Table 2: Reactor Construction Times 2006–2016

Sources: IAEA-PRIS, MSC, 2016

Sources: MSC based on IAEA-PRIS, 2016

Construction Starts and Cancellations

The number of annual construction starts [32] in the world peaked in 1976 at 44, of which 11 projects were later abandoned. In 2010, there were 15 construction starts—including 10 in China alone—the highest level since 1985 (see Figure 10 and Figure 11). However, in 2014, the level had dropped to three units and China did not launch a single new project. Between 2012 and 1 July 2016, first concrete was poured for 28 new plants worldwide—less than in a single year in the 1970s. Over the decade 2006–2015, construction began for 79 reactors (of which one has been cancelled), that is more than twice as many as in the decade 1996–2005, when works started at 33 units (of which three have been abandoned). However, more than half (43) of these units are in China alone, and even the increased order rate remains much too low to make up for upcoming reactor closures.

Sources: IAEA-PRIS, MSC, 2016

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. French Atomic Energy Commission (CEA) statistics through 2002 indicate 253 “cancelled orders” in 31 countries, many of them at an advanced construction stage (see also Figure 12). The United States alone accounted for 138 of these order cancellations. [33]

Sources: IAEA-PRIS, MSC, 2016

Sources: IAEA-PRIS, MSC, 2016

Of the 754 reactor constructions launched since 1951, at least 92 units (12.2 percent) in 17 countries have been abandoned, of which 87, according to the IAEA, between 1977 and 2012—no earlier or later IAEA data available—at various stages after they had reached construction status.

Over three-quarters (71) of the cancellations happened during a 12-year period between 1982 and 1993, 11 were decided prior to this period, and only 10 over the 20-year period between 1993 and 2012.

Close to three quarters (67 units) of all cancelled projects were in four countries alone—the U.S. (40), Russia (15), 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.

There is no thorough analysis of the cumulated economic loss of these failed investments.

Operating Age

In the absence of any 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-2016 stands at 29 years, up from 28.8 a year ago (see Figure 13 and Figure 14). [34] 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 for an additional 20 years from the NRC.

As of June 2016, 81 of the 100 operating U.S. units have received an extension, with another 12 applications under NRC review. Since WNISR2015, seven license renewals (Davis-Besse, Sequoyah 1-2, Braidwood 1-2, Byron 1-2) have been granted and an additional one applied for (Waterford 3). [35]

Many other 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 31.4 years on average, and the oldest have started the process with the French Nuclear Safety Authority (ASN) evaluating each reactor before allowing a unit to operate for more than 30 years. Only few got have passed the procedure yet and the assessments are years behind schedule. They could then operate until they reach 40 years, which is the limit of their initial design age. The French utility Électricité de France (EDF) has clearly stated that, for economic reasons, it plans to prioritize lifetime extension beyond 40 years over large-scale new-build. Having assessed EDF’s lifetime extension projects, ASN Chairman Pierre-Franck Chevet stated during the presentation of the Annual Report 2015:

The continued operation of the nuclear power plants beyond 40 years cannot be taken for granted. The operating conditions for the nuclear power plants beyond 40 years is still a subject of some considerable debate. [36]

 Sources: IAEA-PRIS, MSC, 2016

However, only one of the 33 units that have been shut down in the U.S. had reached 40 years on the grid—Vermont Yankee, the latest one to be closed, in December 2014, at the age of 42. In other words, at least a quarter of the reactors connected to the grid in the U.S. never reached their initial design lifetime. On the other hand, of the 100 currently operating plants, 37 units have operated for more than 40 years. In other words, 46 percent of the units with license renewals have already entered the life extension period, and that share is growing rapidly with the mid-2016 average age of the U.S. operational fleet standing at 36.2 years (see United States Focus).

If ASN gave the go-ahead for all of the oldest units to operate for 40 years, 22 of the 58 French operating reactors would reach that age already by 2020.

In assessing the likelihood of reactors being able to operate for up to 60 years, it is useful to compare the age distribution of reactors that are currently operating with those that have already shut down (see Figure 13 and Figure 15). As of mid-2016, 59 of the world’s reactors have operated for 41 years and more. [37] As the age pyramid illustrates, that number could rapidly increase over the next few years. A total of 215 units have already exceeded age 30.

Sources: IAEA-PRIS, MSC, 2016

The age structure of the 164 units already shut down completes the picture. In total, 56 of these units operated for 30 years and more, and of those, 22 reactors operated for 40 years and more (see Figure 15). Many units of the first generation designs only operated for a few years. Considering that the average age of the 164 units that have already shut down is about 25 years, plans to extend the operational lifetime of large numbers of units to 40 years and far beyond seems rather optimistic. The operating time prior to shutdown has clearly increased continuously, as Figure 16 shows. But while the average annual age at shutdown got close to 40 years, it only passed that age once: in 2014, when the only such unit shut down that year (Vermont Yankee in the U.S.) after 42 years of operation.

As a result of the Fukushima nuclear disaster, more pressing 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 shutdown of seven reactors that had started up before 1981. These reactors, together with another unit that was closed at the time, 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.

Sources: IAEA-PRIS, MSC, 2016

Sources: IAEA-PRIS, MSC, 2016

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 LTO, as they are not considered operating). For the 59 reactors that have passed the 40-year lifetime, we assume they will operate to the end of their licensed operating time.

A second scenario (Plant Life Extension or PLEX Projection, see Figure 18) takes into account all already-authorized lifetime extensions.

The lifetime projections allow for an evaluation of the number of plants and respective power generating capacity that would have to come on line over the next decades to offset closures and simply maintain the same number of operating plants and capacity. Even with all units under construction assumed to have gone online by 2021, an installation rate of about 10.5 per year—installed nuclear capacity would drop by 1.7 GW by 2020, which is marginal. However, in total, 22 additional reactors (compared to the end of 2015 status) would have to be ordered, built and started up prior to the end of 2020 in order to maintain the status quo of the number of operating units. This corresponds to about four additional grid connections per year and would raise the annual startups to about 15. This installation rate would be three times as high as the actual 46 grid connections over the decade 2006–July 2016. In fact, considering even the lowest average construction times, 17 of these 22 units (5 have come on-line in the first half of 2016) would have to be launched over the coming year and be completed without delay.

Sources: IAEA-PRIS, WNA, various sources compiled by MSC 2016

In the following decade to 2030, 187 new reactors (175 GW) would have to be connected to the grid to maintain the status quo, four times the rate achieved over the past decade.

The achievement of the 2020 targets will mainly depend on the number of Japanese reactors currently in LTO possibly coming back on line and the development pattern of the Chinese construction program. Any major achievements outside these two countries in the given timeframe are highly unlikely given the existing difficult financial situation of the world’s main reactor builders and utilities, the general economic environment, the decline of power consumption in many countries, widespread skepticism in the financial community, and generally hostile public opinion—aside from any other specific post-Fukushima effects.

Sources: IAEA-PRIS, WNA, various sources compiled by MSC 2016

Sources: IAEA-PRIS, US-NRC, MSC 2016

As a result, the number of reactors in operation will stagnate at best but will more likely decline over the coming years unless lifetime extensions beyond 40 years become widespread. Such generalized lifetime extensions are, however, even less likely after Fukushima.

Also, soaring maintenance and upgrading costs, as well as decreasing system costs of nuclear power’s main competitors, create an economic environment with sharply decreasing bulk electricity prices that leads to the situation of an increasing number of nuclear plants “at risk” of early closures, notably in the U.S., Sweden and Germany, as discussed below.

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 freeze of construction initiation for almost two years and new siting authorizations for four years has reduced Chinese ambitions.

In addition, the average construction time for the 25 units started up in China over the past decade was 5.7 years. At present, 21 units with about 21.5 GW are under construction and scheduled to be connected by 2020, which would bring the total to 51 GW, far short of the current 58 GW target (see China Focus). The continuing controversy about whether new reactors should be allowed not only at coastal but also inland sites, is restricting the number of suitable sites immediately available.

As usual, we have also modeled 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 shutdown date has been announced. By 2020, the net number of operating reactors would have increased by only two (down from an increase of eight in the WNISR2014 projection) and the installed capacity would grow by 17 GW (down from an increase of 25 GW in the WNISR2014 projection). This decline reflects the recent early closure announcements of units that, for economic reasons, will not operate up to the end of their licensed operational lifetime. A continuation of this trend can be expected over the coming years.

In the following decade to 2030, still 163 new reactors (144.5 GW) would have to start up to replace shutdowns. In other words, the overall pattern of decline would hardly be altered: it would merely be delayed by some years (see Figure 17, Figure 18 and the cumulated effect in Figure 19).

Potential Newcomer Countries

At time of the signing of the Kyoto Protocol, in 1997, the installed capacity of nuclear power in the world was 344 GW, and by the time of the signing of the Paris agreement, at the end of 2015, this had risen to 378 GW (including 35.5 in LTO). This equates to a 10 percent increase in capacity with an associated increase in electricity production of 178TWh per year, an approximately 8 percent increase in output. However, due to rising global demand over the same time period nuclear contribution to global commercial electricity generation has fallen from 17.5 percent to below 11 percent. Therefore, despite the promotion of nuclear power as a technology to address climate change over the past two decades its contribution is diminishing.

If nuclear is to make a difference on the global level, it will need to revise this trend and significantly increase its production both within its current markets and expand into new countries.

The IAEA says that, “seven countries have moved forward in actively developing nuclear programs and two countries (Belarus and the United Arab Emirates (UAE)) have already started constructing their first NPP [Nuclear Power Plant].” [38] The source of this statement is not original IAEA research, but the World Nuclear Association (WNA), whose aim is to promote and represent the nuclear industry. WNA places the seven countries cited by the IAEA in two categories  [39]:

• Contracts signed, legal and regulatory infrastructure well-developed or developing: Bangladesh, Lithuania, Turkey and Vietnam;
• Committed plans, legal and regulatory infrastructure developing: Jordan, Poland and Egypt.

WNA, also claims that there are an additional 11 countries in which nuclear power is planned, which includes, those with “well-developed plans”, Chile, Indonesia, Kazakhstan, Thailand and Saudi Arabia and those “developing plans” including, Israel, Kenya, Laos, Malaysia, Morocco, and Nigeria. They further list another 20 countries in which nuclear is a “serious policy option”. [40] The following section reviews the development of nuclear power in those countries in which WNA believes that there are at least “well-developed plans” for new nuclear. Table 3 provides an overview per category and country.

Under Construction

Construction started in November 2013 at Belarus’s first nuclear reactor at the Ostrovets power plant, also called Belarusian-1. Construction of a second 1200 MWe AES-2006 reactor started in June 2014. In November 2011, the two governments agreed that Russia would lend up to US$10 billion for 25 years to finance 90 percent of the contract between Atomstroyexport and the Belarus Directorate for Nuclear Power Plant Construction. In July 2012, the contract was signed for the construction of the two reactors for an estimated cost of US$10 billion, including US$3 billion for new infrastructure to accommodate the remoteness of Ostrovets in northern Belarus. [41] The project assumes the supply of all fuel and repatriation of spent fuel for the life of the plant. The fuel is to be reprocessed and the separated wastes returned to Belarus. In August 2011, the Ministry of Natural Resources and Environmental Protection of Belarus stated that the first unit would be commissioned in 2016 and the second one in 2018. [42] However, these dates were revised, and when construction started, it was stated that the reactors will not be completed until 2018 and 2020. [43] In May 2016, the startup months were reported as November 2018 and July 2020 respectively. [44] As of April 2016, the two units were said by deputy energy minister Mikhail Mikhadyuk to be 38 percent complete. [45]

In March 2015, Atomstroyexport admitted the plant would cost over 1,400 billion roubles compared to the forecast from 2014 of 840 billion Rubles. However, the falling price of the rouble against the dollar will significantly affect the dollar price of the project.

The project is the focus of international opposition and criticism, with formal complaints from the Lithuanian government. [46] Belarus has been found to be in non-compliance with some of its obligations concerning the construction of the plant, according to the meeting of the Parties of the Espoo Convention. [47] The extent of international opposition to the project was reported in Nuclear Intelligence Weekly, where it said that during the IAEA’s general conference, “a slick presentation from the major government players in the Belarussian nuclear program did little to impress international experts and diplomats.” [48] The trade journal also reported domestic criticism of the project on the grounds of the signing of contracts with a Russian company of poor reputation and that no detailed economic justification of the plant had been presented.

While Belarus is currently a net importer of electricity—in 2015 it received 3.6 TWh from Russia and Ukraine, a fall from 3.8 TWh the previous year. [49] When generating, both nuclear units could produce at least double this amount, so domestic power plants will have to be closed, or output restricted, or consumption or power exports increased. This latter option, which would also bring important revenue to Belarus, may not be possible as the Lithuanian Government is seeking to ban electricity imports from the Belarus nuclear power plant due to its safety concerns over the reactor.

In the United Arab Emirates (UAE), construction is ongoing at the Barakah nuclear project, 300 km west of Abu Dhabi, where there are four reactors under construction. At the time of the contract signing in December 2009, with Korean Electric Power Corp., the Emirates Nuclear Energy Corp (ENEC), said that “the contract for the construction, commissioning and fuel loads for four units equaled approximately US$20 billion, with a high percentage of the contract being offered under a fixed-price arrangement”. [50]

The original financing plan for the project was thought to include US$10 billion from the Export-Import Bank of Korea, US$2 billion from the Ex-Im Bank of the U.S., US$6 billion from the government of Abu Dhabi, and US$2 billion from commercial banks. [51] However, it is unclear what other financing sources have been used for the project, and it is reported that the cost of the project has risen significantly, with the total cost of the plant including infrastructure and finance now expected to be about US$32 billion, [52] with others putting the cost of the contracts at US$40 billion, including fuel management and operation, [53] although little independent information is available.

In July 2010, a site-preparation license and a limited construction license were granted for four reactors at Barakah, 53 kilometers from Ruwais. [54] A tentative schedule published in late December 2010, and not publicly altered since, suggests that Barakah-1 will start commercial operation in May 2017 with unit 2 operating from 2018, unit 3 in 2019, and unit 4 in 2020. Construction of Barakah-1 officially started on 19 July 2012, of Barakah-2 on 28 May 2013, on Barakah-3 on 24 September 2014 and unit 4 on 30 July 2015.  [55] In May 2016, ENEC stated that Barakah-1 is about 87 percent complete, unit 2 is at 68 percent, unit 3 at 47 percent and unit 4 at 29 percent. [56]

All official sources indicate that the unit 1 will be completed and start operating next year. If this occurs, it will be a remarkable achievement for a country to complete their first new commercial scale nuclear reactor on time although the extent of conformity with the existing budget is unknown. No independent assessment of quality-control conditions—a key driver of construction delays in most countries—is available.

Contracts Signed or in Advanced Development

In November 2011, the Bangladesh Government’s press information department said that it was prepared to sign a deal with the Russian Government for two 1000 MW units to be built by 2018 at a cost of US$2 billion.  [57] Since then, although negotiations have reportedly been ongoing, the start-up date has been continually postponed and the expected construction cost has risen.

