Accident” in 2011.394

While it is inevitable that the size of the U.S. nuclear fleet will continue to decline for the foreseeable future, the decline is likely to be slowed by directly subsidizing economically threatened operating plants.

The U.S. reactor fleet provided 808.03 TWh in 2018—a new historic maximum—compared with 805 TWh in 2017. Consequently, the load factor remained stable at a high level (89.8 percent), significantly above the modest lifetime load factor of 75.9 percent. Nuclear plants provided 19.3 percent of U.S. electricity in 2018, compared with 20.1 percent of U.S. electricity in 2017, and about 3 percentage points below the highest nuclear share of 22.5 percent, reached in 1995.

With only one new reactor started up in 20 years, the U.S. reactor fleet continues to age, with a mid-2019 average of 38.9 years, amongst the oldest in the world: 46 units have operated for 41 years or more.

Sources: WNISR, with IAEA-PRIS, 2019

In the year to 1 July 2019, NRC issued 20-year license renewals for four nuclear plants (five reactors): Indian Point-2 and -3395, River Bend-1396, Waterford-3397, and Seabrook-1398. Utility owners of two nuclear plants submitted applications for subsequent license renewal, which, if granted, could see the reactors operate for an additional 20 years beyond their current sixty-year license. Exelon Generation Company, LLC (Exelon), applied to the NRC on 10 July 2018 for subsequent license renewal for Peach Bottom-2 and -3.399 These reactors, both connected to the grid in 1974, are General Electric MK1 BWRs.

The subsequent license request for Peach Bottom -2 and -3 is being contested by the organization Beyond Nuclear.400 In evidence seeking a review by the Atomic Safety Licensing Board (ASLB), expert witness Dave Lochbaum contends that Exelon in its application to the NRC had failed to address how operating experience will be applied during the 60–80-year period of operation of Peach Bottom-2 and -3. This is despite the fact that “[a]bundant evidence also speaks to gaps, deficiencies, and uncertainties in present understanding of aging degradation mechanisms.” 401

In October 2018, Dominion Energy Virginia submitted its Subsequent License Renewal application for the Surry Power Station 1 and 2, which were connected to the grid in March 1972 and March 1973 respectively.402 The NRC is now reviewing six reactors for 60–80-year operation, following the application for the Turkey Point-3 and -4 reactors in May 2018.403 The NRC is planning to issue a final decision on the Turkey Point reactors in October 2019.404 In July 2017, the NRC published a final document describing “aging management programs” that might allow the NRC to grant nuclear power plants operating licenses for “up to 80 years”.405

As of 1 July 2019, 89 of the 97 operating U.S. units had received a license extension.406 However, experience shows that many reactors are closing long before their license expires.

Reactor Closures

On 17 September 2018, the oldest reactor in the U.S. fleet, the 650 MW Oyster Creek reactor in New Jersey, entered permanent closure. Exelon, the owner of the 49-year-old BWR GE MK1 connected to the grid on 23 September 1969, had confirmed its intention for closure in February 2018.407 The safety of the reactor had long been under contention from a coalition of NGOs, including evidence of severe corrosion of the reactor containment system that was effectively ignored by the NRC during the reactor’s relicensing process in the mid-2000s.408 The NRC issued 20-year life extension approval for Oyster Creek in August 2009, granting the reactor operation until 2029.

In August 2015, Exelon had announced that Oyster Creek (together with Quad Cities and Three Mile Island) had not cleared the Pennsylvania New Jersey Maryland Interconnection LLC (PJM) capacity auction for the 2018–19 planning year.409 Exelon announced on 31 July 2018 that Holtec International was interested in the purchase of the Oyster Creek reactor.410 The NRC approved the sale to Holtec on 20 June 2019.411 As WNISR 2018 reported, this model of transferring ownership was already adopted by the utility Entergy for its Zion plant in Illinois (with ownership transferred to EnergySolutions). These developments are problematic as limited-liability companies are only financially liable—in the case of an accident or other legal dispute—up to the value of their assets. Therefore, if the decommissioning funds are exhausted, such a third-party company could declare bankruptcy, leaving the bill for the taxpayer.412

On 31 May 2019, Entergy permanently closed its 47-year old GE MK1 Pilgrim reactor. The 668 MW unit was connected to the grid on 19 July 1972.413 Senator Ed Markey described the plant as having “one of the worst safety records of any nuclear facility in the country”.414 The reactor remained embroiled in safety concerns, not least after four emergency shutdowns (SCRAMs) between 2013–15.415 Long-standing opponents of the plant had challenged Entergy’s application for a 20-year license extension, which was granted by the NRC in 2012, though opposed by then NRC Chair Gregory Jazcko, and which permitted the reactor to operate until 2032.416 Only three years after being granted lifetime extension, Entergy was facing mounting costs, including for safety retrofits, which the utility was reluctant to invest in. These difficulties, combined with loss of competitiveness in the electricity market, led Entergy in 2015 to announce that Pilgrim was “simply no longer financially viable” and would be closed on 31 May 2019.417

