This annex provides an overview of nuclear energy worldwide by region and country. Unless otherwise noted, data on the numbers of reactors operating and under construction (as of July 2013) and nuclear’s share in electricity generation are from the International Atomic Energy Agency’s Power Reactor Information System (PRIS) online database. Historical maximum figures, provided in parentheses, indicate the year that the nuclear share in the power generation of a given country was the highest since 1986, the year of the Chernobyl disaster. Load factor figures are drawn from Nuclear Engineering International, May 2013, unless otherwise noted.



Africa ↑

South Africa has two French (Framatome/AREVA) built reactors. They are both located at the Koeberg site east of Cape Town, which supplied 12.4 TWh or 5.1 percent of the country’s electricity in 2012 (the historical maximum was 7.4 percent in 1989). The reactors are the only operating nuclear power plants on the African continent.

The state-owned South African utility Eskom launched an effort in 1998 to develop the Pebble Bed Modular Reactor (PBMR), a helium-cooled graphite-moderated reactor based on earlier German designs. What happened then has been summed up by the Energy Economist this way: “The project was running about 25 years behind its original schedule, the estimated cost of a demonstration plant had increased 30-fold and a design fit to submit to the regulator had still not been completed.” [1] In September 2010, the Government “[dropped the] final curtain on PBMR,” a few months after having terminated all public support. [2] Some $1.3 billion had been invested in the project, with more than 80 percent coming from the South African Government. [3]

The failure of the PBMR led Eskom to consider buying additional large Pressurized Water Reactors (PWR). In the longer term, it planned to build 20 gigawatts (GW) of nuclear plants by 2025. However, in addition to escalating cost projections, Eskom faced a challenge of a falling credit rating, reduced by Moody’s in August 2008 to Baa2, the second-worst investment grade. In November 2008, Eskom scrapped an international tender because the scale of investment was too high.

In February 2012 the Department of Energy published a Revised Strategic Plan that still contained a 9.6 GW target, or six units for nuclear power by 2030. Startup would be one unit every 18 months beginning in 2022. [4] The South African Government has repeatedly reiterated the 2030 target and Deputy President Kgalema Motlanthe stated, most recently at the “Nuclear Africa 2013” conference, that the country “will continue to develop and promote nuclear energy”. [5] However, he also noted: “Admittedly, the use of nuclear energy to mitigate greenhouse gases remains controversial. We remain committed to invest in clean energy from multiple sources.”

While government support for nuclear power seems little influenced by the events in Fukushima, the construction industry warns that current projects are running late and over budget. Mile Sofijanic, Managing Director at Concor Engineering: “If we follow the trend, could the NPP programme cost, not R300-billion [USD33bn], but R750-billion [USD82bn]? That is not acceptable!” [6] One of the issues identified by Sofijanic: “We have a lack of skills. That is factually correct.”

Russia’s Rosatom has high hopes for South Africa and offered a full package including extensive human capacity-building and progressive increase of local input. “Localisation will at the initial stage of the project be at 30 percent of production, which will eventually peak at 65 percent”, for units seven and eight, said Alexander Kirillov, head of Rosatom’s marketing office in South Africa. [7] Apparently, Russia’s President Vladimir Putin told his South African counterpart in March 2013 that they would “offer(ed) different funding options” for the nuclear new-build programme, should a Russian bid be chosen. [8]

In June 2012, the Energy Minister stated that Government would make a decision on its nuclear future by the end of the year. [9] By March 2013, the prospects were dim to get to the point even a year later, according to trade journal Nuclear Intelligence Weekly:

South Africa’s latest budget seems to leave little room for optimism for those hoping that the government will decide this year to go forward with its proposed 9.6 GW of new nuclear power. The government allocated 709.9 million rand ($78.4 million) for nuclear-related programs and subsidies, less than half the 1.623 billion it allocated for clean energy programs and subsidies. [10]

This may reflect a long-awaited shift towards faster, simpler, lower-cost options. Anton Eberhard, a professor at the University of Cape Town’s Graduate School of Business and a member of the National Planning Commission, concluded from recent modelling:

South Africa can achieve electricity supply security without investing in further nuclear power. Alternative power sources are cheaper and they can also help us achieve our Copenhagen pledges to reduce carbon emissions. [11]

Eberhard also stressed that the Independent Power Producers (IPP) renewable energy procurement program was “highly successful” and “raised R47bn [USD5bn] in its first round”. Meanwhile, the Energy Minister’s Statement in “response to the UN Secretary General’s call for sustainable energy for all (SE4ALL)” does not contain the term “nuclear”. [12]



The Americas ↑

Argentina operates two nuclear reactors that, as in 2011, provided 5.9 TWh or 4.7 percent of the country’s electricity in 2012 (down from a maximum of 19.8 percent in 1990).

Historically Argentina was one of the countries that embarked on an ambiguous nuclear program, officially for civil purposes but backed by a strong military lobby. (An advisor to President Galtieri once said at a press conference that his country had even built a duplicate, unsafeguarded, reprocessing plant. Argentina also reopened its uranium enrichment plant in 2010, and was revealed on 1 July 2013 [13] to have exported 80–100 tons of uranium oxide to Israel, presumably for its nuclear weapons program.) Nevertheless, the two nuclear plants were supplied by foreign reactor builders: Atucha-1, which started operation in 1974, was supplied by Siemens, and the CANDU type reactor at Embalse, which was supplied by the Canadian AECL. After 28 years of operation, the Embalse plant is supposed to get a major overhaul, including the replacement of hundreds of pressure tubes, to operate for potentially 25 more years. [14] Reportedly, contracts worth $440 million were signed in August 2011 with the main work to start by November 2013. Work is expected to take five years at a total cost of $1.37 billion. [15]

Atucha-2 is officially listed as “under construction” since 1981. In 2004, the IAEA estimated that the start-up of Atucha-2 would occur in 2005. Since then, the IAEA has kept adjusting the expected “first grid connection” date, which, as of 6 July 2013 is still given as 1 July 2013, exactly 32 years after construction start. In June 2013, the Government announced that the project would be completed within two months. [16] That date came and went. The President “pre-started” the plant in a 2011 “inauguration” ceremony, but it apparently remains under construction two years later.

The presidents of Argentina and Brazil, Fernández de Kirchner and Lula da Silva-whose countries had long been potential military nuclear rivals-, met in February 2008 and agreed to “develop a program of peaceful nuclear cooperation that will serve as [an] example in this world.” [17] In early May 2009, Julio de Vido, Argentina’s Minister of Planning and Public Works, stated that planning for a fourth nuclear reactor would be under way and that construction could start as early as within one year. [18] It did not. Neither a siting decision, nor a call for tender, has been reported to date.

After repeated delays construction of a prototype 27 MWe PWR, the domestically designed and built CAREM25 (a type of pressurized-water Small Modular Reactor with the steam generators inside the pressure vessel), was scheduled to begin in the first half of 2013 (but was not reported) near the Atucha site with fuel loading planned for the second half of 2017. [19]

The Argentinian public’s opposition to nuclear power was only reinforced by Fukushima. In a September 2012 update of a 24-country IPSOS study, 71 percent of the Argentinians polled opposed nuclear new-build, a score just below Italians, Germans and Mexicans. [20]

Brazil operates two nuclear reactors that provided the country with 15.2 TWh (the historic maximum) or 3.1 percent of its electricity in 2012 (down from a maximum of 4.3 percent in 2001). The record electricity generation, which still contributes only modestly to the power supply in the country, is due to an excellent load factor of 91 percent (+5 percent compared to 2011, 28 percent better than the lifetime load factor).

As early as 1970, the first contract for the construction of a nuclear power plant, Angra-1, was awarded to Westinghouse. The reactor went critical in 1981. In 1975, Brazil signed with Germany what remains probably the largest single contract in the history of the world nuclear industry for the construction of eight 1.3 GW reactors over a 15-year period. However, due to an ever-increasing debt burden and obvious interest in nuclear weapons by the Brazilian military, practically the entire program was abandoned. Only the first reactor covered by the program, Angra-2, was finally connected to the grid in July 2000, 24 years after construction started.

The construction of Angra-3 was started in 1984 but abandoned in June 1991. However, in May 2010, Brazil’s Nuclear Energy Commission issued a construction license and the IAEA indicated that a “new” construction start occurred on 1 June 2010. In early 2011, the Brazilian national development bank BNDES approved 6.1 billion Reias ($3.6 billion) for work on the reactor, mainly to be carried out by AREVA. [21] The IAEA now envisages commercial operation for 1 January 2016. Other sources indicate “commissioning” planned for July 2016. [22]

In January 2011, Brazil’s Energy Minister Edison Lobao stated that the Government planned to approve the construction of four additional reactors “this year.” [23] Right after 3/11, Lobao assured: “We have no need to revise anything, except for learning from what happened in Japan, and taking a look at future proceedings.” [24] In early May 2012, a top-level Brazilian Government official announced that the country will not proceed with the previously stated plans to launch up to eight new nuclear power plants. “The last plan, which runs through 2020, does not envisage any (new) nuclear power station because there is no need for it”, the energy ministry’s executive secretary Marcio Zimmermann stated. “Demand is met with hydro-electrical power and complementary energy sources such as wind, thermal and natural gas.” According to press agency AFP, the official also announced that over the coming decade the level of renewable energy would double from 8 to 16 percent. [25]

Public opinion is still helping the government to look for other solutions than nuclear. In the IPSOS’s updated 24-country study support for nuclear energy increased by 10 percent but 63 percent of the population polled remain opposed to nuclear energy in general. [26]

Canada operates 19 reactors, all of which are CANDU (CANadian Deuterium Uranium), providing 90 TWh or 15.3 percent of the country’s electricity in 2012 (identical to 2011, down from a maximum of 19.1 percent in 1994). Two reactors have been restarted in 2012 after 15 and 17 years shutdown periods. On 28 December 2012, Gentilly-2, Québec’s only remaining nuclear reactor, was closed.