In January 2013, Deputy Finance Minister of Russia Sergey Storchak and Economic Relations Division (ERD) Secretary of Bangladesh Abul Kalam Azad signed the agreement on the Extension of State Export Credit for financing the preparatory stage work for the nuclear power plant at Rooppur (or Ruppur). [58] The site was chosen as early as in the 1960s, when the country was part of Pakistan, on the banks of the largest river in the country; over the decades, the river has shifted from its original trajectory and new land had to be acquired in the last year. [59] The deal was only for US$500 million [60] to cover the site preparatory work. [61] In October 2013, a ceremony was held for the formal start of the preparatory stage, [62] with formal construction then expected to begin in 2015. At the time of the ceremony, the cost of construction was revised upwards and it was suggested that each unit would cost US$1.5–2 billion. [63] These cost estimates tripled in April 2014, when a senior official at the Ministry of Science and Technology was quoted as suggesting the price was more likely to be US$6 billion. [64] In 2015, the Bangladeshi Finance Minister was quoted as saying the project was now expected to cost US$13.5 billion. [65] However, even this is not likely to be the final cost with suggestions that this is not a fixed price contract, but a “cost-plus-fee” contract, and “the vendor has the right to come up with any cost escalation (plus their profit margin) to be incorporated into the contract amount” and that the eventual cost of generating power would be “at least 60 percent higher than the present retail cost” of electricity in Bangladesh. [66]

Over the past year, the design selected for construction has also changed. Earlier, the plan was to construct two VVER-1000 units but in 2015, the Bangladesh government reportedly became interested in the VVER-1200 design during “a high-level meeting in Vietnam”. [67] In December 2015, an agreement was said to be signed between the Bangladesh Atomic Energy Commission and Rosatom for 2.4 GW of capacity, with work expected to begin in 2016 and operation to start in 2022 and 2023. [68] According to the deal, Russia would provide 90 percent of the funds on credit at an interest rate of Libor plus 1.75 percent. Bangladesh will have to pay back the loan in 28 years with a 10-year grace period. As in other countries, Russia has offered to take back the spent fuel. However, four months later, the project was delayed again, this time with a scheduled construction start on 1 August 2017. By April 2016, site preparation was reportedly 80 percent complete. [69] However, in late June 2016, a “siting licence ceremony” was held in Dhaka allowing for “preliminary site works”. [70] The obvious contradiction between the two pieces of information could not be cleared up.

In late May 2016, negotiations were concluded over the US$12.65 billion project, with Russia making available US$11.385 billion, with a final agreement expected to be signed “within two months”. [71] By the end of June 2016, Bangladesh's cabinet had approved a draft of the agreement and a signature was expected in “July or August”. [72]

The deal has been criticized by many in the media. One concern has been that the project will result in a major debt burden. In October 2015, Bangladesh’s Finance Minister Abul Muhith, was quoted as saying that the “country’s debt burden is now US$18 billion, which will go up to US$30 billion after five years at the current pace of external borrowing. The amount would reach US$42 billion if the Russian loan is added to it”. [73]

Lithuania had two large RBMK (Chernobyl-type) reactors at Ignalina, which were shut down in 2004 and 2009, a requirement for joining the European Union. Since then there have been ongoing attempts to build a replacement, either unilaterally or with neighboring countries. The most recent proposal was confirmed in 2012 when the Government, along with its partners in Estonia and  Latvia, chose Hitachi together with its Hitachi-GE Nuclear Energy Ltd. unit as a strategic investor and technology supplier to construct a nuclear plant by the end of 2020. [74] In May 2012, the percentage breakdown of the initially US$6.5 billion project was announced with a 20 percent ownership for Hitachi, and 38 percent for Lithuania, while Estonia would take 22 percent and Latvia 20 percent. [75]

However, in October 2012 a consultative national referendum on the future of nuclear power was held and 63 percent voted against new nuclear construction, with sufficient turnout to validate the result.  [76] Prior to his appointment as Prime Minister, Algirdas Butkevicius stated that legislation prohibiting the project would be submitted once the new parliament convenes and that “the people expressed their wish in the referendum, and I will follow the people’s will”. [77] In January 2013, the Minister set up a Working Group on the energy development in the country, which concluded in April 2013 that the development of the nuclear new-build project could be continued under the condition of the involvement of regional partners, the availability of a strategic investor and “the use of the most modern and practically tested nuclear technology”. [78]

In March 2014, in response to the political situation in Ukraine and growing concerns over energy security, the seven parties represented in the Lithuanian Parliament signed an agreement on strategic priorities through 2020. This included the construction of a liquefied natural gas (LNG) plant, the synchronization of the grid with other EU countries, and that the nuclear project to be implemented “in accordance with the terms and conditions of financing and participation improved in cooperation with partners”. [79] In July 2014 the Lithuania Energy Ministry and Hitachi signed an agreement to set up a joint venture for the construction of the Visaginas nuclear power plant.

Little progress was made in signing agreements with other international partners and in December 2015, Lithuanian press announced that the staff in the preparation company VAE SPB was reduced from 13 to 4 people.  [80] In early 2016, the Energy Minister of Lithuania, Rokas Masiulis, said that the project had been shelved indefinitely, due to unfavorable market conditions.  [81]

In Turkey, up to three projects are being developed, but rather than proceeding with a single builder and design, the Government has decided to undertake at least three different reactor designs and three different sets of financial sources. Analysts have pointed out that the “regulatory framework for nuclear energy in Turkey has severe shortcomings”. [82]

Akkuyu

The first project, on the southern coast, is at Akkuyu, which is to be built under a Build-Own-Operate- (BOO) model by Rosatom of Russia. An agreement was signed in May 2010 for four VVER1200 reactors, with construction originally expected to start in 2015, but now delayed until at least 2016, and to cost US$20–25 billion for 4.8 GW. At the heart of the project is a 15-year Power Purchase Agreement (PPA), which includes 70 percent of the electricity produced from units 1 and 2 and 30 percent of units 3 and 4. Therefore 50 percent of the total power from the station is to be sold at a guaranteed price for the first 15 years, with the rest to be sold on the market, where the average industrial price was 24.4 kurus/kWh ($US 0.08/kWh) in 2015. [83]

The CEO of Akkuyu JSC (the project company set up by Russia’s Rosatom) Alexander Superfin, said in October 2013 that the project was going to be operational by mid-2020. [84] However, further delays have occurred as there were problems with Akkuyu JSC's Environmental Impact Assessment, which was rejected by the Ministry of Environment, when it was submitted in July 2013. When it was eventually approved in December 2014, it was said that the commissioning of the first unit was likely to be in 2021. [85] In January 2015, both the Chamber of Turkish Engineers and Architects (TMMOB) [86] and Greenpeace started legal proceedings against the approval, claiming that the Agency had insufficient qualified staff to make the decision and that there were no clear waste management plans or nuclear liability arrangements.  [87] As a result of these domestic developments and financing problems, it was reported in November 2015 that the operation would now occur only in 2022 [88] and at an estimated budget for the two units of US$22 billion. [89] Site preparation work started in April 2015  [90] and it was estimated that US$3 billion had been spent as of autumn 2015.  [91] In January 2016, Akkuyu Nuclear submitted to the Atomic Energy Authority its final site parameter report, which must be approved before a construction license can be granted.  [92] There are suggestions that Rosatom may sell a 49 percent of its stake to one of Turkey’s leading construction conglomerates, Cengiz Insaat, and that this is part of a political maneuver to keep the deal alive given the souring of relations between Russia and Turkey. [93] This claim was widely published in the Turkish media but denied by Rosatom. [94] It was also reported in October 2015 that Turkish President Recep Tayyip Erdogan warned Russia risked losing the Akkuyu deal as a result of Russian intervention in Syria. [95] In June 2016, Russia’s permanent representative to the IAEA said that work on Akkuyu “is likely to resume following the rapprochement between the two countries”, which evidently indicates that work is suspended as of the time of the statement. [96]

Sinop

Another proposed project is at Sinop, on the northern coast, where the latest project proposal is for 4.4 GW using the ATMEA reactor design. If completed this would be the first reactor of this design, jointly developed by Mitsubishi and AREVA. [97] In April 2015, Turkish President Erdogan approved parliament’s ratification of the intergovernmental agreement with Japan. [98]

The estimated cost of the project is US$22 billion and involves a consortium of Mitsubishi, AREVA, GDF-Suez (now known as Engie), and Itochu, who between them will own 51 percent of the project, with the remaining 49 percent owned by Turkish companies including the State-owned electricity generating company (EÜAS). [99] The ongoing problems with the financial viability of AREVA will affect its ability to invest in the project. Construction is currently expected to start in 2017. However, an Environmental Impact Assessment, which could take up to two years, is still outstanding. [100]

The project is complicated by the region’s lack of large-scale demand and the existing coal power stations, so 1,400 km of transmission lines will be needed to take the electricity to Istanbul and Ankara. Reports at the end of 2014 suggested that the project would be further delayed, by up to two years—the fourth delay in two years. This has led to extreme frustration with the bidders, with one company representative saying of the process: “They’re basically at the point where no one believes them anymore.” [101]

İğneada

In October in 2015, the government suggested that it was aiming to build a third power plant, at the İğneada site. The most likely bidders for the project are said to be Westinghouse and the Chinese State Nuclear Power Technology Corporation (SNPTC), with Chinese companies “aggressively” pursuing the contract, said to be worth US$22-25 billion. [102] The Daily Sabah newspaper noted that “the İğneada district is located some 10 kilometers south of Turkey’s border with Bulgaria and famous for its natural beauty and beach, which is likely to raise questions as to its environmental impact. [103] Additional doubts have been raised by the Deputy Undersecretary for the Turkish Ministry of Energy and National Resources, who stated that “having three different projects with three different technologies is not sound.” [104]

A decision by the Prime Minster of Vietnam of July2011 stated that by 2020 the first nuclear power plant will be in operation, with a further 7 GW of capacity to be in operation by 2025 and total of 10.7 GW in operation by 2030. The previous October Vietnam had signed an intergovernmental agreement with Russia’s Atomstroyexport to build the Ninh Thuan-1 nuclear power plant, using 1200 MW VVER reactors. Construction was slated to begin in 2014, with the turnkey project being owned and operated by the state utility Electricity of Vietnam (EVN). However, numerous delays have occurred and in December 2015, Atomic Energy Agency Director-General Hoang Anh Tuan that construction would start in 2020, a six-year delay of the original plan. [105] “The national electricity development plan, approved by the government in March 2016, envisioned the “first nuclear power plant put into operation in 2028”. [106]

Rosatom has confirmed that Russia’s Ministry of Finance is prepared to finance at least 85 percent of this first plant, and that Russia will supply the new fuel and take back spent fuel for the life of the plant. An agreement for up to US$9 billion finance was signed in November 2011 with the Russian government’s state export credit bureau, and a second US$0.5 billion agreement covered the establishment of a nuclear science and technology center.

Like Turkey, Vietnam has also signed an intergovernmental agreement with Japan for the construction of a second nuclear power plant, with two reactors projected to come on line in 2024–25. The agreement calls for assistance in conducting feasibility studies for the project, low-interest and preferential loans, technology transfer and training of human resources, and cooperation in the waste treatment and stable supply of materials for the whole life of the project.

The delay in the ordering of the new nuclear units is not of concern due to a slower than expected increase in electricity demand, according to the Director General of the Atomic Energy Agency. However, other analysts have suggested that the slowdown in demand has given Vietnam a reason to abandon its nuclear development program altogether. Nguyen Khac Nhan, who formerly taught nuclear engineering at the Grenoble Institute of Technology in France and who has advised French state utility EDF for three decades, stated in 2015: “The nuclear power projects will most certainly be stopped.” [107]

“Committed Plans”

In Egypt, the government’s Nuclear Power Plants Authority was established in the mid-1970s, and plans were developed for 10 reactors by the end of the century. Despite discussions with Chinese, French, German, and Russian suppliers, little development occurred for several decades. In October 2006, the Minister for Energy announced that a 1000 MW reactor would be built, but this was later expanded to four reactors by 2025, with the first one coming on line in 2019. In early 2010, a legal framework was adopted to regulate and establish nuclear facilities; however, an international bidding process for the construction was postponed in February 2011 due to the political situation. Since then, there have been various attempts and reports that a tender process would be restarted, all of which have come to nothing. But Russia’s Rosatom determinedly pursued its strategy of pushing “through a series of bilateral agreements, with each one more detailed than the previous” so that “a commercial contract is ultimately inevitable”. [108] As a result, in February 2015, Rosatom and Egypt’s Nuclear Power Plant Authority signed an agreement that could lead to the construction and financing of two reactors and possibly two additional ones. However, Rosatom highlighted the “need to prepare for signing two intergovernmental agreements—one on nuclear power plant construction and one on financing”. [109]

In November 2015, an intergovernmental agreement was signed for the construction of four VVER-1200 reactors at Dabaa. The deal, was apparently worth €20-22 billion with Russia providing up to 90 percent of the finance, [110] to be paid back through the sale of electricity. Reports suggest that a spokesman for Rosatom said the first plant could be completed by 2022 [111], which is technically impossible, given that construction, if at all, would not start for another two years. In May 2016, it was announced that Egypt concluded a US$25 billion loan with Russia for nuclear construction.  [112] According to the Egyptian official journal, the loan is to cover 85 percent of the project cost, with the total investment thus estimated at around US$29.4 billion. The 3 percent -annual-interest loan is to be paid back over 22 years starting in 2029. [113]

Influential policy makers in Jordan have long desired the acquisition of a nuclear power plant. In 2007, the government established the Jordan Atomic Energy Commission (JAEC) and the Jordan Nuclear Regulatory Commission. JAEC started conducting a feasibility study on nuclear power, including a comparative cost/benefit analysis. [114] In November 2009, JAEC awarded an US$11.3 million contract to Australian engineering company WorleyParsons for pre-construction consulting for Jordan’s first nuclear power plant. [115] WorleyParsons was “to evaluate the nuclear power plant technology most suitable for Jordan (…) conduct a feasibility study and financial assessment of the project, as well as assist in [issuing] the tender for the plant vendor”.  [116] In Jordanian energy plans from that period, the timeline assumed for starting nuclear power production was as early as 2015. [117]

JAEC and WorleyParsons narrowed down the choices to the ATMEA-1 design from AREVA and Mitsubishi (as projected in Turkey); the Enhanced Candu-6 (EC6) from Atomic Energy of Canada Limited; the APR-1400 [118] from Korea Electric Power Corporation, and the AES-2006 and AES-92 variants of the VVER design from Rosatom. [119] Eventually, the ability of Rosatom to potentially finance, as well as its offer to take back spent fuel to Russia, [120] seems to have trumped all other considerations and Jordan decided on two VVER light water reactors. According to the initial announcement, Russia was to finance 49.9 percent of the nuclear power plant. [121] In September 2014, JAEC and Rosatom signed a two-year development framework for a project, which was projected to cost under US$10 billion and generate electricity costing US$0.10/kWh. It is now envisaged the earliest that construction start would be 2019, [122] which would make completion by the original objective of 2021 [123] impossible and even the revised dates of 2023 highly unlikely.