In November 2018, Entergy filed notice with the NRC for the sale of the Pilgrim reactor to Holtec International. Holtec would take ownership after closure, justified by the utility on the grounds that Holtec would “complete decommissioning and site restoration decades sooner than if Entergy completed decommissioning”.418

Exelon Generation announced on 8 May 2019 that Three Mile Island-1 (TMI) will permanently close by 30 September 2019.419 The 45year old reactor was connected to the grid on 19 June 1974. In 2009, the NRC granted a 20-year license extension to operate until 2034. In August 2015, TMI did not clear the PJM capacity auction for the 2018–19 planning year,420 and Exelon warned in 2017 that failure to approve subsidies by the Pennsylvania legislature before 1 June 2019 would lead to the reactor’s closure.421 As of 1 July 2019, no such legislation had been passed (see section on Zero Emission Credits (ZECs) hereunder). The decision to finally close nuclear operations at the power plant site came 40 years after TMI-2 suffered a partial core fuel meltdown on 28 March 1979. (See Table 8 and Figure 33).

Sources: Various, compiled by WNISR, 2019

Table 8 | Early-Retirements for U.S. Reactors 2009-2025



Decision Date

Closure/Expected Closure Date
(last electricity


Age at Closure
(in years)

NRC 60-Year License


Oyster Creek


8 December 2010

December 2019 brought forward to 17 September 2018



Crystal River-3

Duke Energy

5 February 2013

26 September 2009


Application withdrawn

San Onofre-2 & -3


7 June 2013

January 2012

29 / 28

No application


Dominion Energy

22 October 2012

7 May 2013



Vermont Yankee


28 August 2013

29 December 2014





13 October 2015

31 May 2019



Diablo Canyon -1 & -2


21 June 2016

November 2024 & August 2025



Fort Calhoun


26 August 2016

24 October 2016





8 December 2016/

28 September 2017




Indian Point-2 & -3


9 January 2017

No later than 30 April 2020 / 30 April 2021

47 / 44


Three Mile Island-1


30 May 2017

September 2019



Beaver Valley-1 & -2 

First Energy

March 2018




Davis Besse-1

First Energy

March 2018





First Energy

March 2018




Sources: Various, compiled by WNISR, 2019


a - Early closure potentially reversed – see Table 9.

b – According to the NRC, FENOC indicated that with the planned closure of Perry they no longer plan to submit a license renewal application422.

SCE: Southern California Edison; SDG&E: San Diego Gas & Electric; PG&E: Pacific Gas & Electric Company; OPPD: Omaha Public Power District

New Reactor Construction

“If we were deciding today, I don’t think we would decide to build these units (at Plant Vogtle) because natural gas and solar are so cheap today.”
Tim Echols, Georgia Public Service Commission (PSC) who voted for completing the Vogtle project in May 2019.423

The cancellation of the V.C. Summer reactors means that the only new nuclear plant construction in the United States is Plant Vogtle in Georgia. Construction of Vogtle-3 officially began in March 2013, with Unit 4 following in November 2013.424 The original project cost approved by the Georgia Public Service Commission (PSC) was US$6.1 billion in 2009, which corresponds to a cost of US$2,350/kW, whereas the 2017 cost estimates of US$23 billion translates to a cost of US$10,000/kW. The revised 2018 estimates in the range of US$28 billion have increased costs to US$11,000/kW.425 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/kW426 (US$20184,800). During the past year, further cost increases have been reported. There are differing opinions on completion schedules with the utility expressing confidence that it can meet target dates of November 2021 and November 2022 for Units 3 and 4 respectively. Critics of the Vogtle project had long predicted over the past decade that costs would be much higher, as now confirmed.427

As WNISR2018 reported, on 31 August 2017 Southern Company (parent company of majority Vogtle plant owner, Georgia Power) filed its recommendation with the Georgia PSC to continue construction of Vogtle—supported by its other owners Oglethorpe Power Corporation (OPC), Municipal Electric Authority of Georgia (MEAG) and Dalton Utilities.428 In addition to continuation of the project, Georgia Power reported that it had also reviewed the options of cancellation of Unit 4, as well as cancellation of both units. The recommendation was based on the results of a comprehensive schedule, cost-to-complete and cancellation assessment, according to Southern Company. The President of Georgia Power stated that “Completing the Vogtle-3 & 4 expansion will enable us to continue delivering clean, safe, affordable and reliable energy to millions of Georgians, both today and in the future”.429

As WNISR2018 also 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 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, a Georgia Power residential customer using 1,000 kWh per month would have seen his/her 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 PSC, ratepayers had already paid US$2 billion to Georgia Power as of November 2017.430 But given the long timescale of the project, including planned operational life, the actual costs to ratepayers will be much higher. In December 2017, under cross-examination from Georgia Watch, a public interest group, Georgia PSC staff had confirmed that “the nominal life cycle capital cost revenue requirement collected from ratepayers would increase from US$23 billion to US$37 billion...” Georgia Watch’s Liz Coyle concluded that “if the Commission adopts the Company’s recommendations as filed, the Company profits will increase by 5.2 billion dollars and ratepayers will pay an additional 14 billion dollars.”431