There have been significant delays in restarting six of originally eight reactors in long-term-shutdown (LTS). In December 2012, the LTS status of the two 40-year old Pickering-2 and -3 was “retroactively changed to Permanent Shutdown” in May 2007 and October 2008 respectively. In January 2010, operator Ontario Power Generation (OPG, Ex-Ontario Hydro) requested a five-year license renewal for the four Pickering-1 to -4 [27] reactors, but in July 2010 the Canadian Nuclear Safety Commission (CNSC) decided to limit the license to three years. For all remaining six Pickering units, the licenses expired on 30 June 2013. [28] However, these licenses were extended for two months (to August 2013) in late June 2013. [29] The two other units that had been in long-term shutdown, Bruce-1 and -2, were reconnected to the grid on 19 September and 16 October 2012 respectively.

In May 2012, the Government accepted the Environmental Impact Assessment report for the construction by OPG of up to four units at the Darlington site. On 17 August 2012, the CNSC issued a “Site Preparation Licence” for the Darlington project, “a first in over a quarter century”. [30] The next step in the licensing procedure is the submission by OPC of an application for a construction license that will undergo full public hearings.

The province of New Brunswick has abandoned the option of adding a second nuclear reactor at its Point Lepreau site; meanwhile, a massive refurbishment project on the first unit was CAD1 billion over its CAD1.4 billion budget and three years behind schedule. The unit was shut down in April 2008 and was restarted on 26 October 2012. [31]

In June 2011, the Canadian Government sold the commercial reactor division of Atomic Energy of Canada (AECL) to CANDU Energy, a wholly owned subsidiary of engineering company SNC Lavalin for CAD15 million plus royalty payments from potential future new-build and refurbishment projects. There is no assurance that such projects will materalize.

In Mexico, two General Electric reactors operate at the Laguna Verde power plant, located in Alto Lucero, Veracruz. The first unit was connected to the grid in 1989 and the second unit in 1994. In 2012, nuclear power produced 8.4 TWh or 4.7 percent of the country’s electricity (down from a maximum of 6.5 percent in 1995). An uprating project carried out by Iberdrola between 2007 and early 2011 boosted the nameplate capacity of both units by 20 percent to reach 765 megawatts (MW) each. However, work continued until February 2013 while the plant remained officially in operation but the average load-factor of the two reactors plunged from 84 percent in 2011 to 64 percent in 2012. The power plant is owned and operated by the Federal Electricity Commission (Comisión Federal de Electricidad).

In March 2012, former Energy Minister Jordy Herrera stated: “We have to put the option of building and expanding our nuclear plants on the table”. [32] His successor, Pedro Joaquín Coldwell, who was appointed in November 2012, in a speech to a recent OECD conference, stressed the “extraordinary potential” of Mexico’s energy industry, “particularly in the renewable and fossil fuels sectors”. [33] He did not mention nuclear power at all.

Also, public opinion remains a major headache for the nuclear industry in the country with 74 percent opposing nuclear power in general, according to a September 2012 update of an IPSOS 24-country survey. [34]

United States

The United States has more operating nuclear power plants than any other country in the world, with 100 commercial reactors currently operating. This is the lowest number of operating reactors since Chernobyl year 1986. The highest number with 108 operating units was reached in 1990. [35] Four units were closed in the first half of 2013, the first time reactors were shut down since 1998.

The U.S. reactor fleet provided 770.7 TWh in 2012, a 2.5 percent drop over the previous year and 4.5 percent less than in the record year 2010. The average load factor dropped by over 3 percent to 83.2 percent compared to 2011.

The production decline is partially attributed to extended outages of four units that were down most of the year and to a higher level of refueling outages. In 2010, only 49 units were refueled. There have been only three other times since 1995 that fewer than 60 units refueled during a given year (2001, 2004, 2007). [36] Nuclear plants provided 19 percent of U.S. electricity in 2012 (down from a maximum of 22.5 percent in 1995).

First Reactor Closures in 15 Years

In February 2013, nuclear operator Progress Energy, now owned by Duke Energy, decided not to complete repairs and uprating of its 36-year old Crystal River reactor that had been offline since late 2009. This was the first plant closure in the U.S. since 1998. The 825 MWe PWR in Florida had been shut down for regular refueling, maintenance and steam generator replacement when significant deterioration (delamination or cracks) in the concrete containment was identified. Repair was evaluated as a possible option but by 2012 it was concluded that the “nature and potential scope of repairs brought increased risks that could raise the cost dramatically and extend the schedule”. [37] Trade journal Nucleonics Week reported that costs of repairing the containment could have ranged between $1.5 billion and “the worst case”, new walls and dome, $3.4 billion. [38] Work could have stretched between 35 months and 96 months, it was estimated. Under those conditions, Duke Energy’s CEO Jim Rogers concluded: “We believe the decision to retire the nuclear plant is in the best overall interests of our customers, investors, the state of Florida and our company.” [39] Duke Energy intends to put the plant into safe enclosure (SAFSTOR) in order to fully decommission it in 40-60 years.

On 7 May 2013, the second shutdown decision in 15 years in the U.S. led to the permanent closure of the Kewaunee nuclear power plant in Wisconsin. The plant owner Dominion, “one of the nation’s largest producers and transporters of energy” [40] had intended to sell the facility but failed to identify a buyer. The 39-year old 566 MWe single unit reactor was first connected to the grid on 8 April 1974. The decision is particularly remarkable because “despite its operating license being extended for a further 20 years until 2033, no buyer was found”, as the nuclear lobby publication World Nuclear News (WNN) notes. [41] Indeed, the NRC had issued a lifetime extension only in February 2011 [42]. Dominion had bought Kewaunee in July 2005. Dominion has stated in the past that the decommissioning fund of $392 million, transferred when it purchased the plant, would be sufficient to cover the costs. However, as in the case of Crystal River, the reactor will be placed in SAFSTOR.

On 7 June 2013 Southern California Edison (SCE) announced that despite spending over $500 million on repairs and replacement power it would permanently close units 2 and 3 at the San Onofre Nuclear Generating Station (SONGS) after losing a 16 month battle to restart. Unit 1 at the station was closed in 1992. Californian Senator Barbara Boxer, Chairman of the Environment and Public Works Committee, said of the decision: “This nuclear plant had a defective redesign and could no longer operate as intended. Modifications to the San Onofre nuclear plant were unsafe and posed a danger to the eight million people living within 50 miles of the plant”. [43] When announcing the closure Ron Litzinger, SCE’s President said: “We think that our decision to retire the units will eliminate uncertainty and facilitate orderly planning for California’s energy future.” [44]

Aging Reactor Fleet

The last reactor in the US to be completed—in 1996—was Watts Bar-1, near Spring City, Tennessee. In October 2007 the Tennessee Valley Authority (TVA) announced that it had chosen to complete the two-thirds-built 1.2 GW Watts Bar-2 reactor. [45] Questions persist about whether this will prove feasible, let alone economic. Questions persist about whether this will prove feasible, let alone economic.

The lack of new reactor startups leads to the continuous aging of the fleet. Average age stands at 33.4 years (as of May 2013), amongst the highest in the world, with 22 units—every fifth reactor—operating for at least 40 years (up to 44 years). Projects are being developed and implemented to allow reactors to operate for potentially up to 60 years. As of June 2013, 72 of the 100 operating U.S. units have received an extension, another 18 applications are under review by the NRC, and 9 have submitted letters of intent covering a period up to 2019. [46]

First Construction Starts in 35 Years

The George W. Bush administration’s National Energy Policy set a target of two new reactors to be built by 2010, but this objective was not met. To reduce uncertainties about new construction, a two-stage license process was developed. Designs of reactors can first receive generic approval, then utilities need only seek a combined Construction and Operation License (COL) that does not involve questioning of the reactors’ designs.

As of May 2013, the NRC had received 18 licensing applications for a total of 28 reactors. This situation did not change over the past year. (See detailed list in Annex 3 of WNISR 2012). All the applications were submitted between July 2007 and June 2009. Of the 28 reactor projects, eight were subsequently suspended indefinitely or cancelled and at least 16 were delayed. [47]

On 9 February 2012, for the first time in nearly three and a half decades, the NRC granted a COL for Vogtle-3 and -4 units in Georgia. On 30 March 2012, South Carolina Electric & Gas (SCE&G) received the second COL for units 2 and 3 at its Summer site. In an unprecedented move, Gregory B. Jaczko, then Chairman of the NRC, voted against the opinion of the four other Commissioners, stating that the decision was being taken “as if Fukushima never happened”. [48] Jaczko subsequently resigned from his NRC position and is currently writing a book about his experience.

SCANA Corporation, owner of SCE&G, announced the official construction start of the Virgil C. Summer Unit 2 on 11 March 2013, the second anniversary of the Fukushima disaster. On 15 March 2013, first concrete was poured for Vogtle-3. These were the first time in 40 years that a reactor project was started that was subsequently connected to the grid – if indeed that ultimately occurs.

As of May 2013, the NRC had granted four Early Site Permits (ESP) and received two additional applications that are under review. [49] This situation has not evolved over the past two years. ESPs are independent of the construction/operating license. [50] Only the Vogtle project has received an ESP, a COL and a certified design at this stage. The Summer reactors, which received the only other COL and were to start up in 2016 and 2017, have been experiencing repeated delays. Both projects, Summer and Vogtle, “face significant challenges in maintaining the project forecast at or below” budget, the monitor stated. [51] The Economist recently reported that Vogtle is “now perhaps 18 months behind schedule and $737 million over budget. That does not include a further $900 million that is the subject of legal dispute, plus the extra financing costs that will come with these overruns.” [52]

New-build Projects in Trouble

By the end of 2008, nuclear utilities had applied for $122 billion in loan guarantees, and in May 2009 the DOE short-listed four companies for the first group of loan guarantees:

• Southern Nuclear Operating Co. for the two AP1000s at the Vogtle nuclear power plant;

• South Carolina Electric & Gas for two AP1000s at the Summer site;

• NRG Energy for two ABWRs at the South Texas Project site in Texas and

• Constellation for one EPR at the Calvert Cliffs site in Maryland.