This financing arrangement is being revised because JAEC is finding it very hard to come up with its part of cost of the reactor. This was suggested by JAEC Chairman Khaled Toukan who told Associated Press that the probability of the two reactors being built is “70 to 75 (percent) ... it is not 90 percent” in a recent interview. [124] Earlier, in October 2015, Toukan told the press that JAEC is “now in trilateral discussions and seeking strategic partners—technology providers as well as finance partners”. [125] Among the partners mentioned by Toukan are the China National Nuclear Corporation (CNNC), which is being approached to take on a potential equity stake, as well as participation in the construction phase for the turbine islands and other aspects of the plant, the Industrial and Commercial Bank of China, which is being approached for non-equity financing, and Rolls-Royce about potentially providing cooling systems for the plant. [126] JAEC’s current preference is for the equity stake in the project divided three ways with Rosatom and CNNC, and Jordan itself taking the last third. Elsewhere, Toukan has suggested that China might fund an even higher share, “not less than 50 percent”, according to one report. [127] For the JAEC part, Toukan has set up the Jordan Nuclear Power Co., which is to raise funds on the trading market by selling shares. [128] One reason that this arrangement might be attractive to Rosatom is uncertainty about its own finances. Over the past year, its budget has been cut and the Russian government was reportedly considering “suspending loans to other countries”. [129] But in the meanwhile, JAEC and Rosatom have signed a cooperation agreement on nuclear safety. [130]

There is opposition in Jordan's parliament and local opposition is building up at the pre-selected Al Amra site. On 30 May 2012, the Jordanian parliament approved a recommendation to shelve the program, as it was said it would “drive the country into a dark tunnel and will bring about an adverse and irreversible environmental impact”. The parliament also recommended suspending uranium exploration until a feasibility study is done. [131] Prior to the vote, the Parliament’s Energy Committee had published a report accusing the JAEC of deliberately “misleading” the public and officials over the program by “hiding facts” related to costs. [132] The JAEC responded by saying it wouldn’t be able to produce a full evaluation until the start of construction of the plant. [133] At least one member of the royal family, Princess Basma bint Ali, has publicly spoken out against the nuclear program. [134]

Local opposition comes in particular from members of the Beni Sakher tribe that lives around the Al Amra area. [135] One member of the tribe, Hind Fayez, is a prominent parliamentarian and a noted opponent. [136] She is quoted as saying: “I will not allow the construction of the nuclear reactor, not even over my dead body (…). The Bani Sakher tribe also rejects the construction of the nuclear reactor in Qusayr Amra”. [137] A particular concern is water requirements for the reactor, which is to come from the Al-Samra Waste Water Treatment Plant in nearby Irbid. [138] If and when the reactor is commissioned, over 20 percent of the total capacity of the Treatment Plant will be used to supply water to the reactors. The output of the Treatment Plant is currently being used for irrigation; [139] diversion of water to the reactor is, naturally, of public concern. The treatment of wastewater will also add to the already high costs of generating nuclear power. [140] It has been suggested that “it may well be water, the Middle East’s most precious resource, rather than fiscal issues that shoves the country’s nuclear hopes farther into the future”. [141]

Poland planned the development of a series of nuclear power stations in the 1980s and started construction of two VVER1000/320 reactors in _arnowiec on the Baltic coast, but both construction and further plans were halted following the Chernobyl accident. In 2008, however, Poland announced that it was going to re-enter the nuclear arena and in November 2010, the Ministry of Economy put forward a Nuclear Energy Program. On 28 January 2014, the Polish Government adopted a document with the title “Polish Nuclear Power Programme” outlining the framework of the plan. [142] The Progamme was subject to a Strategic Environmental Assessment (SEA), which was also approved in January 2014. In April 2014, Greenpeace started legal procedures against the Assessment, alleging its public participation process was inadequate. The SEA drew around 60,000 submissions, a majority coming from neighboring Germany. The plan includes proposals to build 6 GW of nuclear power with the first reactor starting up by 2024. The reactor types under consideration include AREVA’s EPR, Westinghouse’s AP1000, and Hitachi/GE’s ABWR (Advanced Boiling Water Reactor).

In January 2013, the Polish utility PGE (Polska Grupa Energetyczna) selected WorleyParsons to conduct a five-year, US$81.5 million study, on the siting and development of a nuclear power plant with a capacity of up to 3 GW. [143] At that time, the project was estimated at US$13–19 billion, site selection was to have been completed by 2016, and construction was to begin in 2019. [144] A number of vendors, including AREVA, Westinghouse, and GE-Hitachi, all lobbied Warsaw aggressively. [145] PGE formed a project company PGE EJ1, which also has a ten percent participation each of the other large Polish utilities, Tauron Polska Energia and Enea, as well as the state copper-mining firm KGHM. In January 2014, PGE EJ1 received four bids from companies looking to become the company’s “Owner’s Engineer” to help in the tendering and development of the project, which was eventually awarded to AMEC Nuclear UK in July 2014. The timetable demanded that PGE make a final investment decision on the two plants by early 2017.  [146] Final design and permits for the first plant were expected to be ready in 2018, allowing construction start in 2020 and commercial operation in 2025. That schedule has slipped to commercial operation beginning in 2030-31. [147]

However, in April 2014, it was reported that PGE had cancelled its contract with WorleyParsons to research potential sites. It was thought that this would delay the process by at least two years, with the Supreme Audit Office suggesting that there was a high risk of further delays or that the plant wouldn’t be completed at all. [148] An independent critical assessment stated in late May 2015: “At this point, it is central to highlight that neither the Polish administration, nor PGE have announced so far any realistic or even detailed financing plan for the NPPs’ scheme.” [149] Furthermore, coal, and in particular supporting coal miners, remains a political priority. [150]

In December 2015, the Polish General Directorate for the Environment (GDOS) started the scoping phase for the Environmental Impact Assessment for the first Polish nuclear power station with a notification to states within 1,000 km from the proposed three sites. Directly after the start of this scoping phase, PGE EJ1 informed GDOS that it was withdrawing one of the three proposed sites, at Choczewo, because of the potential impacts on protected nature areas. [151] In January 2016, Poland’s newly formed government further slowed down nuclear plans with the head of the Energy Ministry admitting that the 2020 target for commissioning a first unit was no longer viable. [152]

“Well Developed Plans”

There seems little to indicate that Chile is actively developing nuclear power. The World Nuclear Agency (WNA) stated that in 2010 the Energy Minister had said that the first nuclear plant of 1100 MWe should be operating in 2024, joined by three more by 2035 and that a public-private partnership is proposed to build the first plant, with a tender to be called in 2016. [153] However, plans have not developed significantly since then. Public opinion in Chile turned strongly against nuclear power after the Fukushima accident and a poll conducted in April 2011 showed that around 84 percent of those surveyed were against the development of a nuclear power program in Chile, with only 12 percent in support. [154]

According to the Chilean Nuclear Energy Commission, they continue to evaluate the feasibility of building a nuclear power plant although a “political decision has been postponed”. [155] At the same time, in January 2016, President Michelle Bachelet signed a new energy strategy that sets a goal of renewable energy providing 70 percent of the country’s power needs by 2050. [156] Over the past five years, solar capacity has quadrupled to 770 MW.  [157]

Since the mid-1970s, Indonesia has discussed and brought forward plans to develop nuclear power, releasing its first study on the introduction of nuclear power, supported by the Italian government, in 1976. The analysis was updated in the mid-1980s with help from the IAEA, the United States, France and Italy. Numerous discussions took place over the following decade, and by 1997 a Nuclear Energy Law was adopted that gave guidance on construction, operation, and decommissioning. A decade later, the 2007 Law on National Long-Term Development Planning for 2005–25 stipulated that between 2015 and 2019, four units should be completed with an installed capacity of 6 GW. [158] In July 2007 Korea Electric Power Corp. (KEPCO) and Korea Hydro & Nuclear Power Co. (KHNP) signed a memorandum of understanding with Indonesia’s PT Medco Energi Internasional to undertake a feasibility study for building two OPR-1000 units at a cost of US$3 billion. The OPR-1000 is a Generation II 1000 MW PWR, developed jointly by KEPCO and KHNP. However, the actual construction plans are much more modest and envisage the construction of a 10 MW reactor in the Serpong area, to be operational in 2021  [159], with a tender to prepare blueprints won by Rosatom in April 2015. As with a large number of countries, there have been reports of ongoing co-operation with Russia, including with proposals for the sale of floating reactors.  [160] There is also talk about “on-land” reactors, with “breaking of ground” to start in 2024/5. [161]

Then in December 2015, the Indonesian government pulled the plug on all nuclear plans, even for the longer term future. Energy and Mineral Resources Minister Sudirman Said stated: “We have arrived at the conclusion that this is not the time to build up nuclear power capacity. We still have many alternatives and we do not need to raise any controversies.” The Minister made that statement after the National Energy Council, a presidential advisory body, completed its latest National Energy Plan. Nuclear Engineering International comments: “This effectively cancels a previous [US]$8bn plan to operate four nuclear plants with a total capacity of 6 GWe by 2025.” [162] Indonesia plans to achieve an ambitious build-up of electricity generating capacity—from currently less than 50 GW to 137 GW by 2025 and 430 GW by 2050—without nuclear power. Planning documents and Indonesian officials consider nuclear power to be merely a “last resort” option.

Kazakhstan is the world’s largest producer of uranium, with 40 percent of the global total. It had a small fast breeder reactor, BN 350, which operated at Aktau, between 1972-1999. A number of countries, including Russia, Japan, South Korea, and China have all signed co-operation deals for the development of nuclear power. In 2014, President Nursultan Nazarbayev, used his State of the Nation address to highlight the need to develop nuclear power. Since then, negotiations have continued, particularly with Toshiba-Westinghouse of Japan and Rosatom of Russia, with an intergovernmental agreement expected by some in 2016. [163] However, others are less positive about the timetable and, in October 2015, the Vice Minister of Energy Bakhytzhan Dzhaksaliyev said that finding a suitable site and strategic partner might take two to three years.  [164] In December 2015, a draft Atomic Energy Law was referred to the Senate, in order to address licensing, security, environmental protection rules and standards. [165] An April 2016 joint declaration by the energy ministers of Kazakhstan and the U.S. notes that the 2016 work plan “encourages the use of alternative energy sources in Kazakhstan, reduces emissions, and enhances nuclear safety”. [166]

The National Energy Policy Council of Thailand in 2007 proposed that up to 5 GW of capacity be operational between 2020 and 2028. However, this target will not be met for a number of reasons, importantly local opposition on the proposed sites. The latest proposal from the Electricity Generating Authority of Thailand (EGAT) is for two 1 GW units to be operational by 2036, although no location has been named. [167] Thailand’s largest private power company has announced that it will invest US$200 million for a 10 percent stake of the China General Nuclear Corporation (CGN) and Guangxi Investment Group’s Fangchenggang nuclear power plant in China. [168] CGN obviously eyes a role in the potential 2 GW nuclear project in Thailand. However, as Nuclear Intelligence Weekly (NIW) puts it, “in the near term CGN may have to content itself first with renewable opportunities in the region”. [169]

In 2012, the IAEA suggested that in 2013 the Kingdom of Saudi Arabia might start building its first nuclear reactor. [170] This confident prediction was based on the fact that in April 2010 a royal decree said: “The development of atomic energy is essential to meet the Kingdom’s growing requirements for energy to generate electricity, produce desalinated water and reduce reliance on depleting hydro-carbon resources.” [171] The King Abdullah City for Atomic and Renewable Energy (KA-CARE) was set up in Riyadh to advance this agenda, and in June 2011, the coordinator of scientific collaboration at KA-CARE announced plans to construct 16 nuclear power reactors over the next 20 years at a cost of more than 300 billion riyals (US$80 billion). The first two reactors were planned to be online in ten years and then two more per year until 2030. However, the KA-CARE nuclear proposal has still not been approved by the country’s top economic board, then headed by the late King Abdullah, and in March 2013, it was reported that a KA-CARE official has said that a tender is now unlikely for seven or eight years. In November 2013, it was nonetheless suggested that the project would be put back on track faster than this, with a suggestion that KA-CARE could bring forward proposals for new-build in 2015. [172]

Hashim Yamani, president of the King Abdullah City for Atomic and Renewable Energy has said: “Recently, however, we have revised the outlook together with our stakeholders to focus on 2040 as the major milestone for long-term energy planning in Saudi Arabia.” [173] No reason was given for the delay or when the first nuclear and solar plants would be operational. The falling oil price and subsequent drop in Government revenues is likely to delay or curtail capital intensive project, such as nuclear.

During 2015, new co-operation agreements were signed with France, Russia, China and South Korea. The last seemed to be the most advanced and includes proposals for the building of two SMART small modular reactors and ongoing research and collaboration. [174]

Conclusion on Potential Newcomer Countries

Historically, the expansion of nuclear power into new countries is extremely slow; in the last two decades only two countries, Romania (1996) and Iran (2011), started power reactors for the first time, while over the same time period two countries, Kazakhstan and Lithuania, closed theirs. In the next few years, two countries are expected to start generating electricity from nuclear reactors for the first time, but their experiences are extremely different. On the one hand is the UAE, which if it starts the first unit at the Barakah nuclear power plant next year, will be a remarkable achievement, as it will be completed on time. In Belarus, at the Ostrovets site, project costs seem to have risen, and officially the construction phase is on schedule, but without any independent verification, there is considerable skepticism over the validity of the claim. As the summary table shows in all of the emerging new countries their programs have experienced significant delays and most are exhibiting rises in expected costs. In reality, beyond Turkey it is difficult to imagine any of the countries that are so far not yet building any nuclear power plants, completing new reactors before the 2030s.

Furthermore, it is important to note the dominance of Russian technology in the proposed projects. Most, if not all, of these proposed sales are backed by Russian finance. However, given the economic problems in Russia in particular relating to the lower global fossil fuel prices and ongoing economic embargoes, it is likely that many of these are to be further delayed or curtailed.

Table 3: Reactor Construction Schedules in Potential Newcomer Countries

Sources: Various, compiled by WNISR, 2016

Nuclear Finances: Corporate Meltdown?

Nuclear power has a significantly different finance profile to the other conventional power plant technologies, with, under normal circumstances, large upfront construction costs, relatively small fuel costs and at the end of operational life, increasing operational costs as well as significant decommissioning and waste management costs. Furthermore, as other sections of the report have shown, nuclear construction projects have recently demonstrated an almost inherent inability to be built to time and cost. Under these circumstances, the views and actions of the markets, credit-rating companies and analysists can be decisive for the competitiveness of nuclear power.

Some years ago, many saw the call for decarbonization as an opportunity for nuclear power to expand, given that no greenhouse gases are emitted during operation—although significant CO2 emissions are generated during other parts of the fuel and operational chain. However, as illustrated in the nuclear vs renewables chapter, this has not occurred and it is renewables, particularly solar and wind power, that have over the last decades been deployed at scale. Steve Kidd, long-term nuclear industry strategist, has gone as far as suggesting “to abandon climate change as a prime argument for supporting a much higher use of nuclear power to satisfy rapidly-rising world power needs”. [175] The reason:

The nuclear industry giving credence to climate change from fossil fuels has simply led to a stronger renewables industry. Nuclear seems to be “too difficult” and gets sidelined - as it has within the entire process since the original Kyoto accords. And now renewables, often thought of as useful complements to nuclear, begin to threaten it in power markets when there is abundant power from renewables when the wind blows and the sun shines.

Indeed, there is growing conflict between the power produced by variable renewables, such as wind and solar power, and the large centralized capacity operating around the clock (traditionally known as base-load capacity), such as nuclear power and coal. In particular, many renewable energy sources have priority access to the grid system and/or have lower operating costs than conventional sources and therefore, when they are able to generate, it is their electricity that enters the grid system. As more and more solar and wind is deployed, they are taking a greater and greater share of the market at particular times, therefore, restricting the production sales of other power sources [176], especially in North America and Western Europe, regions where there is also flat or falling power demand. On 15 May 2016, in Germany, the world’s 4th largest economy, for a few hours over 80 percent of the country’s power was provided for by renewables  [177]; a country with 10.8 GW of installed nuclear and 48 GW of coal and lignite capacity.

Therefore, it is clear that as renewables make an ever increasing contribution to the power mix, then any conventional power capacity will need to be smaller, more flexible units that compliment rather than conflict with the increasingly cheap renewables, as well as interact rapidly with other balancing options, such as energy storage or flexible demand. This view is shared by many politicians, [178] financiers [179], and industry experts, including Steve Holliday, then CEO of the U.K.’s National Grid, which owns and operates the infrastructure and is responsible for grid balancing, who stated:

From a consumer’s point of view, the solar on the rooftop is going to be the baseload. Centralized power stations will be increasingly used to provide peak demand [180].