In early August 2018, Southern Company reported that it had revised its own expenditure for the project from US$7.3 billion to US$8.4 billion, stating that the increase would be absorbed by the company (i.e. its shareholders), not by customers.432

As to the construction schedule, in 2017, officially Southern Company gave fuel-loading times as November 2021 for Unit 3 and November 2022 for Unit 4, which compares with an original planned startup date of 2016. However, the operational dates from Southern are at variance with the assessment made by the Georgia PSC in its December 2016 quarterly progress report, which indicated a credible completion date of 2023. Obtained by E&E News433—one public version, the other classified as “Highly Confidential Trade Secret EPC Information”—the report cast major doubts on the company’s estimated completion dates of the Vogtle reactors, with future long-term activities identified by “staff as high risk for delay.” Although both versions of the report were heavily redacted, it confirmed that “there have been continued delays” and “that all of the paths to Unit 3 completion are under schedule stress and will likely incur additional delays.”434 The 2023 date itself was highly speculative, and was on the basis of maintaining the 2016 nine-percent annual construction completion-rate, with no further delays, which given the track record of the project must be in serious doubt.

During the past year, Southern Company reported that the completion schedule was on track. On 20 February 2019, Southern Company’s CEO Tom Fanning said that “a lot of work ahead of us to sustain this performance, but we are pleased with our progress and are confident that we can meet the schedule approved by regulators.”435 The optimism of the utility contrasts with continuing warnings from Georgia PSC staff. In their November 2018 report to the Georgia PSC, which was an analysis of the “Nineteenth Semi-Annual Vogtle Construction Monitoring Report”, they questioned both the credibility of the construction schedule and the risk of further cost increases, noting that “the +21-month schedule is highly unlikely to be achieved” and even the “+29-month schedule is also stressed.”436 In terms of costs, the Georgia PSC staff noted that at “the monthly spending rate, currently $200 million per month (100 %) on the Project, the cost consequences of Project delay could be severe depending on the duration of the delay.” Staff concluded that “at this time the status of the Project is uncertain,”437 with major uncertainties whether the target date of Hot Functional Tests scheduled for Unit 3 on 31 March 2020 can be achieved. Fuel loading is scheduled for 14 October 2020.

According to a media write-up,438 during December 2018 hearings on the latest assessment from Southern, expert testimony warned that the cost to ratepayers will be nearly “US$4 billion in financing costs and income tax expenses upon completion. That figure is likely to increase and affect ratepayers who have financed the project since construction began in 2011”; with experts warning that “a delay of more than eight months may deem the project, now about 71 percent complete, ‘uneconomic to continue.’”439

At the February 2019 session of the Georgia PSC, regulators approved a further US$526.4 million in costs for the Vogtle plant to be paid for by Georgia ratepayers.440

As reported in WNISR2018, on 13 February 2018 a coalition of groups filed in Fulton County Superior Court a complaint challenging the Georgia PSC decision, declaring that it was unlawful, violating the PSC’s own guidelines and Georgia state law.441 The coalition contended that new investments in solar power and energy efficiency would be less risky, more affordable, and more than up to the job of powering Georgia’s economy. On 21 December 2018, the court found that dissatisfied customers cannot raise concerns about the unfairness of Goergia PSC process “until 2022 or later, after the project is complete.”442 “The court dismissed the appeal on technical grounds without addressing its substance,” attorney Kurt Ebersbach of Southern Environmental Law Center (SELC) stated.443 “The people of Georgia have been pre-paying for this mismanaged project since 2011, while the price tag has ballooned and the project timeline has slipped again and again,” Liz Coyle, executive director of Georgia Watch, said. “Unless the court reverses the commission’s decision, Georgia Power customers remain exposed to significant financial risk with seemingly no end in sight.”444 The groups are planning to challenge the court decision.

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.” Full-year 2018 earnings were US$2.23 billion, compared with earnings of US$842 million in 2017.445

The Vogtle plant construction has faced ongoing legal challenges since approval for construction in 2009. On 19 February 2019, the Fulton County Superior Court in Georgia granted class-action status to a lawsuit challenging charges Georgia Power Co. collects from customers each month related to Vogtle construction. The lawsuit, originally filed in 2011,446 charges Georgia Power with artificially raising municipal franchisee fees. “This is a good day for electric power customers in Georgia. For the first time in over seven years, a court has authorized plaintiffs to move forward as a group representing all two million-plus ratepayers”, said the plaintiffs’ lawyer and former speaker of the state House of Representatives, Glenn Richardson.447

In a separate lawsuit, on 18 June 2019, the Georgia Court of Appeals heard arguments about whether the 2017 Georgia PSC decision to continue the construction of Vogtle broke regulatory rules.448 The coalition of citizens’ organizations challenging the Georgia PSC, including Georgia Watch and Georgia Interfaith Power and Light, filed the appeal after their case was dismissed on technical grounds in December 2018.449 They contend that the 2017 decision approving the completion of the Vogtle reactors should have been subject to judicial review.450 Under Georgia PSC guidelines, commissioners are not required to judge whether costs are prudent until after the plant is complete, when retroactive prudency hearings are held. Only then advocates are allowed to challenge expenses. As the lawyer representing the plaintiffs states, “And that’s their [Georgia Power’s] argument: ‘Wait until we build it.’ But if you wait ‘til you build it, you can’t go back and say, was it right to continue? It’s moot at that point. They’re taking away one of the powerful arguments to hold the company accountable, which is whether or not the additional expenses are reasonable. And that matters. Because it shifts the burden of proof.”451 Georgia Power’s attorney stated that “It’s not a question of whether they can seek judicial review. It’s a question of when.”452 A decision by the court is expected by the end of 2019.