By then, the limit for coverage of loan guarantees had been increased from 80 percent of the debt to 80 percent of the total cost. In February 2010, Southern’s Vogtle project was the first to have been awarded a conditional loan guarantee ($8.3 billion) for a nuclear power plant project worth an estimated $14 billion. The reactors were supposed to start operating by 2016 and 2017. As stated above, the first units at the Vogtle and Summer sites are now under construction.

The other two projects are in trouble. Constellation Energy abandoned the application for a loan guarantee for the Calvert Cliffs-3 project after discovering a “shockingly high estimate of the credit subsidy cost” (11.6 percent or $880 million)-a fee legally required to recompense taxpayers for the fair market value of the risk they would undertake by issuing the guarantee. [53] Constellation has since been absorbed by Exelon, and on 1 November 2012, the NRC issued an order terminating the adjudicatory proceeding on the combined license application for Calvert Cliffs 3. [54] On 30 August 2012, the NRC had given French state utility EDF 60 days to find a U.S. based partner for the project to build an EPR at the Calvert Cliffs site in Maryland. Majority ownership, control or domination of a nuclear power plant by a foreign entity is illegal in the U.S. [55] EDF failed to identify a new partner after Constellation had pulled out. EDF lost over $1 billion in this unsuccessful U.S. adventure.

The South Texas Project (STP) is facing the same problem as Calvert Cliffs 3. Nuclear merchant (unregulated) utility NRG, the majority shareholder announced in April 2011 that it was withdrawing from the project, writing down a $481 million investment and excluding any further investment. NRG CEO David Crane said that the Fukushima aftermath was “dramatically reducing the probability that STP 3 and 4 can be successfully developed in a timely fashion.” [56] The proposal was to build two Advanced Boiling Water Reactors (ABWR) at STP, through a company called Nuclear Innovation North America (NINA). NINA was originally a joint venture between Toshiba American Nuclear Energy Corporation (TANE) and NRG. However, after NRG pulled out of the project and according to the NRC letter to NINA “that, although TANE owns about 10 percent of NINA, its overwhelming financial contributions give it significantly more power than is reflected by this ownership stake”. [57] According to Brett Jarmer, an attorney for a coalition of groups opposing the license, “federal law is clear that foreign controlled corporations are not eligible to apply for a license to build and operate nuclear power plants. The evidence is that Toshiba is in control of the project and this precludes obtaining an NRC license for South Texas Project 3 & 4”. [58] Considering the fate of the Calvert Cliffs project, it will be extremely difficult for Toshiba to identify a new U.S. investor.

In early May 2012, Progress Energy, later taken over by Duke Energy, announced that it was delaying its Levy project in Florida for two AP1000 reactors by three years to start-up the first unit in 2024 and the second 18 months later. The “shift in schedule will increase escalation and carrying costs and raise the total estimated project to between $19 and $24 billion”, from a 2008 price tag of $17 billion, the company announced. [59] On 3 May 2013, Duke Energy announced that it had withdrawn the 1998 license request for the construction and operation of two 1000 MWe reactors at the Shearon Harris plant in North Carolina. The company informed the NRC that the plant was no longer needed due to sluggish demand growth forecasts. However, others contest the explanation and suggest that Duke have consistently exaggerated demand growth projections and that the changes in the energy market mean that utilities can no longer keep locking out competitors, especially rooftop solar. [60]

Gas prices in the U.S., due to the accelerated development on non-conventional gas, remain low and increase the uncertainty over the economics of building new nuclear plants. “Let me state unequivocally that I’ve never met a nuclear plant I didn’t like,” said John Rowe, former chairman and CEO of Exelon Corporation, the largest nuclear operator in the U.S. with 22 nuclear power plants. “Having said that, let me also state unequivocally that new ones don’t make any sense right now.” [61] One year after John Rowe’s statement, renewables have spectacularly increased their role as a serious competitor in the power market. In the first three months of 2013, of the 1,546 MWe newly connected to the U.S. grid, 82 percent were renewables (and 47 of the 82 percent was solar), the rest natural gas plants [62]—no coal, no nuclear (see also the section Nuclear vs. Renewables).

Public opposition has also been growing over the past year, according to a March 2012 poll by ORC International. While supporters of new-build stagnated at 46 percent, opponents increased their share from 44 to 49 percent. At the same time, people were split over lifetime extensions with 49 percent in favor and 47 percent opposed. On the other side, 77 percent of the respondents favor the shift of loan guarantees from nuclear to renewable energies. [63]

“The long-term outlook for nuclear generation depends on lifetime of existing capacity”, is the title of an extract of the Annual Energy Outlook 2013 of the U.S. Department of Energy (DOE). [64] The title suggests that even the long-term future of nuclear power is not mainly characterized by the number of new-build projects but by the longevity and number of surviving plants. The DOE has built four scenarios and concludes:

Projected reliance on nuclear power in 2040 varies across cases, providing between 10% and 20% of projected total electricity generation with total capacity between 63 GW and 133 GW.

This compares with the current installed capacity of about 100 GW. In the Reference Case of its Annual Energy Outlook 2013, DOE projects an increase in installed nuclear capacity of about 19 GW to 2040, of which only 5.5 GW is new-build capacity and the rest would come from uprates. The DOE “assumes that the operating lives of most of the existing U.S. nuclear power plants will be extended at least through 2040”. [65] Many of the plants would have passed 60-years of operation by then an astonishing assumption considering the characteristics of the recent Crystal River and Kewaunee closures. This assumes that such elderly plants will remain economic to run and to keep fixing when most of them have trouble competing today and when a need for major repairs is often a reason to shut them down immediately. Energy analyst Amory B. Lovins, analyzing recent industry operating-cost data, comes to the conclusion: “For economic or other reasons, the gradual phase-out of unprofitable nuclear power plants, already quietly under way, may accelerate.” [66]

While the new U.S. Secretary of Energy Ernest Moniz is considered a supporter of nuclear power, as was his prececessor Steven Chu, Government support has remarkedly cooled off. In his February 2013 State of the Union speech to Congress, President Barack Obama “highlighted the potential for solar, wind and even natural gas – but nuclear power received not a single mention”, complains the industry’s World Nuclear News. [67] It has simply been overtaken in the marketplace.



Asia ↑

China

China started construction of its first commercial reactor only in 1985, but its nuclear sector is developing fast, with 28 reactors under construction (40 percent of the world’s total). However, despite this potentially large planned increase as of July 2013, China has only 18 reactors (14 GWe) in operation, which in 2012 provided 92.65 TWh or 2 percent of the country’s electricity, the lowest nuclear share of any country. The maximum of 2.2 percent was reached 10 years ago in 2003. All of the units under construction are scheduled to come online before 2018 and would bring the total to 46 reactors (42 GWe).

During 2013 China plans to add 52 GW of non-fossil fueled generating capacity, comprising 21 GW of hydro, 18 GW of wind, 10 GW of solar and 3 GW of nuclear power [68]. By comparison the total fossil fueled capacity expected to be introduced in 2013 is 40 GW. [69] During the first six months of 2013, construction did not start on any new nuclear power plant. Thus non-hydro renewables are closing in on coal-fired plant construction, and their lines should cross shortly, as the government recently raised its 2015 PV installed-capacity target to an astonishing 40 GW to soak up surplus production capacity, mostly in China.

In 2010, a revision to the National Nuclear Power Middle and Long Term Development Plan 2005-2020, was under consideration in 2010, when some officials predicted that a likely target for 2020 would be 80 GW in operation together with a further 50 GW under construction. [70] However, in January 2011, the State Council Research Office (SCRO), which makes independent policy recommendations to the State Council, suggested that the 2020 target should be restricted to 70 GW of nuclear power in operation, with another 30 GW under construction, so as to ensure quality control in the supply chain. It cautioned against the launch of new Gen-II projects, and emphasized the need for a greater deployment of Gen-III+ projects, notably AP1000s, and that going too fast could threaten the long-term health of the sector. [71]

Safety concerns of the domestic designs were also highlighted in a cable from the U.S. embassy in Beijing from 2008, released by Wikileaks, which stated that the Gen-II CPR-1000 design were copies “of 60’s era Westinghouse technology that can be built cheaply and quickly” [72] —so by the time some of those reactors reached the end of their lives, their design would be a century old. (To be sure, that characterization may have reflected eagerness to sell newer U.S. technologies instead.) Similar concerns have been expressed by Tange Zede a member of the State Nuclear Power Technology Corp (SNPTC) who reportedly said the CPR-1000 could not even meet the national safety standards issued in 2004, let alone the most up-to-date international standards. Zede stated that “unless, the constructed Gen-II reactors are renovated, they should not be allowed to load fuel and start operation” [73].

Furthermore, the SCRO report advised that since goals to increase the localization of AP1000s has proven difficult, efforts needed to be made to de-bottleneck the domestic supply chain for AP1000s. In addition, the SCRO recommended that the National Nuclear Safety Administration, responsible for implementing safety regulations, be removed from the authority of the China Atomic Energy Authority, whose aim is to promote the nuclear industry [74].

Contrary to perceptions, Fukushima had a significant impact on nuclear development in China. On 14 March 2011, Xie Zhenhua, vice chairman of the National Development and Reform Commission, stated that “[e]valuation of nuclear safety and the monitoring of plants will be definitely strengthened.” [75] Then an account of a mid-March 2011 State Council meeting chaired by Premier Wen Jiabao states: “We will temporarily suspend approval of nuclear power projects, including those in the preliminary stages of development.... We must fully grasp the importance and urgency of nuclear safety, and development of nuclear power must make safety the top priority.” [76] As a result, a new China National Plan for Nuclear Safety with short-, medium- and long-term actions was ordered and approval for new plants remained suspended until it was approved. [77]

In May 2012, the State Council announced it had finished inspecting the country’s existing nuclear plants, and gave preliminary approval to both a revised 2020 nuclear strategy and a post-Fukushima safety plan. The revised 2020 nuclear strategy is expected to propose a target of 60-70GWe by 2020 [78]. The new much stricter standards for new nuclear construction—especially the call for elimination of the potential for large radiation releases in units built beyond 2016—suggest that utilities may abandon Gen II plants and switch to next-generation designs [79], which will delay construction. Despite this, existing designs, were given construction approval at Fuqing 4 and Yangjiang 4 in November 2012 as well as a High Temperature Gas reactor at Shidao Bay in December 2012. This raises concerns about how effective the new regime will be with critics saying that the industry’s rules and guidelines are a decade out of date, and that there is no coherent legal system to govern the use of nuclear energy. [80] But, as of early July 2013, no construction starts have occurred since then.