The falling manufacturing costs—the solar PV module costs have fallen 80 percent since 2008—and the subsequent lower operating cost of renewables—the levelized costs of onshore wind power has fallen 50 percent since 2009 [181]—is also reducing the market price for power. This is most starkly seen in Europe, with major utilities seeing this not as a cyclical trend but as a permanent change. “I think that the price of electricity has no reason to rise. It will never be like it was before,” stated Isabelle Kocher, chief executive of French company ENGIE, the world's largest non-state-owned producer of electricity. [182]

Most traditional utility companies have been slow to invest in renewable energies and most onshore wind and solar PV are not owned by the incumbent utilities. Given that solar and wind have been and are expected, by the International Energy Agency (IEA), amongst others, to be the largest source of new capacity to be deployed on the medium term [183], many utilities are changing their business focus. In Germany, two of the largest power companies, E.ON and RWE, have announced that they will both split in two and develop a conventional business arm and another deal with renewable energy and energy services. While in France, the bastion of large scale, centralized electricity planning, ENGIE, formally known as GDF-Suez, has also announced that it too will focus on energy services. [184]

In addition to, and in part as a result of, these changes the short-term prices of fossil fuels have fallen considerably, with coal prices in Europe in 2008 were approximately US$200/ton, while in Asia achieved only about US$175/ton, but both fell to less than US$75/ton in 2015 [185] and are expected to fall to US$50/ton during 2016 in Europe. [186] Globally natural gas prices have also fallen in the U.S. in 2013 from US$5/MBTU  [187]to less than US$2/MBTU in 2016, while in Asia and Europe, over the same time period they, respectively, fell from US$20/MBTU and US$11/MBTU to less than US$5/MBTU in 2016. [188] The falling prices of fossil fuels are likely to further drive down the market prices for electricity, particularly affecting the relative economics for nuclear power.

Low interest rates are of huge significance for large capital intensive projects like nuclear power. A study published by the Oak Ridge National Laboratory in the U.S., suggested that halving the annual interest rate for a nuclear power plant that cost US$6000/kW, from 10 to 5 percent, would reduce the final production cost of power by around 40 percent. [189] This approximate assessment is in line with findings from the IAEA, that notes that interest rate and construction period are fundamental to the economics of a project and that :

this can be shown by comparing the relative amounts of interest during construction (IDC) incurred by two projects of identical value ([US]$5.75 billion) in terms of overnight costs (costs of materials, equipment, labour, etc.), but which differ in terms of project duration and the rate of interest paid on financing. The total amounts of IDC incurred by these two projects was almost [US]$2.8 billion if a 7 year construction duration and 10% rate of interest was assumed, versus [US]$1 billion if a 5 year duration at a 5% rate of interest was assumed. [190]

Given that interest rates are at a historic low and have been for some time, from a cost of borrowing money perspective there has never been a better time for building a nuclear power plants. Despite this, and the availability of capital, there is very little private sector investment in nuclear power.

Given this combination of circumstances, it is not surprising that the views of the financial sector towards large incumbent power utilities and the nuclear industry in particular remains as nervous and unforgiving.

Credit ratings companies assign ratings on companies’ or government’s expected ability to pay back debt, in a timely manner and therefore, “can and should provide a robust forward looking indication of relative credit risk.” [191] There are three main ratings agencies, Moody's Investors Service and Standard & Poor's (S&P), which together control 80 percent of the global market, while Fitch Ratings controls a further 15 percent. The views of the rating agencies have a large impact on the financial situation of companies and states. It was said, in 2011, of head of S&P, “David Beers might be the most powerful man in the world you have never heard of.” [192]

The rating companies assign score cards to companies or governments. S&P's long-term rating system has 10 categories: AAA, AA, A, BBB, BB, B, CCC, CC, C and D. The rating is given a + or - to indicate that the company is in the upper or lower end of the category. All of the ratings are supplemented with an “outlook”; this is the rating agency’s opinion on the probable short-term trend in the company’s credit quality. The outlooks are positive (up), stable or negative (down). The highest rating is AAA, down to BBB, which are also said to be a safe investment. However, BB down to C is described as speculative or “junk”. [193]

Table 4: Standard and Poor’s Long-Term Credit Rating of Major European Utilities

Sources: Standard & Poor’s; Companies’ Financial Reports

Table 4, shows the trends in rating from S&P for a selection of major electricity utilities. What is clear, is that S&P recognizes the prevailing conditions in the power sector in Europe with negative or stable reviews of the companies and, indeed, all of the assessed ones having lower credit rating than nine years ago. In February 2016, S&P published a summary of its views on 16 European parent companies of power utilities, which concluded that falling power prices, structural changes, including a new market design across Europe, and falling earnings could result in downgrades across the sector this year. [194]

As shown in the France Focus section of this report, EDF has particular financial troubles. This is recognized by the rating agencies. In May 2016, Moody’s issued a credit opinion, which highlighted three key problems for EDF; exposure to declining market prices in France and the U.K.; increased competition in its domestic supply market; and the substantial investment program required to upgrade its nuclear reactors. Moody’s also noted that the “rating could be downgraded if Hinkley Point C were to go ahead” and that “the outlook could return to stable provided that EDF decides not to proceed with Hinkley.” [195] This is all the more remarkable as during the same week, Jean-Bernard Levy, EDF chief executive told its shareholders that Hinkley was “essential”, adding: “Without Hinkley Point, the group would have no credibility to reach new nuclear markets.” [196] During the year 2015, EDF’s company debt rose by nearly €3 billion (US$3.6 billion) to €37.4 billion (US$40.9 billion). As EDF's credit-rating was downgraded, the debt load will likely increase further as debt becomes more expensive.

Source: Yahoo Finances, July 2016  [197]

This is a similar view to S&P, which in May 2016 lowered its long-term corporate credit rating by S&P to A from A+, which “reflects the increasing share of revenues that EDF derives from unregulated activities following the partial liberalization of the French energy market. This comes at a time of a sharp decrease in power prices.” [198] In June Fitch ratings also downgraded its assessment of EDF from A to A-, one of the key reasons for this was “in view of further potential major commitments, its biggest challenge will be to reduce underlying negative free cash flow.” [199] EDF shares lost 87 percent of their value since they peaked in 2007 (see Figure 20).

While EDF has sought and achieved increased government support and finance to maintain its structure, GDF-SUEZ, has taken a different route, by redefining its business model and renamed itself as ENGIE, in April 2015 and in doing so it stated [200]:

That’s why GDF SUEZ is now ENGIE. The world of energy is undergoing profound change. The energy transition has become a global movement, characterized by decarbonization and the development of renewable energy sources, and by reduced consumption thanks to energy efficiency and the digital revolution.

The rating agency S&P was receptive to this restructuring, saying:

We view ENGIE's recently announced asset rotation plan as a positive, albeit ambitious, strategic shift. We expect this will change the group's business mix over time. [201]

Despite this, the prevailing conditions in the European market have resulted in an overall downgrading of the company by S&P and Moody’s. [202] During the 2015/16 financial year the financial debt of ENGIE rose from €38.3 billion (US$42.5 billion) to €39.2 billion (US$43.4 billion). Furthermore, despite this rebranding, ENGIE still describes itself as a “player in the worldwide nuclear revival”, with projects including in the U.K.; with part ownership of NuGen, which together with Toshiba plan to build 3.4 GW of capacity; in Turkey it is involved in the Sinop project; and is active in projects in Brazil, Saudi Arabia and Poland. [203]

Of all countries in Europe, the incumbent companies in Germany are experiencing the most visible transformation. On 1 January 2016, E.ON completed its restructuring, whereby it will focus on renewables, energy networks and customer solutions, while a separate company, Uniper will focus on conventional power (hydro, natural gas, coal) and global energy trading. However, somewhat surprisingly, E.ON retained responsibility for its remaining four nuclear power plants, which was said to avoid delay in the establishment of Uniper. [204] S&Ps stated, prior to the final agreement on nuclear power, that the new structure of E.ON would strengthen their risk profile, but that it was still being downgraded. [205]

RWE, have taken a similar approach separating its renewables, grids and retail distribution into a subsidiary, floating 10 percent in an initial public offering in 2016, which “allows RWE to tap market capital for renewable energy while winding down conventional operations”. [206] In May 2016, Moody’s downgraded RWE, as its “generation fleet is primarily fixed-cost in nature, with over half of output represented by lignite and nuclear, making it exposed to movements in wholesale power prices as RWE's hedges roll off” as well as concerns over the risks associated with nuclear liabilities and political expose to its coal and lignite generation. [207] RWE shares lost about 85 percent of their value since they peaked in January 2008 (see Figure 21).

Source: Yahoo Finance, July 2016  [208]

Vattenfall, which owns significant capacity in Sweden and Germany, is also suffering and its outlook according to Moody’s and S&P is negative. This is in part due to lower fuel prices, but also, to exposure to carbon pricing, given its ownership, although it is trying to sell it, of significant lignite capacity in Germany and uncertainty over nuclear decommissioning policy also in Germany. [209]

The fragility of the European utilities and the impacts of nuclear construction are extremely pronounced in Finland with the impact of Olkiluoto on Teollisuuden Voima Oyj (TVO). The reactor should have been completed in 2009, but is now scheduled for completion in 2018 and has experienced a considerable cost over-run (see Finland section in Annex 1 for further details). As this news emerged year on year, it has had a negative impact on the company’s credit ratings. In May 2016, S&P lowered its rating for the company to 'BB+/B' from 'BBB-/A-3. This was said to be both as a result of the deterioration in the Finish power prices and most damningly:

Future prices are currently predicted by the market to be below TVO's expected costs of production when the third nuclear power plant Olkiluoto 3 (OL3) is commissioned in 2018/2019. [210]

In 2009, the Fitch Long term rating was A-, but by May 2016 it had fallen to BBB with a negative outlook. [211] Fitch also revised its outlook for TVO from stable to negative in May 2016 and said that it may downgrade the rating in the next 12 to 18 months depending support from the shareholders with particular concern “when the Olkiluoto 3 (OL3) nuclear power plant will be commissioned in late 2018, leading to substantially higher electricity production costs”. [212] TVO's rating by Fitch and S&P is now just two notches above “junk”.

Source: Yahoo-Finance, Google Finances, 2016 [213]

This news should be particularly troublesome for those building or considering building nuclear power plants, as the perceived wisdom was that the main financial risk was during construction and that once operational, the financial risks would decline. However, these agencies are highlighting a danger that, once complete, the reactors are unlikely to be profitable, which may well apply across the whole European market and therefore raise concerns for the other construction projects, in France, Slovakia and even Belarus, who plans to sell into the Baltic market.

ENEL, which is primarily an Italian company, but with other European assets including in Spain and Slovakia, is one of the few European power companies deemed by the credit agencies to have a stable outlook. This is primarily because despite falling power prices, “Enel's earnings exposed to merchant generation in Europe is low relative to other European utilities”. Moody's estimates that approximately 70 percent of group EBITDA comes from a combination of regulated/contracted activities that support cash flow stability’. [214]

In Central Europe, the large centralized utilities are also suffering. In April 2016, Moody’s downgraded the Czech Utility, CEZ, as it said its generating fleet was “predominantly fixed-cost in nature, with around 90 percent of output represented by lignite, nuclear and hydro, thus making it particularly exposed to movements in wholesale power prices”.  [215]

The falling revenues and negative outlook from the rating agencies is mirrored in the stock market, with European stock market prices for major utilities falling since the turn of the decade, as can be seen in Figure 22. Of the five selected companies, only ENEL of Italy has retained most of its value, still losing one third of its value a decade ago.

In Japan the power companies are financially suffering, which is not surprising given the immediate impact that Fukushima had on the power companies with the closure of all of the country’s nuclear power stations. However, what is now also clear is that the longer term political impacts with the introduction of market liberalization may affect the longer term viability of the incumbent utilities. This raises concerns over the longer term viability of the companies, as Moody’s notes on the proposed reforms that, “the utilities' relatively high ratings have been underpinned by their protected monopoly position, and a supportive and relatively predictable regulatory framework”. [216]

In April 2016, the next wave of Japanese electricity market liberalization entered into force, this enabled non-commercial customers to choice their electricity supply for the first time. In response to this some of the previously monopolistic regional power companies are proposing restructuring. For example, Tokyo Electric Power Corporation (TEPCO), has adopted a new business slogan “Energy for Every Challenge”, and established a holding company, which will continue to own the nuclear, hydro and other renewables, with three additional subsidiaries; fuel and thermal power generation, general power transmission and distribution and retail electricity. [217] Moody’s have stated that the restructuring will have no impact on their ratings. [218] However, as the operator of Fukushima, TEPCO’s credit rating and financial outlook in general has experienced massive downward turn as a result of the accident.

The situation is very different in Korea, where the Korean Electric Power Corporation (KEPCO), remains in a strong position due to its virtual monopoly of generation (85 percent), through its ownership of the six generating companies as well as its monopoly operation of the transmission and distribution systems. Furthermore, with falling fossil fuel costs and the absence of an automatic pass-through to customers, its earning almost doubled in 2015. Consequently, Moody’s have noted that the strong operating results support a stable outlook rating. [219]

The difference between the Japanese and Korean utilities can be seen in Figure 23, which track the share of top two Japanese companies TEPCO and Kansai Electric and the Korea virtual monopoly KEPCO. The impact on the share prices of the Japanese companies of the beginning of the Fukushima catastrophe in March 2011 is clear and expected. However, the failure to show any recovery in the intervening five years is remarkable. This is likely to be for a variety of reasons including: the failure to restart a significant number of reactors and the ongoing uncertainty over the future role for nuclear power; the introduction of new electricity market liberalization legislation, opening up the market to new actors; and the development of new technologies, enabling decentralized power production and storage. In Korea, KEPCO remains in a regulated market and has been able to increase its revenue significantly in the past 12 months, hence its rapid upturn in its share value.

(in % since 2010)

Source: Yahoo Finances, Google Finances, 2016 [220]

China General Nuclear Corporation (CGN), one of the three nuclear operators in China, was established in 1994 and is wholly owned and directly supervised by the State-owner Assets Supervision and Administration Commission under China’s State Council. A CGN subsidiary, CGN Co Ltd, was established in March 2014 and in December 2014, the company made its first public listing, which raised US$3.16 billion and was deemed credit positive by Moody’s. The ownership of the company is 64 percent by CGN, 24.56 percent by Hong Kong Shareholders, 7.54 percent by Hengjian Investment and 3.70 percent by China National Nuclear Corporation. [221] In May 2015, Moody’s said of CGN, when reviewing its proposed bond for a wholly owned subsidiary: “CGN's standalone credit metrics will remain weak for the next two to three years, given its massive capital expenditure pipeline, potential delays in projects and slowing electricity demand growth in China.” The rating agency also stated that CGN’s outlook remained stable, reflecting that “the company will not undertake further aggressive debt-funded acquisitions or expansion”. [222] In July 2015, Moody’s assigned a definitive rating, of A3, to the US$600 million bond, which was said to be for “refinancing short term borrowings, replenish working capital and for general corporate purposes.” [223] The share price of CGN Corporation’s subsidiary, CGN Co. Ltd, on the Hong Kong stock exchange, has fallen by 60 percent since June 2015, as can be seen in Figure 24.

Source: Yahoo Finance, July 2016

In June 2016, Exelon, announced that it was going to shut down the reactor at Clinton Power stations in June 2017 and the two reactors at Quad Cities station in June 2018 since it had failed to get the financial support from the State of Illinois, as the power plants had lost a total of US$800 million over the past seven years. One utility analyst was quoted as saying: “The lesson here is that there’s not going to be much subsidizing of merchant nuclear plants.” [224] Exelon shares lost about 40 percent compared to their level a decade ago and they are over 60 percent below their peak level in 2008 (see Figure 25).

Source: Yahoo Finances, July 2016 [225]

All four reactors under construction in the U.S. are being built in regulated markets. Two of these are being built by Georgia Power at the Vogtle site. In May 2016 Moody’s downgraded its parent company, Southern Company from Baa1 to Baa2—just two notches above “junk”—as a result of its acquisition of AGL Resources and the additional debt it was taking on. However, Moody’s noted that Southern's financial position had been weakened over a number of factors, including the Vogtle site “that has experienced costs increases and delays, with commercial operation currently three years behind schedule.” [226]

Nuclear Builders and Vendors

In addition to the utilities, the nuclear builders and vendors are suffering in part as a result of the changes in the power market. The traditional reactor suppliers, namely, AREVA, Atomic Energy of Canada Limited (AECL), Westinghouse and General Electrics (GE), are losing what remains of the export market to countries such as China, Russia and South Korea, (see Potential Newcomer Countries), which is partly due to their greater ability to potentially access (cheaper) finance.