Vogtle Federal Loan Guarantees

Under the terms of the Department of Energy (DOE) Loan Guarantee Program, owners of nuclear projects are able to 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 rates, 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.453

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 nuclear plants being built in the U.S. in the coming decades. 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. The other owners, Georgia Power and Municipal Electric Authority of Georgia (MEAG), have secured US$8.3 billion in separate loan guarantees from DOE since 2010, when they were approved by the Obama administration. Both of these 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.454 A decision on terminating the Vogtle project would raise the prospect of repayment of the previous US$8.3 billion loan to Southern.455

In April 2019, the DOE provided a further 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.456 This brings the total loan guarantees provided for the Vogtle project by the DOE to US$12.03 billion.457

Ongoing Fallout from Termination of V.C. Summer Project

As in WNISR2018, 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 project during the past year has seen ongoing financial and legal fallout for the companies and ratepayers of South Carolina.

On 24 November 2018, SCANA and SCG&E agreed to a US$2 billion settlement to resolve a ratepayer lawsuit over cost recovery for the abandoned V.C. Summer nuclear expansion project.458 Under the controversial Base Load Review Act (where ratepayers pay during the construction period) there had been nine rate increases that to date have cost ratepayers US$2 billion. Under the agreement, approved by the Georgia PSC on 14 December 2018, while there was to be a reduction of 15 percent in electricity prices, South Carolina’s citizens will continue to pay towards the abandoned project for an additional US$2.26 billion over the next 20 years.459 The decision of Georgia PSC was part of an overall settlement whereby SCANA would be taken over by Dominion Energy; the utility had threatened to walk away from its SCANA takeover if the Georgia PSC were to approve higher rate cuts.460 Critics of the agreement estimated that total costs to ratepayers will amount to US$5 billion.461 When V.C. Summer was cancelled in 2017 total costs for completion of the two AP-1000 reactors was projected to exceed US$25 billion—a 75 percent increase over initial estimates.462

Meanwhile, legal action against SCANA continues in 2019, including a civil fraud lawsuit that will proceed to jury trial,463 with a ratepayers’ lawyer telling the federal court judge: “The bottom line is they (SCANA executives) lied to everyone, and they did it intentionally.”464 It is known that since 2017 the Federal Bureau of Investigations (FBI) and the U.S. Attorney’s office of South Carolina have been conducting an investigation into alleged criminal fraud by former SCANA top officials.465

The cancellation of the V.C. Summer project adds to the history of 40 other stranded nuclear reactor projects in the United States whose construction started in the 1970s and which were abandoned between 1977 and 1989, as can be seen from the WNISR’s Global Nuclear Power Database.466

Securing Subsidies to Prevent Closures

“This is the only industry known where when you’re not doing well you don’t go to shareholders and have them pay and suffer the losses, you go to the ratepayers and make them pay. This is a bailout for aging and obsolete technology.”
Ohio State Senator Sean O’Brien, May 2019 467

Utilities have been actively lobbying for state legislation and contracts that would provide significant financial support for their reactor operations (for details see WNISR2018—Annex 4). In addition to legislation that has been enacted in New York and Illinois, new policies have been implemented in Connecticut and New Jersey, while efforts are ongoing to secure funding mechanisms continue in Pennsylvania and Ohio. Central to the future of nuclear power in the Pennsylvania-New Jersey-Maryland Interconnection LLC (PJM) wholesale electricity market are the rules expected to be proposed by the Federal Energy Regulatory Commission (FERC).468 PJM is a Regional Transmission Organization (RTO) that coordinates the wholesale electricity market in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. In June 2018, FERC invalidated the PJM market rules.469 The FERC order relates to how the PJM sets the price of capacity it procures through its capacity market, known as the Reliability Pricing Model (RPM). As state subsidies, including Zero Emission Credits or ZECs, have evolved from small-scale renewables to thousands of megawatts from larger nuclear units, FERC noted: “With each such subsidy, the market becomes less grounded in fundamental principles of supply and demand.”470 The next PJM capacity market auction will take place in August 2019.471 As of 1 July 2019 the rule changes from FERC have not been issued. They will affect how state subsidies, including ZECs, will be considered in the wholesale market. At issue is whether the subsidies being received by utilities for their nuclear plants will be factored into the capacity auction pricing. The PJM stated that pending new rules from FERC it will hold the August auction under current rules.472

As a result of securing financial support for reactors, it is likely that “early closures” of several additional reactors will be cancelled (see Table 9).