Safety concerns of the current and future reactor fleet have been raised by Academician He Zuoxiu, a former state nuclear physicist, who argues that the pace of nuclear development and the diversity of reactor designs is leading to insufficient actual operating experience, as such he predicts that the “most probable” period for a nuclear accident in China is between 2020 and 2030. [81] He had earlier compared China’s aggressive nuclear power plans with Mao’s disastrous “Great Leap Forward,” and urged building new reactors at a more measured pace, with strong attention to safety, and only on the coast (a policy that has reportedly been quietly adopted) but with tsunami protection. [82]

Furthermore, public acceptance of new reactors can no longer be taken for granted -a factor of rapidly increasing relevance in modern China. Historically, nuclear protests had mainly occurred in Hong Kong against the Daya Bay facility (both before and after the transfer of sovereignty). However, after Fukushima, greater public concern coupled with reactors being proposed in up to 16 provinces made wider public engagement on the issue likely. In particular, concerns have been raised over the safety and public support for inland nuclear power plants. Despite considerable investment in the preparation for construction projects at Taohuajiang, Pengze and Dafan remain suspended and it is now stated that no further approval will be given for the construction of inland projects [83]. The Pengze nuclear power plant has been subject to on-going local opposition [84], which is spreading to other projects in the region [85].

China’s importance to global new-build is not solely due to construction numbers but the types of reactors now being built, based on the world’s major reactor vendors most advanced designs. Westinghouse is building four AP1000 Generation III+ reactors at Sanmen and Haiyang. Construction began in April 2009 at Sanmen and at the time it was said that operation would begin in August 2013 [86], although delays of six to twelve months are reported [87]. For the first unit at Sanmen, this is said to be due to design changes post-Fukushima, while for the remaining three units due to supply chain issues relating to increasing local content. In 2009, it was said they would cost $1,940/kW, but the latest figures range from €2,300 to €2,600/kW [88], it is higher than the reported costs for the CRC 1000 at $1,800/kW [89]. It is suggested that the domestic content across the series of the four reactors will increase from 30 percent to 70 percent. When purchasing the four reactors China acquired domestic rights to much of the core AP1000 technology (but not the instrument and control technology) and the right to sell overseas its own version of the AP1000 with capacities over 1350 MW. Work is underway on the construction of the first domestic hybrids, the CAP 1400, a co-operation between Westinghouse, the State Nuclear Power Technology Corporation (SNPTC) and Shanghai Nuclear Engineering Research & Design Institute (SNERDI), with construction expected to start in 2014 [90].

In November 2007 AREVA announced the signing of a €8 billion ($11.6 billion) contract with the China Guangdong Nuclear Power Group, (CGNPC) for the construction of two EPRs in Taishan in Guangdong Province, and that it will provide “all the materials and services required to operate them” [91]. It is said that the cost of the reactors in this deal was €3.5 billion [92]. At the start of construction this was 40 percent below the starting price of construction of EPRs in Europe. [93] The power plant will be jointly owned by EdF (30 percent) and CGNPC (70 percent). At the time of the start of construction, the first of these reactors was expected to be completed in October 2013. The latest press statement suggests that unit 1 should begin operating in 2014, with unit 2 following in 2015 [94].

In April 2013 China and France signed a series of agreement to cement their relationship on nuclear issues. This included co-operation on the further development of nuclear reactors and preliminary agreements for the sale of equipment for an 800 tonne/year reprocessing facility. [95]

China has also been broadening its ambitions to export nuclear reactors. The most consistent example is in Pakistan, where despite its being outside the regime of the Non-Proliferation Treaty (NPT), China has supplied equipment for the two reactors at Chashma, the second of which only entered commercial operation in May 2011. Construction of units 3 and 4 was said to have begun at the end of 2011 with the engagement of China Zhongyuan Engineering as the general contractor and China Nuclear Industry No 5 as the installer, with finance also coming from China and completion expected in 2016 and 2017. [96] CGNPC has been in negotiations with Romania’s state-owned Nuclearelectrica to invest in the completion of units 3 and 4 of the Cernavoda plant in Romania, since other potential partners, including CEZ (Czech Republic), GDF of France, RWE of Germany and Iberdrola (Spain) have pulled out. [97]

In recent months, the Chinese industry has also reportedly connected with many other projects around the world. The April 2012 visit of Turkish Prime Minister Erdogan to Beijing was used to discuss China’s assistance for a proposed nuclear power station at Sinop.

In January 2013, CNNC and Nucleoeléctrica Argentina SA signed two nuclear agreements, and discussed further plans on the construction of fourth unit at the Atucha nuclear power plant. [98] It is unclear how many of these proposals will come to fruition, nor whether they would help China’s domestic nuclear additions by spreading capital costs or perhaps hurt them by diverting scarce technical resources and attention.

As with most energy sectors, what happens in China about nuclear power has global impact. In many quarters there is significant confidence that ambitious targets for domestic construction will be met, but this should be tempered given the remaining strategic questions over nuclear safety standards, engineering and skills bottlenecks, increasing environmental opposition, siting problems, and even basic economics. Despite China’s central planning system, its world-leading wind and solar achievements and their steeply falling price must be expected to put increasing competitive pressure on new-build nuclear prospects, just as in market economies if perhaps through different channels.

India operates 20 nuclear power reactors with a total capacity of 4.4 GW; the majority of these have a capacity of 220 MW per unit. In 2012, nuclear power provided a record 29.6 TWh that covered just 3.6 percent of India’s electricity, slightly below the record level of 3.7 percent already achieved in 2001/02 when nuclear generation was only around 17 TWh.

India lists seven units as under construction with a total of 4.8 GW. Most currently operating reactors experienced construction delays, and operational targets have rarely been achieved. India’s lifetime nuclear load factor is only 59.3 percent as of the end of 2012, the lowest of any country operating more than two units.

India’s 1974 nuclear weapons test triggered the end of most official foreign nuclear cooperation, including invaluable Canadian assistance. The nuclear weapons tests in 1998 came as a shock to the international community and triggered a new phase of instability in the region, including a subsequent nuclear test series by Pakistan. Various (and different) international sanctions were imposed on the two countries.

This state of affairs started to change under U.S. Bush administration’s announcement in 2005 of what became known as the U.S.-India deal. Following intense lobbying by the United States, supported by France and Russia, the IAEA approved a “safeguards agreement” with India in August 2008, and on 6 September 2008 the Nuclear Suppliers Group (NSG), a 45-country group regulating international commerce to prevent the proliferation of nuclear weapons, granted an exception to its own rules. Thus, although India is a non-signatory of the NPT, has developed and maintains a nuclear weapons program, and refuses full-scope safeguards, [99] it is still permitted to receive nuclear assistance and to carry out nuclear commerce with other nations. The reasons for this deviation from the previous nonproliferation consensus appear to be geopolitical and commercial. France has abstained from any criticism of India’s nuclear weapons program and has strongly encouraged the NSG to grant India access to international cooperation. A French parliamentary report states:

Grateful for these diplomatic positions in its favour and conscious about the French technological excellence in this sector, India has logically chosen to make France one of its principal partners. [100]

However, the report also highlights “the problems generated by the law on civil responsibility” that the Indian Parliament voted in September 2011, in particular because the supplier could be held liable for potential accidents under some circumstances. Furthermore, a petition filed by prominent lawyer Prashant Bhushan has requested the Indian Supreme Court to declare the liability legislation “unconstitutional and void ab initio” [meaning to be treated as invalid from the outset]. The outcome could mean the application of “absolute liability” to nuclear plants. Vendors will then be faced with the question “whether they are confident enough in the safety of their reactors to risk potential bankruptcy”. [101] In other words, in India, unlike virtually all Western countries, reactor owners or operators may need to shoulder responsibility for any harm caused by major accidents at their plants, rather than having their liability limited by special laws unique to their technology.

In addition, an August 2012 report by the Comptroller and Auditor General of India raises the issue of the independence of the Atomic Energy Regulatory Board (AERB). The report points to a number of inadequacies of the nuclear regulatory system in India. Even the international nuclear lobby’s World Nuclear News noted:

Other abnormalities in Indian regulation include the lack of a requirement for nuclear power plant owners to have decommissioning plans and secured funds for the work. [102]

In December 2010, the Nuclear Power Corporation of India Ltd. (NPCIL) and AREVA signed an agreement—though not yet a commercial contract—for the construction of two EPRs (and potentially four more) for a site in Jaitapur and a fuel supply for 25 years. [103] The contract reportedly would be worth some €7 billion ($10 billion) for two EPRs [104], a surprisingly low figure considering that the cost-estimate for the French and Finnish EPRs has escalated to €8.5 billion each. (See Economics section.)

Even before the agreement was signed, as on other sites, opposition against the Jaitapur project was massive. The Fukushima events triggered a significant increase in opposition. Two Russian-built reactors at Kudankulam were mostly completed before 3/11, “since when the sudden growth of a powerful local protest movement has effectively brought commissioning to a standstill”. [105] The Indian Government, however, appears intent on starting up the reactors, already years behind schedule. In May 2013, India’s Supreme Court paved the way for the commissioning of the reactors, which had been legally challenged by citizens’ groups, arguing that the plant is “in the largest interest of the nation particularly the State of Tamil Nadu”. [106] Meanwhile the state of West Bengal has scrapped another project for up to six Russian reactors at the coastal site of Haripur. [107]

The current five year plan counts on doubling the currently installed capacity and starting construction of a further 19 units. Princeton University’s M.V. Ramana concludes a milestone historical assessment of the Indian program with a question and answer:

Is a rapid and large-scale expansion of nuclear power in India, along the lines projected by the Department of Atomic Energy (DAE), feasible? The answer that emerges in the course of our excursion through the history of how the nuclear project has materialized in the country is that is is very unlikely and probably impossible. The principal reasons, among many, for this conclusion are the technical implausibility of the DAE’s plans, its inability as an organization to learn lessons from its earlier failures, and local opposition. [108]

Trade journal Nuclear Intelligence Weekly put it more bluntly: “There’s no reason to believe that the country can keep this schedule, of course.” Indeed, Indian nuclear planning has been always overly optimistic, not to say unrealistic. In 1984 a target of 10 GW was set for the year 2000. Almost 30 years later, not even half of that capacity has been installed. Projections for the future seem even more astounding (see Table 7).