Over the past few years, AREVA has experienced wide-ranging financial problems, which are reflected in its credit rating. S&P downgraded AREVA to “junk” (BB+) in November 2014 [227], and by another two notches in March 2015, deep into the speculative domain (BB-). [228] Then in December 2015, following further revelations on the extent of its financial problems S&P’s downgraded the stock further to B+. [229]

Source: Investing, June 2016 [230]

The rising debt—from €4.47 billion (US$5.4 billion) in 2014, to €6.32 billion (US$7 billion) in 2016—and lack of financial credibility has led the Government to propose that the company's reactor construction arm, AREVA NP, become incorporated into EDF [231], the details of which are still to be finalized (see Focus France section). However, the impact of these developments can be seen in the evolution of AREVA’s share price, which, as of early July 2016, is 96 percent lower than it was in June 2008 (see Figure 26).

The nuclear industry is Russia is largely state owned and operated. However, Rosatom State Atomic Energy Corporation of Russia is the 100 percent owner of the joint stock company JSC Atomenergoprom, which is rated by the major credit agencies. In January 2015, S&B downgraded the company to BB+ (“junk”). In April 2016, it was given a negative outlook by Moody’s, primarily in response to the sovereign credit ratings of the Russian Federation as a whole, but the rating company warned that “the lack of adequate liquidity could put pressure on the company's rating.”  [232] This is particularly important given that Rosatom stated that it is currently building nine reactors in Russia and an additional 11 overseas (with said to a total of 29 reactors in the portfolio). They further stated that the overseas order portfolio is worth US$101.4 billion. [233]

Table 5: Standard and Poor’s Long-Term Credit Rating of Major Nuclear Vendors

Sources: Standard & Poor’s, Companies’ Annual Reports

Toshiba purchased Westinghouse from British Nuclear Fuels Limited in 2006 for US$5.4 billion. In April 2016, it announced that it expected to have US$2.3 billion in impairment losses, in recognition that it had overpaid for the company and falling revenues. Toshiba’s current fiscal year estimate for sales revenue from the nuclear firm is US$3.1 billion in 2015/6 — US$540 million below what it was in November 2015 and US$180 million below what the company projected in March 2016.  [234] Even before the latest financial situation had come to light, Toshiba admitted that it was looking for a partner so that it would reduce it 87 percent ownership of Westinghouse. [235]

Atomic Energy of Canada Limited, is one of the world’s largest nuclear constructors, with sales across the world, including in Europe, Asia and the Americas. However, AECL, is a federal Crown corporation and so is not listed on stock exchanges or given rating by the Agencies.

Conclusion on Corporate Finances

The power sector is in a period of transformation as the need for decarbonization is leading to the larger deployment of renewable and greater energy efficiency. This, coupled with falling fossil fuel prices, is reducing the revenues of the traditional utilities, that until recently had remained focused on maximizing profits from its existing infrastructure.

Furthermore, already, in systems with higher levels of deployment of solar and wind power and other variable renewables the operational regime and economic profile of the power market has changed. This has been increasing the need for flexible generation and reduced the need for base-load capacity such as nuclear and coal. Further reducing the opportunities for further nuclear power deployment, as illustrated by the technical and/or economic problems of the world’s most experienced nuclear exporters.

These factors are recognized by, and being acted upon by the financial community, with negative outlooks for many power companies particularly for those without regulated prices for conventional power. However, even in regulated market, the onward drive of new technologies is expected, by analysists, investors and the industry itself, to be only a temporary block of the development of a new power market, driven by new market actors and technologies and greater customer engagement.

In some countries, the extent of these have been recognized and the existing incumbents are restructuring to develop business models to sell; energy services, rather than just kWhs; balancing services; and smaller, often decentralized generation units. However, this is not always these case and many are retrenching and are unwilling to reform, which is likely to threaten their economic stability.

Chernobyl+30 Status Report

“The magnitude and scope of the disaster, the size of the affected population, and the long-term consequences make it, by far, the worst industrial disaster on record. Chernobyl unleashed a complex web of events and long-term difficulties, such as massive relocation, loss of economic stability, and long-term threats to health in current and, possibly, future generations…”

IAEA/WHO; 26 July 2005 [236]

General Overview of the Chernobyl Site

The Chernobyl Power Complex, (ChNPP) owned and operated by the state company Energoatom, is situated about 130 km north of Kiev, Ukraine, and about 20 km south of the border with Belarus, and consisted of four RBMK-1000 (reaktor bolshoy moshchnosty kanalny or high-power channel reactor) a 1000 MWe pressurized light-water cooled reactor with individual fuel channels, and using graphite as moderator.

The first unit, commissioned in 1977, was followed by unit 2 in 1978, unit 3 in 1981, and unit 4 in 1983. Unit 1 was subject to a partial core meltdown on 9 September 1982 and was repaired. [237] Contamination was observed in the area within 14 km radius but no public information was disclosed about the accident at the time.

Two more reactors, units 5 and 6, were under construction at the time of the 1986 accident. Unit 5 was then about 70 percent complete and was scheduled to start operation on 7 November 1986. However, construction work was halted and eventually cancelled in April 1989. Unit 6 was never completed.

The three remaining units, resumed operation a few days after the 1986 accident. Unit 2 was shut down in 1991 following a major fire in the turbine hall. [238] Unit 1 was shut down in November 1996, and unit 3 in 2000.

Sequence and Origin of the Accident on 26 April 1986

The Chernobyl nuclear accident happened on 26 April 1986 at 01.23 a.m. in the course of a technical test in unit 4. The “beyond design-basis accident” was caused by inappropriate reactor operation at low-power level. The reactor was under extremely unstable conditions because of the withdrawal of almost all control rods. This was a very dangerous operation in RBMK reactors as these had positive void coefficients, meaning that runaway nuclear reactions could take place. This duly occurred with the result of a sudden power surge, and, when an emergency shutdown was attempted by inserting the remaining control rods, a much larger spike in power output—output increased about 100-fold in about four seconds—which led to at least two massive steam and hydrogen explosions and the rupture of the entire reactor vessel and a major conflagration. This released a large volume of radioactive gases, aerosols and particulates into the atmosphere. Radionuclides released from the explosion included very short-lived fission products, which resulted in very high dose rates in adjacent areas.

These events exposed the reactor’s graphite moderator (1600 tons) to air, causing it to ignite.  After the initial release, larger releases of radionuclides occurred over a period of 10 days due to the continuous graphite fire. It has been estimated that the explosions and fires released about a third of the reactor’s radioactive inventory into the atmosphere and across much of Europe.

The accident was classified as a level 7 event (the maximum classification) of the IAEA’s International Nuclear Event Scale (INES).

Onsite Challenges

Following two explosions, the first being the initial steam explosion, followed a few seconds later by a second explosion, possibly from the build-up of hydrogen due to zirconium-steam reactions, a significant part of the fuel, the graphite and structural materials were ejected. One worker, whose body was never recovered, was killed in the explosions, and a second worker died in hospital a few hours later as a result of injuries received in the explosions.

Fires started in what remained of the unit 4 building, giving rise to clouds of steam and dust, and fires also broke out on the adjacent bitumen covered turbine hall roof. The chimney effect of the ten-day-lasting graphite fire ejected smoke, radioactive fission products and debris from the core and the building several kilometers into atmosphere. The heavier debris was mostly deposited within 5 km of the site, but lighter components, including most fission products and noble gases, and were blown by the prevailing winds to create the radioactive plumes, which contaminated over 40 percent of the land area of Europe.

A first group of 14 firemen arrived on the scene of the accident on 26 April 1986 at 01:28. Over 100 fire fighters from the site and called in from Pripyat were deployed, and it was this group that received the highest radiation exposures. Reinforcements were brought in until about 04:00, when 250 firemen were available and 69 firemen participated in fire control activities. According to corroborating reports from various sources, [239] the fires on the roofs of units 3 and 4 were localized at 02:10 and 02:20 respectively, and the fire was quenched at 05:00. Unit 3, which had continued to operate, was shut down at this time, and units 1 and 2 were only shut down in the morning of 27 April.

The main challenges were to prevent the fire from spreading to unit 3, to localize the fire on the roof of the common machine hall of units 3 and 4, to protect the undamaged parts of unit 4 (the control room, inside the machine room, the main circulating pump compartments, the cable trays), and to protect the flammable materials stored on-site, such as diesel oil, stored gas and chemicals.

Source: chnpp.gov.ua

On 28 April 1986, a massive accident management operation began. This involved dropping large amounts of different materials, each one designed to combat a different source of the fire and the radioactive release. The first measures taken to control fire and the radionuclides releases consisted of dumping neutron-absorbing compounds and fire-control material into the crater that resulted from the destruction of the reactor. The total amount of materials dumped on the reactor was about 5,000 t including about 40 t of boron carbide, 2,400 t of lead, 1,800 t of sand and clay, and 800 t of dolomite. About 1,800 helicopter flights were carried out to dump materials onto the reactor (see Figure 27).

During the first flights, the helicopter remained stationary over the reactor while dumping materials. As the dose rates received by the helicopter pilots during this procedure were too high, it was decided that the materials should be dumped while the helicopters travelled over the reactor. This procedure caused additional destruction of the standing structures and spread the contamination. Boron carbide was dumped in large quantities from helicopters to act as a neutron absorber and prevent any renewed chain reaction. Dolomite was also added to act as heat sink and a source of carbon dioxide to smother the fire. Lead was included as a radiation absorber, as well as sand and clay, which it was hoped would prevent the release of particulates.

A system was installed by 5 May to feed cold nitrogen to the reactor space, to provide cooling and to blanket against oxygen thus avoiding further hydrogen explosions. By 6 May when most of the graphite had burned, the core temperatures fell and there was a sharp reduction in the rate of radionuclide releases. In addition, work began on a massive reinforced concrete slab with a built-in cooling system beneath the reactor. This involved digging a tunnel from underneath unit 3. About 400 people worked on this tunnel, which was completed in 15 days, allowing the installation of the concrete slab. This slab would not only be of use to cool the core if necessary, it would also act as a barrier to prevent penetration of melted radioactive material into the groundwater.

In addition to the two workers that had died from the explosions on the day of the accident, by the end of July, six firemen, a further 21 plant staff and a visitor had died of acute radiation poisoning as a result of the accident.

Following the accident and the large contamination by the radioactive cloud, a 2,800 km2 exclusion zone designated for evacuation has been established and placed under military control. More than 130,000 people were moved out of their homes and villages in the immediate aftermath of the accident. But many more people were eventually displaced. The U.N. Office for the Coordination of Humanitarian Affairs (OCHA) stated in 2004: “Nearly 400,000 people were resettled but millions continued to live in an environment where continued residual exposure created a range of adverse effects.” [240]

While units 1, 2, 3, unaffected by the explosions, resumed operation a few weeks later, the Soviet army engaged (and poorly trained) more than 550.000 workers called the “liquidators”, who were engaged in the disaster management. Their tasks included evacuation of contaminated debris, cleaning emergency areas, repairing equipment and buildings etc.

Dispersion of Radioactivity

The graphite fire at unit 4 caused the ejection of radioactive gases, aerosols and particulates high into the atmosphere. These were distributed in plumes by prevailing winds and rainfall throughout Europe and eventually across the northern hemisphere. The consequent caesium-137 fallout patterns in Europe were later measured by the European Commission (see Figure 28).

In total, 40 percent of Europe’s land area was contaminated significantly (>4,000 Bq per m2) by Chernobyl’s fallout. [241] The most seriously affected countries (ranked by magnitude of Cs-137 fallout) were the former USSR Republics adjacent to the stricken reactor—Belarus, Russia and Ukraine.

Other seriously affected countries were, in area size order, former Yugoslavia, Finland, Sweden, Bulgaria, Norway, Romania, Germany and Austria. Although former Yugoslavia was not measured by the EC teams (because of the Balkan civil war), earlier measurements had been made by the U.S. Department of Energy.

In terms of the percentages of their land areas, which were contaminated, Austria, Finland, Sweden, Slovenia, and Slovakia were also significantly affected outside the former USSR.

Source: De Cort et al., 1998 [242]

In terms of average Cs-137 concentrations (Bq per m2), Austria, Slovakia, Slovenia, and Moldova were also affected. The most relevant parameter for health was the average concentration of Cs-137 in diet during the year 1986 to 1987 and the countries (outside former USSR) with the highest levels were Austria, Moldova, Bulgaria, Croatia, Liechtenstein, Finland and Romania. [243]

As shown in Figure 29, radioiodine distribution patterns in Europe were very different from those for caesium-137. This is because the iodine isotopes were distributed largely in gaseous and aerosol forms and not as particulates.

Source: C. Seidel et al., 2012 [245]

Populations Affected

According to the United Nations Scientific Committee on the Effects of Atomic Radiation (UNSCEAR) [246], over six million people still live in contaminated areas of Belarus, Russia and Ukraine. Over half a million clean-up workers were exposed to high doses at an average of 120 mSv (see Table 6).

Table 6: Populations Exposed to Chernobyl Fallout: Average Effective Dose

Source: UNSCEAR 2008

Health Impacts

The Chernobyl accident resulted in epidemics of thyroid cancer in Belarus, Ukraine and Russia starting after 1990. Over 6,000 thyroid cancers have arisen so far [247] and at least another 16,000  [248] are expected to arise in future decades. It is notable that radiogenic thyroid cancers are still occurring among the Japanese bomb survivors nearly 60 years after their exposures.  [249]

In 2015, continuing increases in thyroid cancer cases were seen among adults in Belarus and Ukraine. The estimated thyroid cancer risks per gray (Gy) [250] in the most contaminated areas are high, with relative risks of 8.7 per Gy in Belarus and 8.0 per Gy in Ukraine. This translates into 770 percent to 700 percent increases respectively over the background rates in these countries. The raised incidence rates for adults are expected to peak in the near future in Belarus but will continue above the pre-accident rates for many years. Similarly, 500 percent increases were observed in leukemia risk in both Belarus and Ukraine. [251] These are extraordinarily high risk increases, perhaps the largest increases in risk ever measured after exposures to toxic substances.

In total, TORCH-2016 (The Other Report on Chernobyl) estimated that 40,000 fatal cancers will arise over the next 50 years from Chernobyl, about eight times greater than the expected number of fatal cancers from arising in future from Fukushima.

TORCH 2016 revealed new evidence of increased thyroid cancer cases in Austria, similar to previous indicative studies of increased thyroid cancers in the U.K., Czech Republic, Poland and Slovakia. TORCH 2016 estimated that between eight and 40 percent of increased thyroid cancer cases after 1986 in Austria may be due to Chernobyl.

After thirty years, sufficient time has elapsed for dose registries to observe statistically significant increases in other solid cancers including breast, colon, lung and kidney cancers. However, their relative risks, 20 percent to 50 percent per Gy, are about an order of magnitude lower than those observed for thyroid cancer and leukemia. The new evidence in TORCH 2016 indicates increased incidences of cardiovascular effects, stroke, mental health effects, birth defects and various other radiogenic effects in the most affected countries.

Recent studies provide strong evidence of decreased health indicators among children living in contaminated areas in Belarus and Ukraine, including

• impaired lung function and increased breathing difficulties [252]
• lowered blood counts [253]
• high levels of anemias and colds  [254] and
• raised levels of immunoglobulins  [255]

The “Sarcophagus”

As it was impossible in the immediate aftermath of the initial explosions to work on the destroyed structure of the reactor, containing 200 tons of highly radioactive corium, 30 tons of highly contaminated dust and 16 tons of uranium and plutonium, three weeks after the accident it was decided as the first and urgent action to build a protection structure above the reactor to limit radioactive contamination and protecting it from climate exposure.