In December 2018, Dominion secured approval to gain subsidies for its two reactors at Millstone in Connecticut. Existing generating capacity in the state, such as the Millstone plant, cannot be credited for its zero-carbon and other environmental attributes unless it is designated by state regulators as being at risk of early closure. Dominion applied for that status for Millstone and received it in early December 2018. Prior to this approval, under the Low and Zero Emissions Renewable Energy Credit Program only renewable energy was eligible. Dominion threatened to close Millstone early unless recognized as a renewable source. In December 2018, Dominion got state approval to purchase just over 50 percent of the Millstone output over a period of ten years but without setting a contract price. The state had passed in November 2017 legislation that secured just under 50 percent of Millstone’s output over a ten-year period.

Dominion in early 2019 continued to lobby over pricing473 and on 15 March 2019, Dominion announced that it had reached agreement with state utilities and therefore would not be closing the Millstone reactors.474

Table 9 | U.S. State Emission Credits for Uneconomic Nuclear Reactors 2016–2019
(as of 1 July 2019)




Planned Permanent Closure Date

Status of Permanent Closure


Status of Emissions Credit Legislation


Legal Status




June 2017


Illinois Future Energy Jobs Act passed by legislature – June 2016

US$16.50/MWh (US$200 million a year)

ZEC Upheld

in Courta

Quad Cities-1 &- 2

June 2018





September 2019


Legislation not passed as of 1 July 2019




Beaver Valley-1 & -2



New Jersey


Salem-1 & -2


by 2019

Likely to be cancelled

Legislature passed – April 2018 (reactors with operating license through 2030 only)

US$300 million

a yearb

Legal challenge filedc


Hope Creek


by 2019

Likely to be cancelled




Millstone-2 & -3

Threatened – no date


Senate Zero Carbon Procurement Act approved by Governor November 2017d

US$330 million a year


New York




Likely to be cancelled

NYPSC Clean Energy Standard ZEC passed in 2016

US$482 million 2018–2019; US$8 billion 2017–2029





Likely to be cancelled

Nine Mile Point-1


Likely to be cancelled



Davis Besse

May 2020

To be cancellede

Legislation passed as of 27 July 2019

US$150 million per year



May 2021

Sources: Various, compiled by WNISR, 2019


a - See Pamela King, “SUPREME COURT—The fight's not over yet on state nuclear credits”, E&ENews, 16 April 2019,
see https://www.eenews.net/stories/1060166933, accessed 12 July 2019.

b - RTO Insiders, “NJ Approves $300M ZECs for Salem, Hope Creek Nukes”, 19 April 2019,
see https://rtoinsider.com/nj-approves-zecs-nukes-114741/, accessed 15 July 2019.

c - ProPublica, “New Jersey’s $300 Million Nuclear Power Bailout Is Facing a Court Challenge. Does It Have a Chance?", 16 May 2019,
see https://www.propublica.org/article/new-jerseys-300-million-nuclear-power-bailout-is-facing-a-court-challenge-does-it-have-a-chance, accessed 13 July 2019.

d - Robert Walton, “Dominion threatens Millstone closure if plant shut out of support program”, Utility Dive, 10 July 2018,
see https://www.utilitydive.com/news/dominion-threatens-millstone-closure-if-plant-shut-out-of-support-program/527364/, accessed 12 July 2018.

e - FirstEnergy has announced that it will begin the process to rescind the deactivation orders for its Perry and Davis Besse reactors.
See FirstEnergy Solutions, "FirstEnergy Solutions Applauds Enactment of HB6 Legislation", 24 July 2019, op. cit.

The Millstone nuclear plant was listed in 2017 as the most profitable in the U.S. through 2019, at US$14/MWh.475 Yet Dominion used the threat of closure of Millstone as leverage to secure state support. In a 2017 study commissioned by the Stop the Millstone Payout coalition, a group composed of competitive energy companies—NRG, Calpine and Dynegy and the Electric Power Supply Association (EPSA)—challenged Dominion’s claims. The study showed that state support for Millstone would cost ratepayers US$330 million per year, translating to a 15–20 percent increase in supply costs.476

Exelon Generation communicated in February 2019, that its three nuclear plants in Illinois, Braidwood, Byron and Dresden were

…showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.477

As noted by Nucleonics Week (NW), “The company had not previously said publicly that those plants were at risk of early closure.”478

In January 2018, Exelon had already secured Zero Emissions Credits for its Quad Cities and Clinton reactors, which equates to a cumulative value over the expected life of the ZEC contracts, without any adjustments, of US$3.5 billion.479 Currently, its Dresden, Byron and Braidwood reactors with an installed capacity of 6.9 GW, are not eligible for ZECs, as the existing support for Quad Cities and Clinton “fill[s] up the scope of the existing ZEC program under Illinois law”.480