Table 7: Nuclear Power in India: Planning, Projection or Fantasy?

Indian Forecasting Capacity “planned” Capacity installed Share realized in 1984 for 2000 10 GW 2.7 GW

in ca. 15 years 27% in 2005 for 2012 11 GW 4.8 GW

in ca. 30 years 43% in 2012 for 2017 10 GW 10 GW max

in ca. 35 years ? in 2012 for 2023 27 GW +12.7 GW

in ca. 10 years? ? in 2012 for 2032 63 GW +58 GW

in ca. 20 years? ? in 2009 for 2050 470 GW x 100

in 40 years? ?

© Mycle Schneider Consulting

Sources: various, assembled by MSC

In contrast, Indian entrepreneurs—largely in the vibrant private sector rather than large state-owned enterprises and agencies—have proven adept at rapidly scaling competitive, modular, short-lead-time, renewable technologies. India added 2.3 GW of wind turbines in 2012 (the fourth largest addition in the world) and now has an installed capacity of wind power of 18.4 GW, compared to 4.8 GW of nuclear capacity with the contribution of the wind sector to electricity supply having overtaken that of nuclear power in 2012.

Japan

In Japan nuclear power in 2012 provided about 17 TWh or 2 percent of total electricity compared to 18 percent in 2011, 29 percent in 2010 and the historic maximum of 36 percent in 1998.

This result, is obviously a consequence of the tragic events of 11 March 2011 known in Japan and overseas as 3/11. The triple disaster earthquake-tsunami-nuclear accident that hit Japan on that day had a profound impact on the nation’s and the world’s environment, economy and energy policy.

In October 2011 the Cabinet office released an energy white paper that dropped the paragraph on the expansion of nuclear power and instead called for the reduction on the reliance on nuclear power. Furthermore, the paper stated that the Government “regrets its past energy policy and will review it with no sacred cows”. [109]

Under Japanese law, every nuclear power plant has to be shut down at least every 13 months for inspection and maintenance. As of 26 March 2012, Japan’s main island Honshu was no longer using nuclear power, when unit 6 at Kashiwazaki-kariwa shut down for refueling, maintenance and inspection. Tomari-3 in Hokkaido was the last unit to go offline in Japan and as of 5 May 2012, all 54 Japanese nuclear power reactors were closed. However, in July 2012, two units at the Ohi plant in the Fukui Prefecture were restarted, but they remain the only reactors in operation across the country.

Officially, the Japanese Government declared only four of the Fukushima Daiichi units “permanently shut down”, the other 50 units remaining “operational” and two units “under construction” in the international statistics. It is virtually impossible to imagine that all reactors will return to operation. However, once the reactors are declared permanently closed, they become liabilities on the balance sheets of the utilities. Therefore, changing their status will have a profound impact not only on the electricity generation but on the economic viability of the companies, potentially leading to their bankruptcy. Japan is still absorbing former NRC Commissioner Peter Bradford’s remark about the financial risk revealed by the Three Mile Island accident: “Wall Street learned that a group of licensed operators no worse than any other could transform a billion-dollar asset into a two billion dollar clean-up in ninety minutes.” [110] At Fukushima, the accident was triggered by natural disaster, but the financial reversal was analogous—just one or two orders of magnitude bigger.

On 14 September 2012 the Japanese Government announced that it had adopted an “Innovative Strategy for Energy and the Environment”, for a zero nuclear power future by the 2030s [111]. However, due to lack of clarity, the Government statement immediately gave way to speculations as to the schedule for the shutdowns, and the future of the plutonium fuel program and of the reactors under construction.

To further confuse the issue, a statement by the Prime Minster said that “it is rather irresponsible to make a decisive judgment on the unforeseeable future. We must start with a strategy that has both a secure direction and the flexibility to cope with changes in the situation, without wavering from the basic policy and also not excessively restricting future decisions” [112].

No reactors can restart until they have conformed to the new guidelines issued by the Nuclear Regulatory Authority (NRA), which are expected to enter into force in July 2013. The new guidelines make it compulsory for operators to protect against radiation leaking to the environment through a review of existing reactors and their protection against external natural hazards such as tsunamis and earthquakes. This includes a more indepth review of the seismic conditions for the plants, which may permanently exclude the restart of some reactors. Secondly, the reactors must be retrofitted to implement additional measures for severe accident management, such as the prevention of hydrogen explosions [113]. The safety reviews are expected to take at least six months and therefore no significant electricity production from nuclear power will be achieved before 2014, and even then it is likely to be initially only from the more modern PWR designs [114]. It remains unclear to what extent the NRA will accept restarts while upgrading is under way. The change of government from the nuclear-skeptical Prime Minister Naoto Kan (who served during the accident) to the nuclear-friendly Yoshihiko Noda to the nuclear-enthusiastic Shinzo Abe has influence but is far from decisive when many provincial Governors and most of their constituents oppose nuclear restart.

The Japanese Government is facing unprecedented opposition to nuclear power in the country. Opinion polls indicate large majorities in favor of a nuclear phase out. Furthermore, opposition seems to be growing. The update of the IPSOS Mori’s post Fukushima global opinion poll found that between April 2011 and September 2012 a further 10 percent of the popoulation went against nuclear power. [115] Massive demonstrations of unprecedented scale have flooded the streets of Japan’s cities. At a public event in Osaka on 29 June 2013 in advance of Upper House elections the ruling LDP’s Secretary General Shigeru Ishiba was the only lawmaker out of nine to vote “No” to the question about favoring moving towards a non-nuclear future for Japan (see Photo 1).

Japanese media, once docile and quietly consored, have turned increasingly critical not only on the mismanagement of the Fukushima disaster, but also the political pressure that has been brought to bear to restart the nuclear reactors. In a stinging editorial the Director of the Asahi Shimbun Editorial Board stated on 29 June 2013:

The nation likely does not have the ability to cope with another accident of a similar scale.

If that is the case, the only alternative will be to reduce the number of nuclear plants as quickly as possible while making safety standards stricter and implementing measures to prepare for the likelihood of another accident.

That is the brutally frank reality Japan now faces.

Following a meeting between the new Japanese Prime Minister Shinzo Abe and French President Francois Hollande to cooperate on the development of a nuclear fuel cycle and the export of nuclear power technology, an editorial in the Japan Times stated: “Mr. Abe’s decision to move forward with the development of nuclear power technology represents his cynical disregard for the victims of the Fukushima nuclear crisis”. [116]

Photo 1: LDP Only Japanese Party to Vote Against Nuclear-Free Japan Source: Asahi Shimbun, 30 June 2013.

Numerous measures were taken between March and September 2011 to reduce electricity demand. Their estimated costs ranged from a few yen to a few hundred yen per kWh, in other words from very cheap to ridiculously high. Now, “METI is studying a ‘Nega-Watt Trade’ and other innovative programs” and an in-depth revision of the Energy Conservation Law is under preparation. [117] Japan’s target is to cut electricity demand by at least 10 percent by 2030. That target is, according to the Japan Times “a moderate one that could be exceeded if the government supports and enacts its policies more thoroughly” [118].

In the meantime, fossil fuel imports have increased significantly, in particular a 20 percent in the use of Liquified Natural Gas (LNG) over the past two years. This increase, coupled with increases in other countries in the region, such as China, resulted in a significantly higher regional price of gas, which affected Japanese balance of payments. In April 2013, as a result of higher fuel prices and a weaker Yen, the price per tonne of LNG reached €816, a level not seen since September 2008. [119]

In the meantime, the government introduced feed-in tariffs for renewable energy that are significantly higher than those in Germany or any other country. The tariffs became effective on 1 July 2012 and led to the rapid investment in renewable energy in Japan (chiefly solar, as wind is more constrained by artificial utility rules). In 2012, according to Bloomberg New Energy Finance, the total investment in clean energy in Japan reached $16.3 billion, nearly double the previous year. These investments are essential if Japan is to increase its use sufficiently to meet the 20 percent target by 2020. But there are already growing signs that the local demonstration of competitive renewables is starting to splinter the business community’s previously nearly-solid front in support of the old nuclear-centric policy. [120]

One of the key issues for the future of the power sector in Japan will be its reform and in particular the liberalisation of the market. This was to be a three stage process starting with the creation of an independent body to oversee supply and demand, followed by the liberalisation of the retail market and then the separation of retail and power generation, by 2020. However, in June 2013 the bill to introduce the first stage of the process was abandoned in the Upper House of Parliament. [121]

Pakistan operates three reactors that provided 5.3 TWh and 5.3 percent of the country’s electricity in 2012, both historic maxima. The nuclear load factor has been close to 89 percent. The third unit, supplied by China, came on line only three days after 3/11. During Chinese Prime Minister Wen Jiabao’s visit to Pakistan in December 2010, it was reported that China might build another two 650 MWe reactors in the country. [122] The Pakistan Atomic Energy Commission (PAEC) indicated a target capacity of 8.8 GW with 10 installed units by 2030. [123] Construction of two 315 MWe units started in 2011 at the Chasnupp site with the engagement of China Zhongyuan Engineering as the general contractor and China Nuclear Industry No. 5 as the installer, with finance also coming from China. According to press reports [124], the Finance Ministry has released a modest $4.8 million (465 million Pakistani rupees) for a fesibility and design study into a second reactor for the Karachi site. The first unit at the site, KANUPP, a 125 MW CANDU heavy water reactor, was first connected to the grid in October 1971 and is one of the oldest operating reactors in the world.