Source: chnpp.gov.ua

The structure was called “sarcophagus” (see Figure 30) and was built by thousands of liquidators who participated in the construction mostly made of concrete slabs covering the entire structure. [256]However, the sarcophagus was put together in haste under severe conditions and rapidly deteriorated in the following years.

G-7 Support of Shutdown of RMBK and VVER 440-230 Reactors

In 1993, the G7 launched an initiative on the prevention of nuclear accidents at Russian built plants and agreed that the European Bank for Reconstruction and Development (EBRD), establishes a fund aimed at the closure and decommissioning of the oldest Russian built nuclear power plants of the RBMK and VVER 440-230 types. The initiative initially included the plants of Ignalina-1 and -2 in Lithuania, Kozloduy units 1 to 4 in Bulgaria, Saint Petersburg units 1 to 4 in the Russian Federation and Bohunice-V1-1 and -2 in the Slovak Republic. In 1996, Chernobyl-4 was added to the scope. The fund contributors included the G7 countries, the EU, Belgium, Denmark, Finland, the Netherlands, Norway, Sweden and Switzerland. Initial contributions were in excess of €285 million (then about US$330 million). As of 2016, 45 countries and the European Community are contributing grants for safety upgrades and decommissioning of the above nuclear power plants. The concept included for each plant a nuclear safety assessment, the implementation of essential short- and medium-term safety improvements and the final closure of the plants. Later on, an additional special fund was established for the decommissioning of each unit. [257], [258]

The Nuclear Safety Account team was created at EBRD with the purpose of establishing the safety assessment for each plant, identifying and designing the safety facilities to be built as well as the decommissioning procedures, drafting grants agreements between the EBRD, Chernobyl Nuclear Power Plant and the supplier and finalizing construction contracts. The team remains in charge of monitoring the projects and of verifying their compliance with the contracts.

EBRD Chernobyl Decommissioning/Spent Fuel Storage Program

This program has been developed by the Nuclear Safety Account team in cooperation with the European Commission TACIS program and following the grant agreements signed between the Bank and the Chernobyl Nuclear Power Plant. [259] It includes the construction of an intermediate spent fuel storage facility, liquid and solid nuclear waste treatment plants and a long-term protection structure to cover unit 4.

An in-depth safety assessment was carried out of the local Intermediate Spent Fuel storage building (ISF-1), which was part of the original plant, and hosted most of the spent fuel assemblies from the four reactors prior to the 1986 accident. ISF-1 was found in poor conditions, judged unsafe and not suitable for the long-term as well as unable to meeting today’s safety standards. Consequently, the decision was made to build a second, intermediate dry storage facility, called ISF-2 to be located 2.5 km south east of the Chernobyl plant, 12 km north-west from Chernobyl city. A turnkey contract to design and build the entire ISF-2 facility was signed in June 1999 between Energoatom and Framatome ANP (now AREVA NP), jointly with French construction giants Vinci and Bouygues. The system is based on the Transnuklear Nuhoms dry casks system. [260]

ISF-2 includes a Spent Fuel Processing Facility (SFPF) and the Spent Fuel Storage Area (SFSA), made of 232 above-ground Concrete Storage Modules (CSM). The storage employs 4,000 tons of reinforced steel, 2,700 tons of stainless steel and 26,000 cubic meters of concrete. The structure was designed to store dry fuel for a period of 100 years. A central geological repository for spent fuel and high-level waste is planned to be built after 2030. This plan also envisages the decontamination of 1,500 hectares of land containing over 5,550 terabecquerel of activity. A railway was built to transport the spent fuel by train carriages.

Following the shutdown of the three operating plants, the total inventory accounted for 21,300 fuel bundles for a weight of 2,700 tons of uranium and 2,000 absorbers, partly still in the three units' cores, partly kept in the reactor cooling pools as well as transferred to the interim storage facility ISF-1. The fuel bundles and absorbers are inserted into a transfer flask and carried by a train carriage to the SFPF at the ISF-2 site. There they are introduced into a hot cell where the fuel bundle and absorbers are dried by means of a gas dehydration system and cut by means of a specially built cutting machine.

The Nuhoms system consists of an enclosure vessel comprising canisters forming separate confinements to prevent the spread of radioactive materials. Spent fuel bundles are introduced in an internal basket that is then included into a canister. Each canister is placed horizontally in the Nuhoms casks that are then introduced in individual compartments of the heavy concrete storage module built at the ISF-2 site. [261]

Construction was due to be completed by March 2003. However, construction went on for about six years of construction until 2006 and several problems had arisen. Despite the near-completion of the processing building and the concrete housing structures for the Nuhoms casks, the work was interrupted due to design errors and negligence of the fact that water had penetrated through the cladding in more than 10 percent of the fuel assemblies. It was also found that the fuel included some reprocessed uranium and plutonium, for which a different neutron spectrum would require redesign of the storage shielding. Additional problems were caused by considerable cost overruns, which raised the investment into the project from an original €68 million (US$64 million) to €275 million (US$326 million).

In March 2006, US-based Holtec International submitted to ChNPP a feasibility study for drying the spent fuel that contained water and, in November 2006, conducted successful testing of the drying facility model. EBRD's Safety Review Group recommended that the donors continue funding the project with Holtec as the main contractor.

The Framatome ANP contract was terminated in April 2007 [262] and following an international audit and arbitration, the company was requested to pay the client a compensation of €45 million (US$59.4 million). In September 2007, Holtec signed a contract to complete the ISF-2. The facility's final design was approved by the Ukrainian Regulator in October 2010.

While still making use of the Nuhoms system, the project implements several Holtec technologies including an innovative double-wall canister, an advanced forced gas dehydration system, and a hot cell to dismantle the RBMK fuel assemblies. The first phase of work, which lasted 100 weeks, valued at slightly over €30 million (US$41 million) involved the preparation of safety and environmental qualification documents in compliance with Ukrainian norms and standards.

The entire work, scheduled to span nearly eight years, involves the supply of 231 canisters manufactured at Holtec's plant in Pittsburgh to be delivered between 2016 and April 2019. The contract includes the construction of the processing facility, numerous physical modifications to the site, and issuance of the intermediate and final safety analysis reports.

The ISF-2 has been completed, pre-commissioning is scheduled to start in September 2016 and full-scale operation is to begin in the fourth quarter of 2017. The fuel loading will most likely be completed by 2022. The total cost of the facility is estimated at €400 million (US$446 million).

Liquid Radioactive Wastes Treatment Plant

The LRWTP [263] is a processing plant for liquid radioactive wastes stored during operation in five 5,000 m3 and nine 1,000 m3 tanks, as well as during the decommissioning operations. The liquids include perlites, resins and evaporator concentrates. The LRWTP also processes the liquids produced during the entire operations on site. The plant, designed by Belgian company Tractebel, was built by the consortium Belgatom (Belgium), Ansaldo (Italy), SGN (France) and by Ukrainian contractors. Construction has been completed in 2015 and has started operation. Total cost was about €35 million (US$39 million).

Industrial Complex on Solid Radioactive Wastes Management

The Industrial Complex on Solid Radioactive Wastes Management (ICSRWM)  [264]includes the Temporary Solid and Liquid Waste Storage (SLWS) and Solid Waste Processing Plant (SWPP), comprising a plant for the sorting and segregation of all categories of solid radioactive waste and the processing of the solid waste generated from the previous retrieval activities and from the routine operational and decommissioning activities of unit 4. Short-lived wastes will be packaged and immobilized for final storage at a near surface disposal facility, whilst higher category wastes will be packaged, over-packed and stored in a temporary storage facility awaiting the construction of a final disposal facility.

A near surface repository for the disposal of short-lived waste, in accordance with the requirements of the Ukrainian Nuclear Regulatory Authorities and in the form of an Engineered Near-Surface Solid Radioactive Waste Disposal Facility (ENSWDF) is located at the Vektor Complex located in the Exclusion Zone. This facility has been built for the final disposal of conditioned LILW-SL and for wastes from the Liquid Radwaste Treatment Plant (LRTP). The storage capacity is 55,000 m_ and the design lifetime is 300 years.

The complex was designed and built by RWE NUKEM GmbH (Germany) with Ukrainian contractors. It was financed by Ukraine and the European Commission and has started operating. The total cost is €33.5 million (US$37.3 million).

Shelter Implementation Plan/New Safe Confinement [265],  [266],  [267]

Following the construction of the “sarcophagus” above the destroyed unit 4, some additional work has been carried out in 1997 to minimize the risk of its collapse. A limited stabilization was achieved with great difficulties in high-radiation levels inside and outside the structure. Safety and protection of personnel and the environment has been improved since. A Fire Protection System and an Integrated Automated Control System have been installed with the purpose of monitoring the status of the shelter, including the “fuel containing material (FCM)” i.e. the corium, collected in the lower section of the reactor.

Additional work was carried out for the clearing of the site, the demolition of nearby buildings as well as construction of an “engineering building” for the management and control of all works. Also a computer-based system was introduced integrating radiation data, information on the structural integrity of the old shelter, measurements of seismic activities and other parameters important for the safety on site and for the future operation of the New Safe Confinement (NSC).

A new change facility with a capacity for 1,430 workers has been built which provides medical screening, training, radiation monitoring, supply of protection equipment as well as an ambulance.

However, these measures would still have not secured the long-term integrity of the structure as well as site safety. It was then decided to build an additional and major protection structure above the unit 4. This has been called the NSC.

The entire Shelter Implementation Plan has been financed separately by a new fund (Chernobyl Shelter Fund) created in 1997 and supported by 44 countries plus the European Union. As with the other fund, it is administered by EBRD and the project is managed by the Nuclear Safety Account team.

The word “confinement” is used instead of the traditional “containment” to emphasize the difference between the “containment” of radioactivity generated in case of an accident, and the “confinement” of radioactive waste that is the primary purpose of the NSC.

The NSC was designed and is being built by the French consortium Novarka with 50/50 partners VINCI Construction Grands Projects and Bouygues Travaux Publics. The contract was signed in August 2007 for an estimated amount of €1.4 billion (US$1.9 billion). Due in particular to the complexity of the task in a radioactive environment, the budget for completion was increased to €1.54 billion (US$2.2 billion) in April 2011. It is likely that the final total cost will exceed €1.8 billion (US$2 billion).

The NSC design is an arch-shaped steel structure that has been designed to cover entirely the existing sarcophagus (see Figure 31). Requirements included the NSC’s resistance to the impact of seismic events of a magnitude of level 6, to tornado class 3 and to other heavy winds and snow loads. The dimensions of the arch were defined based upon the need to operate equipment inside the NSC and to dismantle the existing “sarcophagus”. A large crane and other remotely controlled equipment are installed inside and will be used to dismantle the sarcophagus and to attempt to remove the fuel-containing masses (corium) from the destroyed reactor. NSC is being assembled 600 meters away from the damaged reactor where, thanks to the remediation work over the past two decades, the relatively low ground-level radiation levels allow staff to work for up to 40 hours a week. It is planned to move the NSC above the sarcophagus and to commission it in 2017.

The dimensions of the New Confinement Structure are impressive. The internal height is 92.5 m, the external span is 257 m and the overall length of the structure is 162 m. The external cladding covers an area of 85,000 m 2. The NSC includes two bridge cranes of 50 t capacity suspended from the arch which have the purpose to carry out the deconstruction of the sarcophagus and the structure of the remaining reactor as well as handling of radioactive material. The cranes and other mechanical scrapping and removal equipment will be remotely operated from outside the NSC. All electrical and controls of the NSC are installed in the “engineering building” built nearby.

The NSC will be slid into its final position on a 300-meter rail system by 116 remote-controlled synchronized jacks. The sliding operation at a speed of 10 mph is expected to take two days. The final phase will include the sealing operations and interconnections between the NSC and the shelter. The New Safe Confinement has been designed and built for a 100-year lifetime. Total decommissioning may take several decades as the environmental contamination will last even longer.

Source: chnpp.gov.ua

Fukushima+5 Status Report

Five years have passed since the Fukushima accident began in March 2011. The Japanese government has launched a reconstruction plan to recover from the Great East Japan Earthquake over the next five years. This chapter attempts to describe onsite and offsite challenges of the government's plan, including its impact on the people most affected by the disaster.

Onsite Challenges [268], [269]

Decommissioning Plan

In June 2015, the government revised, for the third time, the medium- and long-term roadmap for decommissioning, following the second revision made in June 2013. At that time approximately 800 m3/day of ground water was flowing from a nearby mountain into the Fukushima nuclear power plant site; specifically, about 400 m3/day of this flow was running into the buildings and the remaining 400 m3/day was running into the ocean. According to the new roadmap, the plan was, during FY2016, to reduce this inflow to the site by 75 percent.

As for the plans for the removal of spent nuclear fuel from the storage pools, the removal from unit 4 was completed in 2014. According to the new roadmap, spent fuel removal from unit 3 is planned to be carried out between financial years 2017 and 2019. Removal from unit 2 is planned for FY2020 but could stretch into FY2021. It is proposed that the removal of used fuel from unit 1 will also begin in FY2020, but its completion is not expected before FY2022.

As for the removal of fuel debris, it is planned in the roadmap to start the work within 2021 although on which unit is not yet determined. In terms of the method to remove the fuel debris, it had been planned in the previous edition of the roadmap to fill the entire interior of the containment vessel with water and then remove the debris. However, due to the concerns about water leakage from the containment vessel and the possible implications in a seismic event, a decision was made in the new roadmap to launch a comprehensive, comparative study on several methods, including implementing the task after partially filling the containment with water or in the air without using any water. The plan is to decide on the method two years later.

Current Status of Each Reactor

The temperatures in the reactor and containment vessel has dropped to about 15 to 30 degrees Celsius. However, radiation doses inside the containment vessels have remained high at 4 to 5 Sv/h. As of 23 June 2016, the amount of water injected into each of the reactor cores of unit 1, 2 and 3 is around 4.4 m3/hour. [270] Therefore, five years after the beginning of the accident, every day, over 300 m3 of water have to be injected into the three reactor cores.

At unit 1, the building cover for preventing radioactive material diffusion is being dismantled to enable the removal of spent fuel from the storage pool. According to current planning, debris removal work will continue until FY2018, and then cranes and handling equipment will be installed for spent fuel removal by FY2020.

At unit 2, preparation for dismantling the building roof began in April 2016. The method of spent fuel removal has not been determined yet.

At unit 3, debris is being removed from the building roof and spent fuel pool. Similar to unit 1, cranes and handling equipment will be installed for spent fuel removal.

The spent fuel removed from unit 1 through 3 will be stored in the common storage pool as in the case of unit 4. The long-term storage method is planned to be determined around FY2020.

A large number of workers had been exposed to radiation in order to get video footage of the conditions in the containment vessels. [271] However, from April 2015, radiation surveys using robots began. For example, 9.7 Sv/h was measured in unit 1 during the first survey. [272] Several of these robots have only lasted for a few minutes before their electronics including computer chips were destroyed by the intense radiation fluxes.

As for the measurement of fuel debris, the data obtained from the survey implemented in March 2015 at unit 1 revealed that there is no significant volume of fuel material in the reactor core and no progress has been made in collecting detailed data of the fuel debris.

In other words, it remains unknown where the fuel is.

Contaminated Water Management

A dedicated bypass system has been operational since 2014 with pumps underground water into  the sea after analyzing its quality subsequent to storage in temporary storage tanks. [273] As of March 2016, the inflow of underground water to the reactor building was reduced from around 400 m 3/day to about 150 to 200 m3/day. [274]

Since 2 September 2015, Tokyo Electric Power Company (TEPCO) has also started pumping groundwater using subdrains—41 wells around the buildings and 5 wells on the sea side. Similarly, to the bypass system, water pumped up from the subdrains is discharged into the ocean after assessing radioactivity levels in storage tanks. [275] Similarly to the bypass system, water pumped up from the subdrains is discharged into the ocean after assessing radioactivity levels in storage tanks [276]. These discharges have been carried out with the consent of the Fukushima Prefectural Federation of Fisheries Co-operative Associations that is concerned about further radioactive contamination and negative publicity.