Legal efforts to overturn ZEC contracts in Illinois (and New York) were rejected by the Supreme Court on 14 April 2019.481 As WNISR2018 reported, the Electric Power Supply Association (EPSA) had filed a complaint in the U.S. District Court of the Northern District of Illinois opposing the proposed ZECs for Exelon, stating that “bailing out uneconomic power plants is a bad deal for Illinois ratepayers, who will see their electric bills go up across the state”.482

The Supreme Court ruling follows federal appeals court rulings in New York483 and Illinois484 during September 2018, which endorsed the constitutional rights of states to establish financing for generators and to regulate electricity prices. By doing so the courts have rejected contentions that support for nuclear power by state legislation (such as ZECs) influences the prices that result from the wholesale auction system established by the Federal Energy Regulatory Commission (FERC) and therefore distorts the market mechanism for determining which energy generators should close.485 Lawyers observed that the rulings do not resolve the underlying tensions between state subsidies and wholesale electricity markets.486

On 18 April 2019, the New Jersey Board of Public Utilities (NJBPU) awarded Zero Emission Certificates (ZECs)487 to Salem-1 and -2 and Hope Creek reactors.488 The State Legislature passed the Zero Emissions Certificate Law in May 2018489, noting the “moral imperative for the State to invest in energy infrastructure that does not produce greenhouse gases.”490 Welcoming the decision, Public Service Enterprise Group (PSEG) stated that, “We are pleased with the decision to award ZECs to PSEG to help support New Jersey’s primary supply of zero-carbon electricity. The BPU just saved the people of the State hundreds of millions of dollars in what would have been higher energy costs, thousands of jobs lost and tons of environmentally damaging air emissions.”491 Opposition to the ZEC legislation, including from New Jersey’s Ratepayer Advocate and a generators’ group in the Pennsylvania-New Jersey-Maryland Interconnection LLC (PJM) market, said there is no evidence three nuclear units in New Jersey need ratepayer subsidies to survive.492 In testimony to the Board, from State Rate Counsel President Stephanie Brand it was stated that modeling used by the utilities in the subsidy application did not account for the addition of renewable energy resources over the long term or increased energy efficiency requirements: “In short, they skewed the analysis of future revenues in order to deflate those revenues and support their claim 3 of financial distress.”493

The data suggests that the ZEC Act would require New Jersey electric distribution companies (“EDC”) to collect approximately [US]$300 million per year from New Jersey retail distribution customers based on annual data. This amount would be incremental to charges collected from distribution customers and transmission for other programs. For the three nuclear units, the ZEC Act would result in a [US]$10/MWh revenue adder for each unit’s owner if the Board approves the three applications… The ZEC Act allows the Applicants, who are merchant owners, to cover costs—including the cost of capital. 494

The credits were to be available immediately, which will net approximately US$10/MWh amounting to US$100 million in subsidies per year for each reactor through 2022. The two units at Salem owned by Public Service Enterprise Group (PSEG) subsidiary PSEG Nuclear and 43 percent by Exelon are licensed by the Nuclear Regulatory Commission (NRC) to operate until 2036 and 2040. Hope Creek is licensed to operate until 2046.

For the third time in as many years, FirstEnergy Solutions has sought to secure state financing for its reactors in Ohio. Both Davis Besse and Perry reactors are long considered at risk of closure due to economic factors.495 On 31 March 2018, FirstEnergy Solutions Corp. and six affiliated debtors each filed a voluntary petition for protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court for the Northern District of Ohio.496 The company is currently under petition at the NRC due to its failure to secure sufficient decommissioning funds for its three nuclear plants.497 A 2017-estimate put decommissioning costs for the three nuclear plants at US$5.4 billion, with a current fund level of only US$2.5 billion.498 In April 2018, First Energy filed official notification with the NRC of its bankruptcy and planned closure of Beaver Valley (Pennsylvania), as well as the two reactors at Davis Besse and Perry in Ohio.499 First Energy noted: “We are actively seeking policy solutions at the state and federal level as an alternative to retiring these plants, which we believe still have a crucial role to play in the reliability and resilience of our regional grid.”500 but that “short of significant market changes... right now, we have nothing in front of us that allows us to rescind that deactivation notice.”501 FirstEnergy’s debts amounted to US$2.8 billion.502

The decision of FirstEnergy Solutions is a further signal that just because reactors have obtained 20-year license extensions does not mean they will operate through the full license period. The Beaver Valley Units 1 and 2 in 2009 were issued by the NRC 20-year license extensions to permit them to operate until 2036 and 2047 respectively.503 FirstEnergy had notified the NRC only in May 2017 that it planned to file a license extension in 2020 for the one Perry reactor, whose current license expires in 2026. The 42-year-old Davis-Besse reactor was granted an NRC license extension in 2015, to operate through 2037.504

Despite bankruptcy filings in 2018, FirstEnergy continued to spend millions of dollars on lobbying and advertising

FirstEnergy’s power purchase agreement approved in March 2016505 was blocked by the Federal Energy Regulatory Commission (FERC) a month later. Through 2016 and 2017, FirstEnergy then continued to lobby for the establishment of Zero Emission Nuclear (ZEN) legislation that would support their Davis Besse and Perry reactors, which could be worth an estimated US$300 million a year to their owners. In October 2017, a fresh bill was introduced, the ZEN resource program, aimed at saving the Davis Besse and Perry reactors, leading FirstEnergy to claim that it “would increase the likelihood of keeping the plants operational throughout the life of the program.”506 The bill reduces the amount FirstEnergy would receive over two consecutive periods of six years, from US$300 million in previous introduced legislation to US$180 million.507 The Perry reactor was expected to operate at a profit of US$3.5/MWh during 2017–2019, with Davis Besse at US$4.5/MWh through the same period. These figures do not include the additional income if Ohio’s emissions credits are finally approved.