In the 1980s, Pakistan developed a complex system to access illegally various components for its weapons program on the international black market, including from diverse European sources. [125] Immediately following India’s nuclear weapons tests in 1998, Pakistan also exploded several nuclear devices. International nuclear assistance has been practically impossible, given that Pakistan, like India, has not signed the NPT and does not accept full-scope safeguards, and is currently unlikely to be granted the same exception as India to the NSG’s export rules. Some Pakistani experts bitterly complain about the “simply unfair” differential treatment under the international non-proliferation regime and consider that “participation in the NSG is essential if Pakistan is to be able to acquire the equipment and expertise needed to build the nuclear plants that will fill this power gap”. [126]

On the other hand, according to Pakistan’s Alternative Energy Development Board, the country has vaste potential resources in wind energy, estimated at 350 GW. Several hundred megawatts of wind projects are currently under development. [127] In January 2013, the Korean Solar Energy Company launched a large 1 GW solar project in Beluchistan that is supposed to help ease power shortages in the region.

On the Korean Peninsula, the Republic of Korea (South Korea) operates 23 reactors that provided 143.6 TWh (2.4 percent less than in record year 2011) or 30.4 percent of the country’s electricity in 2012 (down from a maximum of 53.3 percent in 1987). In addition, four reactors are listed as under construction. The first Shin-Uljin unit officially started construction on 10 July 2012. South Korea’s reactors have shown excellent performance in the past, and held the fourth position of lifetime load factors with 86.4percent by the end of 2012. However, due to component and quality control issues, the annual load factor dropped by almost 10 percent in 2012 to 80.7 percent.

Less than a month after 3/11, the Korea Electric Power Corporation (KEPCO) presented plans to double installed nuclear capacity to close to 43 GW by 2030 and bring the nuclear share in the power generation to 59 percent. [128] However, observers see a “dramatic political shift against nuclear power in the year since Fukushima”. [129] The Mayor of Seoul, for example, initiated a program to “save away” the equivalent amount of energy generated by one nuclear reactor. According to an updated 24-country study by IPSOS, general support of nuclear power recovered significantly (+18 percent), but by September 2012 still 51 percent of Korean people polled opposed nuclear energy. [130]

The newly elected Korean Government under President Park Geun-hye, who came into office in December 2012, attempts to support the nuclear industry and to restore public trust after a series of scandals. In April 2012, the CEO of Korea Hydro & Nuclear Power (KHNP) was forced to resign over the cover-up of two significant incidents, a 12-minute station blackout at Kori-1 with two emergency diesels failing to start up on 9 February 2012 and another diesel failure at Yonggwang-2 on 28 March 2012. Both events had not been disclosed for several weeks. [131] In November 2012, a massive quality control scandal broke and up to 74 investigators inquired about tens of thousands of items at the country’s nuclear power plants. In January 2013, the Nuclear Safety and Security Commission (NSSC) announced:

Over the past 10 years, 13,794 units of 561 items with falsified quality certificates have been supplied to KHNP, and 6,949 units of 341 items were found installed curently in the nuclear power plants. Almost all 5,258 safety-related items supplied with falsified documents were replaced under witness of site investigators. [132]

A total of 20 suppliers and 215 cases of quality record falsification had been identified. In May 2013, the scandal widened into safety-class control-command cables. After an anonymous report had tipped off the NSSC, it was confirmed that test reports had been forged and that the test in fact failed under loss-off-coolant-accident conditions. Two operating reactors, Shin-Kori-2 and Shin-Wolsong-1, were shut down, and the maintenance period of Shin-Kori-1 was extended in order to replace the faulty cables. Shin-Kori-3 and -4 as well as Shin-Wolsong-2, all three under construction, also had “forged” quality-control documents and need to replace the incriminated cables. [133]

In December 2009, South Korea succeeded in securing its first major overseas nuclear deal, “snatching” a multi-billion dollar contract with the United Arab Emirates (UAE) from the world’s largest builder AREVA, backed by French state utility EDF, for building of four 1.4 GW reactors. In the meantime, however, cost estimates have soared and financing negotiations have been delayed (see section on UAE in chapter Potential Newcomer).

Taiwan operates six reactors that provided a record 38.7 TWh or 18.4 percent of the country’s electricity in 2012 (down from a maximum of 41 percent in 1988). Two 1.3 GW Advanced Boiling Water Reactors (ABWR) have been listed as under construction at Lungmen, near Taipei, since 1998 and 1999 respectively. Their startup has been delayed many times and they are many years behind schedule. According to the Atomic Energy Council, by April 2013, the first unit was “nearly finished” and operator Taipower was presently carrying out “on-site testing of operating procedures and systems functions”. [134] In March 2012, the Atomic Energy Minister raised doubt over the safety of the plant. [135] In May 2012, media reports gave 2014-15 as the current planned start-up date. Another source has indicated startup of the first unit “no earlier than March next year”, in 2014, “if there are no further problems”. [136] The plant is estimated to have cost USD 9.6 billion so far. According to the Minister of Economic Affairs, the project costs Taipower an estimated NT$400–600 million (USD10–15 million) for each month of delay. [137]

Taiwan’s nuclear program has a certain number of very specific problems. The nuclear plants are located in areas with high population density, high seismicity and tsunami risks. In addition, with the absence of a long-term waste strategy, the spent fuel pools are filling up and, in spite of re-racking and dense-packing, the first pools are expected to be full by 2014. [138] “The confidence of residents are [sic] feeble on nuclear safety issue”, admitted Taipower Vice-President Hsu Hwai-Chiung in July 2011. “The license renewal of NPPs will be suspended until National Energy Policies are clear in near future.” [139]

The Taiwanese public is increasingly critical towards the country’s nuclear power program and on 9 March 2013 over 200,000 people demonstrated in various cities against the startup of the Lungmen plant. An opinion survey released in late March 2013 indicated a 73 percent majority in favor of a halt to the Lungmen plant. On 26 April 2013, the ruling party introduced a bill in the legislature to organize a national referendum over the future of the Lungmen project. What appears to be an exemplary exercise of democracy is seen by many as a manouver to get a silent majority for the project’s completion. The referendum legislation requires a quorum of at least 50 percent to make the outcome binding, a score difficult to achieve nationwide.

In November 2011, the Government presented a new energy strategy to “steadily reduce nuclear dependency, create a low-carbon green energy environment and gradually move towards a nuclear-free homeland”. [140] The document released by the Ministry of Economic Affairs’ Bureau of Energy also announced the shutdown of its oldest reactors at Chinshan (grid connection 1977 and 1978) as soon as the Lungmen reactors come online and the non-renewal of operating licenses beyond a 40-year lifetime. That would mean the shutdown of the operating units between 2016 and 2025.



European Union (EU27) and Switzerland ↑

The European Union 27 member states (EU27) have gone through three nuclear construction waves, two small ones in the 1960s and the 1970s plus a large one in the 1980s (mainly in France). The region has not had any significant building activity since the 1990s. (See Figure 26.)

In July 2013, 14 of the 27 countries in the enlarged EU operated 131 reactors—about one-third of the world total—12 fewer than before the Fukushima events and one-quarter below the historic maximum of 177 units in 1989. (See Figure 27.) The vast majority of the facilities, 112 or 85.5 percent, are located in eight of the western countries, and only 19 are in the six newer member states with nuclear power.

In 2012, nuclear power produced 27 percent of the commercial electricity in the EU, down from 31 percent in 2003. [141] Nearly half (48 percent) of the nuclear electricity in the EU27 was generated by one country, France.

Figure 26: Nuclear Reactors Startups and Shutdowns in the EU27 , 1956–2013 Source: IAEA - PRIS , MSC , June 2013

Figure 27: Nuclear Reactors and Net Operating Capacity in the EU27 , 1956–2013 Source: IAEA - PRIS , MSC , June 2013

With the lack of new reactor construction, the average age of the EU’s reactors now stands at 29 years (see Figure 28).

Figure 28: Age Pyramid of the 131 Nuclear Reactors Operated in the EU Sources: IAEA - PRIS , MSC , July 2013

Western Europe

In Western Europe (EU15), as elsewhere, the public generally overestimates the significance of electricity in the overall energy picture, as well as the role of nuclear power. Electricity currently accounts for only about one-fifth of the EU15’s commercial primary energy consumption.

As of July 2013, the EU15 was home to 112 operating nuclear power reactors, or 45 units fewer than in the peak years of 1988/89.

Two reactors are currently under construction in the older member states EU15, one in Finland and one in France. These are the first building sites in the region since construction began on the French Civaux-2 unit in 1991. Apart from the French exception and the Sizewell-B reactor in the U.K.(ordered in 1987), until the reactor project in Finland, no new reactor order had been placed in Western Europe since 1980.

The following provides a short overview by country (in alphabetical order).

Belgium operates seven reactors and has the world’s third highest share of nuclear in its power mix, at 51 percent in 2012 (down from a maximum of 67.2 percent in 1986). The nuclear plants achieved their best productivity level generating 46.7 TWh in 1999 compared to 38.5 TWh in 2012. In 2002, the country passed nuclear phase-out legislation that required the shutdown of nuclear plants after 40 years of operation, meaning that (based on their start-up dates) plants would be shut down between 2015 and 2025. On 13 October 2009, the Government issued a 10-page general policy statement that included one reference to nuclear power: “The government has decided to postpone by 10 years the first sequence of the phase-out of nuclear power.” [142] However, that government was voted out in June 2010, just prior to voting on supporting legislation to delay the phaseout. Following Fukushima and the establishment of a new Government the still existing phase-out legislation was left in place and no legislative initiative has been taken to overturn it, even if the operator GDF-Suez is lobbying hard to postpone via an extension of “at least 10 years”. [143]

In the summer of 2012, the operator identified unprecedented numbers of crack indications in the pressure vessels of Doel-3 and Tihange-2 with respectively over 8,000 and 2,000 previously undetected defects. After several months of analysis including international experts, the Belgian safety authority FANC asked the operator to carry out a specific test program prior to any restart decision. However, in late January 2013, AIB-Vinçotte, an international quality-control company based in Belgium, working on behalf of the Belgian safety authority, stated that “some uncertainty about the representativity of the test program for the actual reactor pressure vessel shells cannot be excluded”. [144] The safety authority’s own subsidiary BEL-V concluded at the same time [145]:

Indeed there exists no validated procedure neither for evaluating flaws having the morphology and orientation of the hydrogen-induced flaws nor for evaluating thousands of those defects with interactions between themselves (clustered flaws) because such a situation has never been met (and, as a result, accepted) in an operating safety-related pressure component like the reactor pressure vessel for which break exclusion is assumed.