Radioactive isotopes except for tritium are removed from the highly contaminated water using multi-nuclide removal equipment (Advanced Liquid Processing System, ALPS). The performance of ALPS is under review. However, the disposal method of this processed water has not been determined yet. The Federation of Fisheries Co-operative Associations has commented that reaching any further agreement on discharge would be difficult and that they are concerned about the release of large amounts of tritium. [277] The tritium concentrations are very high, over 500,000 Bq per litre.

The operation of the frozen soil wall as a land-side impermeable barrier was started on 31 March 2016 [278]; this is a controversial measure whose cost and effectiveness have been questioned in the review process of the Nuclear Regulatory Authority (NRA). Although the operation has started, the NRA has not yet fully recognized the effectiveness of this measure. Since the groundwater flow may be altered by the frozen soil wall, the area to be frozen will need to be continually expanded. It was assumed that the effects of this wall would be seen in mid-May 2016. However, on 25 April 2016, TEPCO reported to the NRA that the temperature near the frozen pipes had decreased and that the underground water level had changed. [279] On 2 June 2016, TEPCO admitted that, while about 97 percent of the soil wall showed temperatures below 0°C, other spots remained at +7.5°C due to fast groundwater flow. TEPCO concluded that additional work, such as injecting cement, was needed. [280]

Current status of workers

The government is insisting that they are ensuring that this are a sufficient numbers of workers for decommissioning Fukushima Daiichi and that they are properly managing the workers. [281] For example, according to TEPCO, about 3,000 to 7,500 workers per day are engaged in the decommissioning work as of September 2015, [282] and their average monthly radiation dose is maintained at a low value of 0.51 mSv according to data from February 2016. [283] 

But reportedly, the reality of the labor environment can be different. In March 2015, a local newspaper of Fukushima Prefecture reported that 174 workers were legally forbidden to continue working at the site because their total dose exceeded 100 mSv. [284]

In September 2015, the Fukushima Bureau of Ministry of Health, Labour and Welfare (MHLW) demanded that TEPCO fully implement labor disaster countermeasures in response to successive fatal accidents [285] that occurred at the site. [286] In addition, the bureau reported that as of September 2015, there had been 656 cases of violation of regulations concerning the decommissioning work such as problems with wage payments and dosimeter deficiency [287].

On 20 October 2015, MHLW recognized, for the first time, as an occupational disease the leukemia developed by a worker who had carried out decommissioning tasks after the Fukushima accident. [288] The worker, who was in his thirties at the time, had performed tasks involving radiation exposure for 18 months, starting in October 2011. During that period, he had worked for about one year at the Fukushima Daiichi site, beginning in October 2012. According to media reports, he was exposed to a total of about 20 mSv; specifically, he was exposed to about 16 mSv at Fukushima nuclear power plant site and about 4 mSv at Genkai NPP site of Kyushu Electrics. [289]

Although the standard for recognizing a worker’s leukemia as an occupational disease is exposure to more than 5 mSv/year of radiation, MHLW stated that “this recognition does not prove scientifically the causal relationship of radiation exposure and its health effects”. [290]

Offsite Challenges

Current Status of Evacuation

The Reconstruction Agency set the five years following the earthquake of 2011 as the intensive reconstruction period, and the term from April 2016 to March 2021 as the reconstruction and revitalization period.  [291] However, there have been many delays with the reconstruction efforts over the past five years.

As of May 2016, 92,600 Fukushima Prefecture residents had been forced to evacuate from their homes: Specifically, 50,600 people had evacuated to other areas within Fukushima Prefecture. The remaining 42,000 people had evacuated to other prefectures across Japan. [292]

As of September 2015, which are the latest available figures, about 70,000 people have been evacuated from the designated evacuation zones due to the Fukushima accident: specifically, about 24,000 people were evacuated from the difficult-to-return zone, about 23,000 people from the restricted-residence zone, and 24,000 people from the zone in preparation for the lifting of the evacuation order. [293]

As of the end of September 2015, the total number of disaster-related deaths—i.e. deaths that were not caused directly by the earthquake and tsunami but were due to indirect causes such as deterioration of physical conditions as a result of evacuation—was 3,407 people. These people had been living in nine prefectures and Tokyo. Of these, Fukushima Prefecture had the highest number with 1,979 deaths. [294] This figure is particularly high among people who evacuated from cities and towns within evacuation zones such as Minami-soma, Tomioka and Namie.

Moreover, according to the statistics collected by the Cabinet Office, the number of suicides related to the Great East Japan Earthquake has decreased everywhere else but Fukushima Prefecture (see Table 7). [295]

The government is aggressively seeking to lift evacuation orders. In June 2015, the government announced that they will enable the lifting of evacuation orders for all restricted residence zones and zones in preparation for the lifting of the evacuation order by March 2017 [296]. If this plan materializes, 47,000 people will be allowed to return to their homes.

Table 7: Suicides Related to the Great East Japan Earthquake

Notes:      [1] The value of 2011 is a total from June to December. The values from 2012 onwards are the total from January to December.

         [2] Total number of three prefectures (Ibaraki, Saitama, Kanagawa) and Osaka, Kyoto and Tokyo.

Source: Cabinet Office, “Number of suicides related to the Great East Japan Earthquake”, 13 March 2016.

However, evacuees have mixed feelings. In February 2016, the government held a briefing in Minami-soma city and stated that they hope to lift the evacuation order in April. In response to this, numerous residents commented that it is too soon to lift the order since progress has been slow in implementing decontamination activities. [297] In March 2016, Fukushima Prefecture released the results of its questionnaire survey. Among the people who had evacuated to other prefectures and had no home to return to in Fukushima Prefecture after April 2017—when the program for offering rental houses free of charge will be terminated—about 70 percent did not wish to return to Fukushima while about 10 percent wanted to return to the prefecture and about 20 percent responded that they are still debating on whether or not to return. [298]

Radiation Exposure and Health Effects

Fukushima Prefecture is continuing its health survey, which includes assessments of external and internal doses and thyroid examinations. [299] In regard to the thyroid examination, the preliminary survey—ultrasound wave examination for residents who were under 18 years old or younger and lived in Fukushima Prefecture at the time of the accident—was conducted from October 2011 to March 2014. As of the end of June 2015, 113 people were diagnosed with confirmed or suspected thyroid cancer. [300] Of these, 99 people underwent surgery.

However, the Prefectural Oversight Committee Meeting for Fukushima Health Management Survey concluded:

As a judgment based on a comprehensive assessment of the following facts, it is unlikely that the thyroid cancers discovered until now were caused by the effects of radiation: the exposure doses were generally smaller compared to those of the Chernobyl accident, the period from exposure to cancer detection was short ranging from about one to four years, cancer was not found in those aged five years old or younger at the time of the accident, and there was no significant difference in the regional detection rates.

The first full-scale survey was conducted from April 2014 to March 2016, involving the subjects of the preliminary survey and children who were born after the accident including those in utero at the time of the accident. If nodules or cysts that are larger than a predetermined size are found in the primary first examination, those people undergo a confirmatory examination.

Table 8: Confirmed or Suspected Thyroid Cancer Cases and Effective External Dose Estimates

Source: Prefectural Oversight Committee Meeting for Fukushima Health Management Survey, “Thyroid Ultrasound Examination (Full-scale Thyroid Screening Program)”, 15 February 2016.

As of the end of December 2015, 51 people were diagnosed with confirmed or suspected malignant thyroid cancer in the second examination. Unfortunately, only 29 of them submitted a basic survey questionnaire that provides data on their exposure dose at the time of the accident. Among these values, the highest dose was 2.1 mSv (see Table 8). [301]

In October 2015, a research group at Okayama University published an epidemiological study related to the high occurrence of childhood thyroid cancer.  [302] According to the group, based on the results of the screening tests of Fukushima Prefecture, at the maximum, the incidence of thyroid cancer in a certain area of Fukushima Prefecture was up to 50 times higher than Japan's average annual incidence of thyroid cancer incidences. Accordingly, the group concluded that the excessive occurrence of thyroid cancer has already been detected. However, the methodology of this paper has been criticized and the academic debate on this issue is continuing. [303]

Food and Environmental Contamination

The intake and shipment of certain edible wild plants and freshwater fish have been restricted due to the contamination risk. [304] Although fishermen have placed a voluntary restriction on fishing in the waters within 20 km from the Fukushima power plant site, a study is being conducted that hopes to restart fishing in that area.

Most food samples analyzed for radioactive contamination were non-contaminated or contaminated at levels “below the detection limit”, except for rare cases in prefectures adjacent to Fukushima. For example, 263 cases (0.09 percent) exceeded the standard limits in the monitoring from April 2015 to January 2016.  [305]

It should be noted that regarding the term “Not Detected (ND)”, which has been frequently used in government reports, a recent study proposes a review of the detection limit. [306]

The Ministry of the Environment has continued to monitor wild animals and plants. For example, at a scientific meeting held in February 2016, a study conducted in FY2014 was presented that evaluated the exposure-dose rates of about 40 types of animals and plants. According to this study, there is an undeniable possibility that reproductive rates lowered and life expectancy shortened in some species in certain areas. [307] Another study demonstrates that the closer the area is to the Fukushima nuclear power plant, the lower the number of habitats and species of invertebrate organisms. [308]

The government has set two decontamination goals:

1. To incrementally reduce the size of the areas, but as soon as possible, with levels at 20 mSv/year or higher;

2. Reduce the exposure dose rate to 1 mSv/year or less over a long-term period for the areas with levels at less than 20 mSv/year.  [309]

Decontamination work in the designated areas to be decontaminated under the direct control of the government was completed in six municipalities among the 11 designated municipalities within Fukushima Prefecture and the plan is to finish decontamination in the remaining municipalities by the end of FY2016  [310] However, little progress has been made in the decontamination activities implemented by each local government for the wider area that covers seven prefectures including Fukushima [311].

As for the rates of progress made in the decontamination activities for the entire Fukushima Prefecture, 80 percent of houses, 5 percent of roads, and 70 percent of the forests in areas, where daily activities are conducted, have been decontaminated. [312] However, it should be pointed out that by “forest” is meant in general a small band around houses and roads, rather the actual dense forests, that cannot be decontaminated at all. In December 2015, the Ministry of Environment announced that they will not decontaminate areas more than 20 km away from daily-activities areas in Fukushima Prefecture.  [313] However, as a result of local opposition, the ministry changed the policy to carrying out decontamination in satoyama areas—border zones of agricultural land and forested land traditionally regarded as one area—where people may enter easily. [314]

Costs [315]

TEPCO continues to pay compensation for damages caused by the Fukushima accident. Legally required compensation costs have been increasing and the total reached about 7.1 trillion yen (US$71 billion) as of the end of March 2016. Table 9 shows the legally required compensation costs and the amount of agreed-upon compensation payments that had been paid as of March 2016.

Table 9 : Compensation Costs

[1] As of the end of February 2016

[2] As of the end of March 2016

Source: TEPCO, “New Comprehensive Special Business Plan”, 31 March 2016.

According to the estimation of the Board of Audit in March 2015, it will take up to 30 years for  TEPCO to repay the financial subsidies of 9 trillion yen (US$90 billion) it received from the government. [316]

Based on the information from TEPCO, the total cost of damages caused by the Fukushima disaster has been estimated to be at 13.3 trillion yen (US$ 133 billion), based on the following items:

(1) Decommissioning and contaminated water treatment costs of 2 trillion yen. Although TEPCO already set aside a reserve of 1 trillion yen (US$ 10 billion), the government asked the utility to secure another 1 trillion yen (US$ 10 billion) within 10 years.

(2) Compensation costs of about 7.1 trillion yen (US$ 71 billion). The total of the legally required compensation costs according to the latest data is about 7.7 trillion yen (US$ 77 billion), see Table 9.

(3) Decontamination costs of 3.6 trillion yen (US$ 36 billion): The Ministry of the Environment has estimated the decontamination cost at about 2.5 trillion yen (US$ 25 billion) and the interim storage facilities cost at about 1.1 trillion yen (US$ 11 billion).

Fukushima vs. Chernobyl

“We knew, with certainty, with arrogant certainty, that we were in control of the power we were playing with. We could make the forces of nature bend to our will. There was nothing we could not do. This was the day, of course, when we learned we were wrong.”

Sergiy Parashyn

Engineer at the Chernobyl plant

from 1977 to the day of the disaster [317]

Although the Fukushima disaster in 2011 remains very serious, according to some criteria, its effects seem to pale in comparison to the Chernobyl nuclear disaster in 1986. However, it must be noted that all of these numbers are based on modelling with large ranges of uncertainties.

According to Japan’s Science Ministry,  [318] the Fukushima accident contaminated an area of 30,000 km2 in Japan to a level above 10,000 Bq per km2 of Cs-137. Chernobyl contaminated an area of an estimated 1,437,000 km2 in Europe and the former USSR above this level, a 50 times larger area. [319] The Japanese Science Ministry also stated that 8 percent of Japan’s land area was contaminated to this level. [320] In comparison, 37 percent of Europe was affected to the same level.

Table 10 indicates that it was not just the land areas contaminated and collective doses but also the radionuclide amounts released to the air, and the populations affected that were larger by land contamination. In all parameters listed, Chernobyl’s effects were greater than those at Fukushima. Little is known about total discharges to the sea, from aerial disposal and from direct liquid releases.

Table 10 : Comparison of Selected Parameters of the Chernobyl and Fukushima Accidents

Sources: *UNSCEAR 2013 [323]; **TORCH-2016 [324]; ^ Japanese Science Ministry [325], +Fairlie (2016) [326]

Source Term

There are various estimates of the amounts of radioactivity emitted to air, the so-called air source term, from Chernobyl and Fukushima.

Table 11 provides estimates for the main nuclides released according to Fairlie [327], Imanaka et al. [328] and UNSCEAR [329].

Table 11 : Comparison of Atmospheric Releases from Nuclear Accidents (in PBq) [330]

The key points here are:

• Broad agreement about source terms on Cs-137 and Xe-133. Wide range of I-131 estimates by UNSCEAR at Fukushima.
• Release estimates for Chernobyl are much larger than those for Fukushima, about ten times greater for Cs-137 and I-131 which are the main volatile nuclides. For the noble inert gas Xe-133, the situation is reversed, as releases from Fukushima were about double those from Chernobyl. The main reason is that at Chernobyl one reactor exploded whereas at Fukushima, meltdowns occurred at three units, with each reactor releasing its entire gaseous inventory.

Radiation Exposures

The calculation of radiation exposure is based on complex modelling of exposure paths (external, internal, air, food path, etc.), as the actual doses delivered to the body have been measured only partially for a small number of people. Therefore, the exposure numbers indicated throughout this chapter have to be considered with circumspection. Also, radiation risks between a fetus and a grown-up adult vary by two orders of magnitude, and risks show high variability between individuals.

indicates that, in the highest contaminated areas resulting from Chernobyl, the average dose was 9 mSv in the first year after the accident. This is similar to the average dose received in the most contaminated area of Japan in Fukushima prefecture.

However, the average thyroid dose in Belarus and Ukraine was about 20 times greater than in Fukushima prefecture. This is because the I-131 release was about 10 to 12 times greater at Chernobyl than Fukushima and because an estimated (~80 percent) of the plumes at Fukushima were blown out to sea. [331]

Table 12: Average Doses in Fukushima and Chernobyl (Highest Contaminated Areas)

Source: UNSCEAR 2008, 2013

As regards collective dose, the UNSCEAR 2013 report states:

The collective effective dose to the population of Japan due to a lifetime exposure following the Fukushima accident is approximately 10-15 percent of the corresponding value for European populations exposed to radiation following the Chernobyl accident. Correspondingly, the collective absorbed dose to the thyroid was approximately 5 percent of that due to the Chernobyl accident.