The proposed legislation made no progress during the year 2018, despite appeals by the bill’s sponsor to move forward following FirstEnergy’s filing for bankruptcy.508

Despite bankruptcy filings in 2018, FirstEnergy continued to spend millions of dollars on lobbying and advertising in efforts to secure favorable legislative changes in Ohio and Pennsylvania.509 In spring 2019, the Ohio legislature introduced the House Bill 6 or HB6, which would create the Ohio Clean Air Program and provide “clean energy” credits to zero-emission power producers, including Davis Besse and Perry plants.510 Financing is proposed through the Ohio Clean Air Fund. Amendments made to the Bill by Republican sponsors meant that by 28 May 2019 it was clear that the primary beneficiary of the legislation will be FirstEnergy. The estimated US$197.6 million that would be charged in new ratepayer fees would largely be paid to FirstEnergy. Renewable energy companies will not be able to access the Ohio Clean Air Program, with only small domestic wind turbines being eligible. Legislatures have also proposed terminating existing programs that encourage electricity providers to purchase renewable energy as well as energy efficiency programs. Finally, coal power with sequestration would be eligible for financing.

The proposed HB6 and its effective termination of support for significant renewable energy programs and energy efficiency—while instead supporting coal plants in Ohio—runs counter to those who have argued that ZEC support for nuclear plants is a necessary part of an eventual transition to renewable energy. This includes the United States Court of Appeals for the Second Circuit, which in September 2018 stated that in the case of New York, “the ZEC program aims to prevent nuclear generators that do not emit carbon dioxide from retiring until renewable sources of energy can pick up the slack.”511

HB6 charges Ohioans a US$1 fee each month starting in January 2021 for nuclear energy. The fee is higher for businesses (US$15) and industrial customers (US$250 to US$2,500). The fees would in early versions of the legislation be applied for five years through 2026, but amendments by House Republicans would lock in the charges until 2030.512 It has been estimated that these subsidies would net EnergySolutions US$320 million each year for its two nuclear plants. As reported in Ohio, the bailout of FirstEnergy is nothing new. Since 1999, FirstEnergy has received US$10.2 billion in state subsidies.513

Opposition to the legislation included the Chair of the Energy Generation Committee, and the Energy and Natural Resources Committee:

This is a bailout plain and simple. What has happened is that First Energy and First Energy Solutions, they’re in bankruptcy and they need a bailout. (…) Everyone will pay even if their electricity is not provided by nuclear power plants, everyone in Ohio will have to pay. First Energy has been bailed out before.514

On 13 May 2019, analysis of the economics of Davis Besse and Perry reactors argued that “The Ohio nuclear units are operating profitably in covering their going forward and avoidable costs and future capital expenditures. Consequently, there is no rational economic reason for them to retire.”515 The calculations of the reactors was based on unit specific costs, “whose relative accuracy has been verified by examining FirstEnergy financial statements in Securities and Exchange Commission (SEC) filings.”516 This is in contrast to the PJM that uses industry average single unit costs.

FirstEnergy rejected the analysis, citing that it “excludes critical cost components” including capital spending requirements and ignores the fact that the plants did not clear PJM’s 2021/2022 capacity auction and will likely not clear future auctions. The power provider said that fixing the consultant’s “obvious calculation errors” results in a net loss of more than $125 million/year versus a profit for the plants.517

The justification for the HB6 legislation was also challenged in a May 2019 analysis from the Institute for Energy Economics and Financial Analysis (IEEFA).518 It concluded that “FirstEnergy’s nuclear and coal plants are not needed to ensure electricity supply or reliability in Ohio”, and that terminating the reactors is “unlikely to drive up electricity rates in Ohio—but reducing energy efficiency and renewable energy could have that effect.” IEEFA contended that, “If Ohio is serious about providing low cost sources of clean energy, it would make more economic sense to invest in solar energy than to subsidize aging nuclear plants.”519

On 28 May 2019, the HB6 legislation was passed by the Ohio House.520 FirstEnergy was hoping that approval by the Senate would take place during June 2019, before the end of the current legislative sessions and when the utility was to decide whether to proceed with plans for refueling of the Davis Besse reactor, which was scheduled for closure in 2020. Securing HB6 would also likely see reversal of the decision to close Perry in 2021. While the legislature ended on 28 June 2019, before the Senate could vote on HB6, additional dates were added to the session. On 17 July 2019 the Senate passed HB6,521 and on 23 July 2019 the House also voted to approve the Senate version of the legislation.522 The Governor of Ohio signed the legislation into law the same day. Welcoming the legislation, FirstEnergy Solutions announced that it will “begin the process to rescind the deactivation orders for its Perry and Davis-Besse nuclear power stations and immediately resume preparation for the mandatory Davis-Besse refueling outage in the Spring.”523