An independent assessment [146] equally concluded that “FANC should obtain—before authorizing the restart of the affected reactors—absolute certainty that the flaws will not lead to the failure of the reactor pressure vessel. This is obviously not the case at present and will not be the case even if the complementary tests should prove positive”.

However, on 17 May 2013, FANC issued a statement saying that it “considers it safe to restart the Doel 3 and Tihange 2 reactor units”. [147] The units restarted in spite of the serious concerns by independent scientists and reached full capacity respectively on 9 and 11 June 2013. The underlying issue has not gone away.

Finland currently operates four units that supplied 22.1 TWh or 32.6 percent of its electricity in 2012 (down from a maximum of 38.4 percent in 1986). Finland’s load factor has been constantly amongst the top five nuclear countries. Although it dropped in 2012 by 3.3 percent, with an annual average of 90.7 percent, it is still number four in the world.

In December 2003, Finland became the first country to order a new nuclear reactor in Western Europe in 15 years. AREVA NP, then comprising 66 percent AREVA and 34 percent Siemens [148], is building a 1.6 GWe EPR under a fixed-price turn-key contract with the utility TVO—an arrangement that AREVA top managers have admitted in private talks they would “never do again”. The project was financed essentially on the balance sheets of the country’s leading firms and municipalities under a unique arrangement that makes these customers liable to pay the plant’s indefinite capital costs for an indefinite period, whether or not they get the electricity—a Capex “fixed price” but “take-or-pay contract”.

Construction started in August 2005 at Olkiluoto on the Finnish west coast. Close to eight years later, the project is about seven years behind schedule and now 280 percent over budget (see also Economics section). The plant is currently expected to start up in 2016 and the cost estimate has been raised to €8.5 billion. It remains unclear who will cover the additional cost: the vendors and TVO blame each other and are in litigation. “TVO is not pleased with the situation and repeating challenges with the project scheduling” and admits that “the plant completion may be further delayed”. [149] According to TVO, about 75 percent of the installation work has been completed.

From the beginning, the Olkiluoto-3 (OL3) project was plagued with countless management and quality-control issues. Not only did it prove difficult to carry out concreting and welding to technical specifications, but the use of sub-contractors and workers from several dozen nationalities made communication and oversight extremely complex.

The Finnish regulator STUK has still not yet validated the EPR’s Instrumentation and Control (I&C) system. TVO stated in February 2013 that “the I&C design has not proceeded as planned” and could cause further delays.

The repeated construction delays of OL3 are a blow not only to power planning by the utility and to the 60 large customers involved in the project consortium, but also for the Finnish Government.

In late February 2013, TVO’s Board of Directors proposed a new shareholder loan commitment of €300 million to its shareholders in order to cope with financing costs and maintain a minimum 25 percent share of shareholders capital or loan. [150] Credit rating agency Fitch nevertheless downgraded TVO from BBB+ to BBB in late May 2013 [151] - see Table 4 for more details.

OL3 was part of the government’s strategy to achieve its target of a zero-percent increase of 1990 emissions under the Kyoto Protocol. The lack of an operational OL3 will force Finland to use emissions trading to compensate for the GHG’s produced in the country.

The problems produced by the OL3 project have not prevented TVO from filing an application, in April 2008, for a decision-in-principle to develop “OL4”, a 1–1.8 GWe reactor to start construction in 2012 and enter operation “in the late 2010s”. [152] The decision was ratified by the Finnish Parliament on 1 July 2010. But already significant delays have emerged. In late March 2012, TVO invited five reactor vendors—AREVA, GE Hitachi (GEH), Korea Hydro and Nuclear Power (KHNP), Mitsubishi and Toshiba—to submit bids, which were transmitted in January 2013. A license application is planned for mid-2015 and start-up “around 2020.” [153]

In parallel, Fortum Power is planning a similar project, known as Loviisa-3. In addition, in January 2009, the company Fennovoima Oy submitted an application to the Ministry of Employment and the Economy for a decision-in-principle on a new plant at one of three locations—Ruotsinpyhtää, Simo, or Pyhäjoki—which has first been narrowed down to the latter site and to being an EPR or ABWR. Startup was planned for 2020. Bids were received on 31 January 2012 from AREVA and Toshiba. [154] In August 2012, a group of minority stakeholders left the Fennovoima consortium, followed by E.ON, which sold its 34 percent share in April 2013 to Voimaosakeyhtiö SF, a consortium of 60 companies and municipalities, that already held the remaining 66 percent. Fennovoima ended the formal tender process in February 2013, inviting Toshiba to direct negotiations over a 1300 MW ABWR design and effectively dropping the EPR from the competition. In addition, in April 2013, to the general surprise of AREVA and Toshiba, Fennovoima invited Rosatom to direct negotiations over its 1200 MW PWR AES-2006. Fennovoima stated that it will select the plant supplier “during 2013”. [155] However, while Toshiba and AREVA were explicitly mentioned in government and parliament planning authorizations, this is not the case with Rosatom. Greenpeace has already announced it will challenge the decision in court, “if the government shows any signs of approving a Rosatom deal under the current criteria”. [156]

France is the worldwide exception in the nuclear power sector. In 1974, the Government launched the world’s largest public nuclear power program in response to the oil crisis in 1973. After four decades of unchanged support for nuclear power the new Government under President François Hollande has promised a significant shift in energy policy.

In 2012, France’s 58 reactors [157] produced 407.4 TWh or 74.8 percent of the country’s electricity, a drop of almost 3 percent. Nuclear generation and its share in France’s power mix reached their maximum in 2005, with respectively 431.2 TWh and 78.5 percent. The annual load factor dropped another 2.3 percent to 73.6 percent, compared to countries that exceed 90 percent.

France has a significant base load overcapacity that has led to the “dumping” of electricity on neighboring countries and stimulated the development of highly inefficient thermal applications of electricity. A historical winter peak-load of 102 GW in February 2012, (up from 97 GW in December 2010) is to be compared with an installed capacity of 128.7 GW [158]. However, during the coldest days in February 2012, France imported up to 13 GW of power, of which Germany contributed about 3 GW (see also the following section on Germany).

France’s seasonal peak electricity load has increased rapidly since the mid-1980s, due mainly to the widespread introduction of electric space and water heating in an effort to absorb the nuclear surplus – an issue anticipated by critics in the 1970s. Over 30 percent of French households now heat with electricity, the most wasteful form of heat generation because it results in the loss of most of the primary energy during transformation, transport, and distribution. The difference between the lowest load day in summer and the highest load day in winter is now over 70 GW. A drop of 1C° in outside temperature is equivalent to an increase in capacity of 2.3 GW. Short-term peak load cannot be met with nuclear power but rather by either fossil fuel plants or expensive peak-load power imports.

Considering its existing nuclear overcapacity’s and the average age of its reactors (28.4 years in mid-2013), France should not need to build any new units for a long time. In addition, the nuclear share in the power mix is too high; lifetimes of operating units are planned to be extended; the shutdown of the gaseous diffusion uranium enrichment plant will save huge amounts of electricity [159], and several nuclear plants should be made redundant through efficiency.

If the French Government and EDF opt to proceed with construction of a new unit, then this is not to relief capacity constraints but because the nuclear industry faces a serious problem of maintaining competence in the field.

In December 2007, EDF started construction of Flamanville-3. The FL3 site encountered quality-control problems with basic concrete and welding similar to those at the Olkiluoto-3 (OL3) project in Finland, which had started two-and-a-half years earlier. As in Finland, the extensive employment of foreign workers exacerbated communication and social problems. [160] It took until April 2012 for the French safety authority to judge satisfactory the instrumentation and control (I&C) system solution proposed by EDF for FL3. The project is now at least four years late and not expected to start commercial operation before 2016. The price tag has more than doubled since construction start and has been increased to €8.5 billion in December 2012, €2 billion more than in 2011—a “terrible publicity”, as trade journal Usine Nouvelle noted. [161] In addition, the Italian partner ENEL that held 12.5 percent of the project decided to quit the project. EDF is obliged to buy back ENEL’s shares for an estimated €690 million.

Beyond the EPR building problems, the two state-owned companies EDF and AREVA continue to fight over several strategic issues: follow-up agreements on reprocessed uranium conversion, uranium enrichment, reprocessing and plutonium fuel fabrication, as well as the overall industrial strategy.

Even before the Fukushima accident, but especially after 3/11, there have been major difficulties with large investment projects—in Italy, the United Kingdom, and the United States—and all are taking a toll on the balance sheet and credit rating of France’s major nuclear companies. While EDF accumulated a huge debt burden that increased through 2012 by €8 billion to €41.5 billion net ($54 billion), AREVA lost €2.5 billion in 2011 and another €100 million in 2012. AREVA’s debt increased by €400 million—equivalent to an additional provision for OL3—to almost €4 billion. [162] In December 2011, Standard & Poor’s downgraded AREVA to ‘BBB-’ rating as well as its stand-alone credit profile of ‘bb-’.” [163] It has not changed since. AREVA’s share price had plunged in 2012 by up to 88 percent of its peak 2007 value, while EDF shares had lost up to 85 percent of their value over the same period, hitting the bottom in January 2013. In December 2012, Moody’s downgraded EDF’s perspective from stable to negative. [164]

France also operates many other nuclear facilities, including uranium conversion and enrichment, fuel fabrication, and plutonium facilities. France and the United Kingdom are the only countries in the EU that engage in reprocessing, or separating plutonium from spent fuel. The U.K. has announced it will abandon reprocessing in the near future. France’s two La Hague facilities are licensed to process 1,700 tonnes of fuel per year; however, all significant foreign clients have finished their contracts and have stopped plutonium separation. The La Hague operator AREVA NC therefore depends entirely on the domestic client EDF for future business, yet reprocessing’s high cost burdens financially stressed EDF.