This is shown in tabular form in Table 13.

Table 13 : Collective Doses from Fukushima and Chernobyl Accidents (over 80 years)

Source: UNSCEAR 2008, 2013

Nuclear Power vs. Renewable Energy Deployment

Introduction

The December 2015 United National Framework Conference on Climate Change (UNFCCC) in Paris is rightly seen as an important milestone in the global fight to avoid dangerous climate change. The foundation of the conference’s outcome was the national pledges for mitigation actions through until 2030; while voluntary, they have a formal reporting and review mechanism. The Paris agreement noted that these pledges, when aggregated, did not meet the objective “with holding the increase in the global average temperature to well below 2 °C above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5 °C above pre-industrial levels”.

For the Paris Agreement 162 national pledges called Intended National Determined Contributions (INDCs) were submitted to the UNFCCC covering around 95 percent of global emissions in 2010 and 98 percent of the global population. The extent to which nuclear power is included within these plans is limited as just 31 countries currently operating nuclear power, therefore, only around one in five Paris pledges. Furthermore, expansion of the sector, through construction of new reactors, is only taking place in 12 of these countries with an additional two countries, Belarus and United Arab Emirates, building for the first time.

Within the actual INDCs only eleven countries mentioned that they were operating or considering to operate nuclear power as part of their mitigation strategy and even fewer (six) actually state that they were proposing to expand its use (Belarus, India, Japan, Turkey and UAE). This compares with 144 that mention the use of renewable energy and 111, which explicitly mention targets or plans for expanding its use as shown in Figure 32. This highlights the extent to which nuclear power is a niche carbon abatement strategy, compared to the use of renewables which is universal.

The limited use of nuclear power to address climate change concerns, especially compared to renewable energies is further demonstrated in the ongoing review of the Paris Agreement. This mandates meetings every five years, starting in 2018, to review progress, and assess how to increase the emissions reduction plans in order to meet the international agreed targets for 2030. However, it is highly unlikely that many, if any, countries will be able to increase their use of nuclear power over and above the level already included in their existing pledges, given the length of time that nuclear power takes to plan, license and build. Therefore, despite the need for greater action to reduce emissions through until 2030, nuclear power is unable to accelerate its deployment—in fact, as other parts of the report illustrate, more units might close than start up—and further decarbonization will heavily rely on energy efficiency and renewable energy.

In the longer term, while most global models assume that a decarbonized energy sector will include a combination of nuclear, fossil fuels with carbon capture and storage and renewables, there are a significant number of well-respected studies that assume a nuclear- and fossil-free energy future. These include:

• The Global Energy Assessment 2012, published by the Cambridge University press, states, “that it is also feasible to phase-out nuclear and still meet the sustainability targets”. [335]
• The Special report of the International Panel and Climate Change (IPCC) on renewable energy from 2011, reviews at a number of scenarios, which limit the use of different supply options, including renewables, nuclear power and Carbon Capture and Storage. Some of these scenarios, show no additional cost associated with the nuclear-free option, while meeting global mitigation targets. [336]
• Global Energy (R)evolution, published and regularly updated by Greenpeace, is a comprehensive 100-percent renewable energy scenario. [337]

Source: INDCs UNFCCC [338]

Therefore, it is not so much a question of having to deploy nuclear in order to decarbonize, but whether or not Governments choose to actively support nuclear power as a means of climate mitigation.

While no energy source is without its economic costs and environmental impacts, what has been seen clearly over the past decade, and particularly in the past few years, is that choosing to decarbonize with nuclear turns out as an expensive, slow, risky and potentially hazardous pathway, and one which few countries are pursuing. In contrast, some renewable energy sources, particularly wind and solar PV, are being deployed at rates significantly in excess of those forecasted even in recent years, [339] entailing rapidly falling production and installation costs.

This section highlights the differences between the deployment rates of nuclear power and some renewable energy technologies on the global level and in key regions and markets.

Investment

The investment decisions taken are not only an important indicator of the future power mix, but they also highlight the confidence that the technology neutral financial sector has in different power generation options. Consequently, they can be seen as an important barometer of the current state of policy certainty and costs of technologies on the global and regional levels.

Sources: FS-UNEP 2015 and WNISR original research

According to data published by Bloomberg New Energy Finance (BNEF) and United Nations Environment Programme (UNEP), global investment in renewable energy—excluding large hydro—was US$285.9 billion in 2015, up from US$273 billion in 2014 and exceeding the previous record of US$278.5 billion achieved in 2011. [340] Figure 33 compares the annual investment decisions for the construction of new nuclear with renewable energy excluding large hydro since 2004. 2014 saw a sharp drop in new nuclear investment, with construction starting on only three units, which were the Barakah-3 in the UAE, Belarus-2 in Belarus and the Carem reactor in Argentina, but in 2015 eight new construction starts took place, with six of these were in China, with the other starts, the final unit, at the Barakah station in the UAE and K-2 in Pakistan, with a total investment cost of US$28 billion. In the absence of comprehensive, publicly available investment estimates for nuclear power by year, and in order to simplify the approach, WNISR includes the total projected investment costs in the year in which construction was started, rather than spreading them out over the entire construction period. Furthermore, the nuclear investment figures do not include revised budgets, if cost overruns occur. However, despite all these uncertainties, it is clear that over this period the investment in nuclear construction decisions is about an order of magnitude lower than that in renewable energy, with nearly five times more investment in solar and four times more in wind.

Table 14: Top 10 Countries for Renewable Energy Investment 2013–2015

Source: FS-UNEP 2016, 2015, 2014

The past few years have seen the significant rise of investments into small (less than 1 MW) distributed generation and in 2015, they accounted for a quarter of all renewable energy investments, US$67.4 billion, up 12 percent from the previous year, but still down from the record high of US$79.3 billion in 2012. The fall in global investment is a result of slowing down of solar programs in Europe, and particularly Germany, as well as dramatically lower costs. Interesting to note is the rise of investment in Japan, US$36.2 billion in 2015, up 0.1 percent. [341] The increased investment in solar, and its impact on lowering global prices, remains one of the underestimated global impacts of the Fukushima accident in 2011.

Globally, the importance of Europe for renewable energy investments is diminishing, with the rise of Asia, and in particular China and Japan. Ten years ago, in 2005, total investment in China was just US$8.3 billion and is now an order of magnitude larger. Table 14 shows the top 10 countries for renewable energy investment in 2015 and how these have changed over the previous two years. The diversity of renewable energy development is now clear, and 2015 saw Mexico and Chile, entering the top 10 for the first time, with both countries having approximately doubled their annual renewable investment.

Installed Capacity

Globally, renewable energy continues to dominate new capacity additions. In total 147 GW of renewables capacity was added in 2015, according the REN 21, which was the largest increase ever.

Sources: WNISR, BP Statistical Review 2016

In 2015, renewables accounted for an estimated more than 60 percent of net additions to global power generating capacity. Wind and solar PV both saw record additions for the second consecutive year, making up about 77 percent of all renewable power capacity added in 2015. [342] BP figures indicate an increase in 2015 over the previous year of 63 GW in wind power and 50 GW of solar, [343] compared to a 6.5 GW increase for nuclear power.

Figure 34 illustrates the extent to which renewables have been deployed at scale since the new millennium, an increase in capacity of 417 GW for wind and of 229 GW for solar, compared to the stagnation of nuclear power capacity, which over this period increased by only 27 GW, including all reactors in LTO. Taking into account the fact that 35 GW of nuclear power are currently in LTO and not operating, the balance turns negative and 8 GW nuclear less are in operation than in 2000.

Electricity Generation

The characteristics of electricity generating technologies vary and different amounts of electricity are produced per installed unit of capacity. In general, over the year, nuclear power plants tend to produce more electricity per MW of installed capacity than renewables.

Sources: BP, MSC, 2016

However, as can be seen, since 1997, the signing of the Kyoto Protocol, there has been an additional 829 TWh per year of wind power, 252 TWh more power from solar photovoltaics, and just an additional 185 TWh of nuclear electricity (see Figure 35).

In 2015, annual growth rates for the generation from wind power was over 17 percent globally, while it was over 33 percent for solar PV and 1.3 percent for nuclear power. In terms of actual production, nine of the 31 nuclear countries—Brazil, China, Germany, India, Japan, Mexico, Netherlands, Spain and U.K.—now all generate more electricity from non-hydro renewables than from nuclear power.

Status and Trends in China, the EU, India, and the U.S.

China continues to be a global leader for most energy technologies. In 2015, China installed more wind power and solar photovoltaics than any other country (see Figure 36), so worldwide, it now has the largest capacities of both, wind power and solar PV. In 2015, China has overtaken Germany in deployed PV capacity. Having started up eight of the world's ten reactors, China also installed more nuclear capacity in 2015 than any other country.

Sources: BP Statistical Review, IAEA PRIS 2016

Investment in renewables in China was by far the largest in the world with a total of just under US$103 billion up from US$83 billion the previous year. In 2015, investment in solar PV was US$43 billion and wind power was US$42 billion,  [344] that compares to the start of construction on six new nuclear power plants, with Capex of an estimated, based on government figures, of around US$18 billion. [345]

The 13 th Five Year Plan (2015-2020) proposes new targets for energy efficiency, the reduction of carbon intensity as well as diversification away from fossil fuels, whereby non-fossil fuels are to provide 15 percent of primary energy consumption by 2020, up from 7.4 percent in 2005. [346] Consequently, the explosive growth of renewables is expected to continue with a likely increase of installed capacity of approximately 19.5 GW of solar PV in 2016. Officials from China’s National Energy Administration (NEA) are considering raising the 2020 solar target from 100 GW to 150 GW, which would bring about 21 GW of annual installation between 2016 through to 2020. [347]

Sources: BP Statistical Review, IAEA-PRIS 2016

The 13 th Five Year Plan is also proposing to increase the installed capacity of wind to 250 GW by 2020. [348] Chinese officials envisage that there will be 58 GW of nuclear capacity in operation by 2020, [349] up from 29.4 GW in mid-2016. However, the 21 units with 21.5 GW under construction will not be sufficient to reach the target. And the average construction time of the 25 units that China brought on line over the past decade was 5.7 years and many of the units under construction encounter significant delays. It appears therefore practically impossible for the country to reach its 2020 nuclear target.

While the power sector in China continues to be dominated by coal, the growth rate of non-fossil fuels is still impressive. This increase in electricity production is delivering changes in the power mix. While China's the nuclear buildup is fast—production increase by a factor of over three in 10 years, a factor of ten in 15 years—the renewable energy deployment has been breathtaking. In a decade Wind power increased generation from virtually nothing, that is less than 0.1 TWh in 2006 to 185 TWh in 2015. Solar PV went from less than 1 TWh in 2010 to 39 TWh in 2015 (see Figure 37).

In the European Union, between 2000 and 2015, the net changes in the capacity of power plants are estimated to be an increase of 129 GW in wind, 99 GW in natural gas and 96 GW in solar, while there have been decreases in nuclear by 14.8 GW, coal 28.3 GW and fuel oil by 28.2 GW.  [350]

Figure 

 Source: European Wind Energy Association (EWEA) 2016 [351]

Sources: BP Statistical Review [352], IAEA-PRIS 2016

EU 2015 renewable electricity production highlights included:

• In Germany, renewable energy sources – solar, wind, hydropower, and biomass – provided 30.1 percent of gross national electricity consumption.
• Denmark had another record year, with wind power providing a 42 percent of the Danes’ electricity consumption.  [353]
• In Spain, more electricity was produced by solar PV and wind power, than nuclear. While all renewables combined produced more electricity than the total from fossil fuels. [354]
• In the U.K., renewables’ (including hydro) share of electricity generation increased to 24.7 percent, from 19.1 per cent in 2014. In total 83.3 TWh of power were produced by renewables, compared to 63.9 TWh for nuclear (18.9 percent). [355]

Compared to Kyoto Protocol Year 1997, in 2015 wind added 300 TWh and solar108 TWh, while nuclear power generation declined by 80 TWh across the EU as can be seen in Figure 39.

This growth in installed renewables capacity is set to continue beyond the current 2020 targets, as in preparation of the UN climate meeting in Paris in December 2015, the EU has agreed a binding target of at least 27 percent renewables in the primary energy mix by 2030, which is likely to mean 45 percent of power coming from renewables. This will require an escalation of the current rate of renewable electricity deployment. There is no EU-wide nuclear deployment target and the nuclear share has been shrinking for decades.

India has one of the oldest nuclear programs, starting electricity generation from fission in 1969. It is also one of the most troubled nuclear sectors in the world and has encountered many setbacks (see India section in Asia

Sources: BP Statistical Review, IAEA-PRIS 2016

This is in stark contrast to the more recent but steady development of the renewable energy sector.  Figure 40 shows, how, since the turn of the century, the wind sector has grown rapidly and has overtaken nuclear’s contribution to electricity consumption since 2012, while solar is also growing rapidly. India has moved up the league of countries of global importance for renewable energy investment as a whole, with US$10.2 billion in 2015. It is also on the 5th position for non-hydro renewables power generation and the fourth most important for installed capacity for wind. [356]

Further increases in the growth in renewables are expected in the coming decade; in 2014 a 2022 target of 175 GW of renewable-based power capacity (excluding large hydropower) was announced. Of this total, 100 GW is to be solar (compared to 731 MW in 2014), 60 GW wind (compared to 22.4 GW in 2014), 10 GW biomass-based power, and 5 GW small hydropower projects.

In the United States, power demand remained largely static in 2015 as it has for the past decade, however underlying this are significant changes in the supply mix. In 2007, the historic peak for consumption, coal accounted for 48 percent of the power mix, but since coal’s power production has fallen by nearly 500 TWh, to 1,356 TWh in 2015 or just 33 percent of the total. The largest part of this decline has been met by the increased use of natural gas—essentially shale gas—producing an additional 347 TWh compared to 2007 and equaling the share of coal for the first time in 2015. However, non-hydro renewables, have also grown considerably, increasing by 143 TWh, providing 2.7 percent in 2007 and 7.9 percent in 2015. Over the same period the output from the country’s nuclear power plants remained approximately constant. With the current rate of increase of renewables and flat or falling production from nuclear power, by the early part of the next decade renewables, including hydro-power, are likely to exceed production from nuclear power. [357]

In 2015, a total of 16 GW of new renewable capacity was installed, of which 8.5 GW was wind and 7.3 GW was solar PV [358], the majority of new installed capacity with little change in the nuclear sector. This trend is likely to continue as the U.S. Clean Power Plan will regulate the country’s power sector, aiming to cut emissions by 32 percent relative to 2005 levels by 2030, accelerating the current trends of closure of coal and the installation of solar and wind and as we have seen in the country section, little new construction of nuclear and a likely acceleration of the closure rate of reactors in unregulated power markets.

Conclusion on Nuclear Power vs. Renewable Energies

The gulf between the development of new renewables, primarily wind and solar, and nuclear power is growing wider year by year. This can be measured, by the number of countries actively supporting the expansion of the technologies, for climate, energy access or economic reasons, or by the subsequent levels of investment, capacity increases or new generation put into the grid.

Furthermore, with rising nuclear construction costs contrasting rapidly decreasing prices for renewable technology this trend is likely to accelerate, in particular if decarbonization objectives agreed in Paris in December 2015 are adhered too. Nuclear power, even in countries that have or are considering to deploy it, will increasingly play a junior role to renewable energy which is already the case in many of the world’s largest economies, such as Brazil, China, Germany, Japan and the U.K.. However, in the 163 U.N. Member States that don’t use nuclear power, renewables are likely to flourish even faster in the coming decades, which will bring further technological and subsequent economic improvements, further marginalizing nuclear power.

Footnotes

Annex 1: Overview by Region and Country