The final version of HB6 will mean that from April 2021 through 2027, FirstEnergy Solutions will receive quarterly payments that will net on average US$150 million each year from additional electricity charges on domestic and industrial customers. An additional nearly US$50 million a year will be received by Ohio Valley Electric Corp to operate two old coal plants in the state.524 In addition, energy-efficiency standards will end for each utility in Ohio once it achieves a 17.5-percent power reduction while also reducing the state’s renewable-energy target from a maximum of 12.5 percent by 2027 to 8.5 percent by 2026—the level that, under current law, utilities must reach by 2022.525 The American Wind Energy Association stated: “Ohio consumers and manufacturers want greater commitment to renewable energy, not less...(it) won’t make Ohio’s air cleaner, but it will hike consumer electric bills and send both jobs and clean energy investment to Ohio’s neighbors”.526 HB6 arguably sets a new standard for costly and asymmetrical state action to bail out failing coal and nuclear investments while disadvantaging efficiency and renewables.

In Pennsylvania, while legislative initiatives failed in 2018 to secure bailouts of nuclear plant operators, efforts continued during the past year. A contentious debate has been underway over the extent to which Exelon and FirstEnergy are seeking state support for their reactors in the state citing unfavorable market conditions, while at the same time failing to disclose detailed financial statements on grounds of commercial sensitivity. In May 2017, Exelon had announced that TMI-1, scheduled for closure in September 2019, and Quad Cities in Illinois, for the third year running, had not cleared the PJM base residual auctions. With FirstEnergy’s Beaver Valley-1 and -2 planned closures in May and October 2021 respectively,527 total closures in Pennsylvania would represent 25 percent of the state’s nuclear generating capacity, but only 6 percent of the state’s overall power generation.

One analysis released in March 2019 provided insight into the economics of TMI and Beaver Valley nuclear plants operating in Pennsylvania.528 In the case of Exelon’s TMI-1, it reported that losses for 2018 were likely to be in the range of US$73 million; FirstEnergy’s twin Beaver Valley units were found profitable by US$23–96 million per year depending on whether they cleared the PJM auction, but could be as high as US$173 million if based on the day-ahead average Locational Marginal Price (LMP).

The PJM Interconnection in a 5 June 2019 analysis concluded that there would be “no reliability impact from the planned closures of the Davis Besse, Perry and Beaver Valley nuclear units... [however] it can reasonably be expected that imposing additional out-of-market subsidies to retain generation that would otherwise retire would have a chilling effect on new investment in the longer term.”529

Two legislative efforts were underway in the Pennsylvania House and Senate in early 2019.530 In March 2019 an amendment was proposed to the 2004 Alternative Energy Portfolio Standards (AEPS) Act that would provide financial support to the state’s nuclear plants, which were currently excluded.531 The principal sponsor of the bill made the case that “If we lose one or more of these plants we might as well forget about all the time and money we’ve invested in wind and solar. [...] The Legislature can save Pennsylvania consumers money, keep our nuclear power plants open and keep our air clean.”532 In contrast, the Natural Resources Defense Council (NRDC) condemned the draft bill as

…nothing more than a windfall for aging, uneconomical nuclear power plants. It fails to limit carbon pollution or advance commonsense energy policy that transitions Pennsylvania away from nuclear power and dirty fossil fuels to renewable sources and energy efficiency.533

Hearings began in April 2019, with both proponents and opponents contesting the benefits and detriments of the legislation.534 The state’s Public Utility Commission (PUC) has estimated that the legislation if adopted would cost ratepayers between US$459 and US$551 million a year in subsidies to FirstEnergy and Exelon.535 This estimate was on the basis that both TMI-1 and Beaver Valley would be operating, which will no longer be the case as Exelon Generation announced on 8 May 2019 that TMI-1 will permanently close by 30 September 2019.536 As of 1 July 2019, legislation had yet to be approved.

Fukushima Status Report


Eight years have passed since the Fukushima accident began in March 2011. Spent fuel removal in Unit 3 has started following significant delays and the investigation to locate fuel debris in Unit 2 was finally conducted, but with uncertain results. Although the evacuation order of a part of the evacuation zone was lifted again, only few residents have returned.

The assessment of health consequences remains controversial. Thyroid cancer in children continues to increase, with ongoing controversies over the causal relationship with the accident.

Other areas analyzed in this chapter are remaining food contamination, storage of contaminated water and the management of decontamination wastes that continue to accumulate.

Onsite Challenges

Current Status Reactors537

Water injection into all three units with fuel debris—Units 1, 2 and 3—has been continuing; the temperature of the lower part of the reactor pressure vessels and the containment ve