The current Government under President Hollande constitutes without any doubt a major rupture not only with his predecessor Nicolas Sarkozy, but also with previous administrations. For the first time since 1974, a French Government has announced plans for the closure of the oldest operating reactors (Fessenheim-1 and -2, connected to the grid in 1977), the abandoning of a new-build project (Penly-3) and the systematic reduction of the share of nuclear generated electricity (from about 75 to 50 percent by 2025). Currently a major national energy debate is ongoing that will lead to framework legislation to be submitted to the National Assembly before the end of 2013. [165]

Four days after 3/11, Germany’s conservative and pro-nuclear Government decided to shut down 8 of its fleet of 17 reactors. Originally for a three-month period, the closure of almost half of the German reactors turned out to be permanent. Nuclear power plants generated 94.1 TWh net in 2012—a drop of 29 percent compared to pre-3/11 year 2010—and provided 16.1 percent of the electricity (gross) in the country (1.5 percent less than in 2011 and down from the historic maximum of 30.8 percent in 1997) [166].

On 14 March 2011, Chancellor Angela Merkel abruptly announced putting plant life extension plans on hold and initiated a major re-shift of the country’s nuclear policy. On 6 June 2011 the Government passed far-reaching energy transition legislation, including a revision (the 13th) of the Nuclear Law (Atomgesetz). The legislation passed the Bundestag on 31 July 2011 almost by consensus, and came into force on 6 August 2011. Key characteristics include:

• The operating licenses will expires once the production credit is used up and at the latest according to Table 8. This meant that the eight units that had been shut down after 3/11 lost their operating license with the coming into force of the legislation.

• The production credit can be transferred from older to newer plants.

The legislative package included seven other laws ranging from energy efficiency (€3 billion per year for buildings) and increase in the use of renewable energy (with a new target of a 35 percent share of electricity by 2020) to natural gas as well as the large-scale extension of the grid system.

The German nuclear phase-out decision has generated widespread interest from other countries and has led to a number of unfounded claims, such as that ‘Germany would have to replace nuclear electricity through increased coal consumption or nuclear power imports from France’. In fact, Germany made notable progress in energy efficiency, and gross electricity consumption decreased by 1.4 percent in 2011 and another 1.3 percent in 2012, while renewable energy generation increased by 32 percent over the same period and represented 22 percent in the power mix in 2012. However, cheap coal prices on the world market led to perverse effects: while production from natural gas plants dropped by almost 20 percent over the past two years, lignite plants boosted production by 9 percent over the same period and coal plants in 2012 reached the same production level as pre-3/11 year 2010. These effects, however, are expected to be brief and temporary. [167]

Table 8: Closure Dates for German Nuclear Reactors 2011-2022

Reactor Name (type, net capacity) Owner/Operator End of license (latest closure date) First Grid Connection Biblis-A ( PWR , 1167 MW ) Biblis-B (PWR, 1240 MW) Brunsbüttel (BWR, 771 MW) Isar-1 (BWR, 878 MW) Krümmel (BWR, 1346 MW) Neckarwestheim-1 (PWR, 785 MW) Philippsburg-1 (BWR, 890 MW) Unterweser (BWR, 1345 MW) RWE RWE KKW Brunsbüttel [168] E.ON KKW Krümmel [169] EnBW EnBW E.ON 6 August 2011 1974 1976 1976 1977 1983 1976 1979 1978 Grafenrheinfeld ( PWR , 1275 MW ) E. ON 31 December 2015 1981 Gundremmingen-B ( BWR , 1284 MW ) KKW Gundremmingen 170] 31 December 2017 1984 Philippsburg-2 ( PWR , 1402 MW ) EnBW 31 December 2019 1984 Brokdorf ( PWR , 1410 MW ) Grohnde (PWR, 1360 MW) Gundremmingen-C (BWR, 1288 MW) E. ON /Vattenfall 171] E.ON KKW Gundremmingen 31 December 2021 1986 1984 1984 Isar-2 ( PWR , 1410 MW ) Emsland (PWR, 1329 MW) Neckarwestheim-2 (PWR, 1310 MW) E. ON KKW Lippe-Ems [172] EnBW 31 December 2022 1988 1988 1989

Notes: PWR=Pressurized Water Reactor; BWR=Boiling Water Reactor

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

The key driver behind the increase in hard coal and lignite burning is the price signal on the European power exchange market, not the nuclear phase-out. Europe has a large structural overcapacity, so in the absence of a significant carbon price, there has been an increasing incentive to operate existing lignite and coal fired power plants – especially in 2012 when an unusually cold winter helped drive up competing natural-gas prices. Germany does not have any capacity problems, on the contrary, the country never exported more than in 2012 with 23 TWh net, a 3.7 fold increase over the previous year, and due to its highly competitive wholesale prices, (which renewable power has sharply reduced in the past few years), Germany is the only country that consistently exports electricity to France.

The Fukushima events and the political reaction accelerated industrial strategic shifts. Electronics giant Siemens, which built all of Germany’s nuclear plants and exported more, announced in September 2011 that, after having left AREVA NP, the joint consortium with AREVA, it would quit the nuclear sector entirely. Siemens Chairman Peter Löscher declared that “we will not enter into the overall responsibility or the financing of the construction of nuclear power plants anymore. This chapter is closed for us. Siemens will be a motor for the German energy transition (Energiewende)”. [173] In addition, Siemens entered into a “strategic alliance” with Boeing in the U.S. for the development and implementation of micro-grids. German utilities RWE and E.ON also pulled out of nuclear projects in various countries, including in the Bulgaria, Finland, the Netherlands and the U.K.



The Netherlands operates a single, 40-year-old 480 MW PWR that provided 3.7 TWh or 4.4 percent of the country’s power in 2012 (down from a maximum of 6.2 percent in 1986). For comparison, renewables, mainly biomass and wind, accounted for over 10 percent in power generation in 2012. [174] In June 2006, the operator and the Government reached an agreement to allow operation of the reactor until 2033. [175]

On 23 January 2012, the utility DELTA announced it was putting off decision on nuclear new-build “for a few years” and that there would be “no second nuclear power at Borssele for the time being”. The company provided the following reasons for its decision: “The financial crisis, combined with the substantial investment needed for a second nuclear power plant, current investment conditions, overcapacity in the electricity market and low energy prices.” [176]

In early 2004, Borssele operator EPZ extended a reprocessing contract with AREVA NC. This is a curious decision considering that there are no possibilities in the Netherlands of using separated plutonium. Therefore, EPZ has paid the French utility EDF to get rid of the plutonium. However, more recently EPZ has applied for a license to load MOX fuel into the Borssele reactor, which was granted in June 2011. [177] The reasons for the change in plutonium management remain unknown. In France, the extracted plutonium has zero book value and negative market value.

Spain operates seven reactors, an eighth unit was shut down at the end of 2012. Nuclear plants provided 58.7 TWh or 20.5 percent of the country’s electricity in 2012 (maximum of 38.4 percent in 1989). Beyond the de-facto moratorium that has been in place for many years, the previous Premier Jose Luis Zapatero announced at his swearing-in ceremony in April 2004 that his government would “gradually abandon” nuclear energy, while increasing funding for renewable energy. The first unit (José Cabrera) was shut down at the end of 2006. Zapatero confirmed the nuclear phase-out goal following his reelection in 2008, and then Industry Minister Miguel Sebastian has stated, “there will be no new nuclear plants.” [178]

Spain has, however, been implementing both uprating and lifetime extensions for existing facilities. Licenses for the operating units would have run out between 2010 and 2018; however, in 2009 the Government extended the operating license of the then 40-year old Garoña plant to 2013, and in 2010 it granted the 30-year old Almaraz-1 plant a 10-year extension and a capacity increase of 7 percent. The 28-year old Almaraz-2 plant also will be uprated. [179] In February 2011, the Spanish parliament amended the Sustainable Energy Law, deleting from the text a reference to a 40-year lifetime limitation and leaving nuclear share and lifetime to be determined by the government. [180]

Nevertheless, on 16 December 2012, Garoña was shut down definitively. The operator Nuclenor had calculated that further operation of the 446 MW plant would not be economic. Not only would Nuclenor have to invest about €120 million to upgrade the 42-year old plant, but it would also have to face a new tax of €153 million in 2013 following an energy tax reform that was overdue in Spain.

Spain is one of only three countries that increased opposition to nuclear energy since April 2011, according to a September 2012 update of a 24-country study by IPSOS: 63 percent of those polled oppose nuclear power, 6 percent more than in the previous study. [181]

The added capacity from Spain’s nuclear uprating (64 MW at Almaraz so far) remains negligible compared to the country’s surge in renewables. With an installed renewable electricity capacity of 34 GW (end of 2012), almost five times larger than its nuclear capacity, Spain is number four in the world. [182] Spain is also number four in the world in installed wind capacity, number six in installed PV capacity and a leader in concentrated solar power plants with over 2,500 MW installed, with over 800 MW added in 2012 alone. [183] Renewables have met over 30 percent of the Spanish electricity demand for the past three years and over half in spring 2013.

Sweden operates 10 reactors that provided 61.5 TWh or 38.1 percent of the country’s electricity in 2012 (down from a maximum of 52.4 percent in 1996). Sweden’s per capita power consumption is among the highest in the world, due primarily to the widespread and inefficient thermal use of electricity. In recent years, however, Sweden has had negative growth rates in residential electricity consumption. [184]

Sweden decided in a 1980 referendum to phase out nuclear power by 2010. The referendum took place at a time when only six out of a planned 12 reactors were operating; the other six were still under construction. It was therefore effectively a “program limitation” rather than a “phase-out” referendum. Sweden retained the 2010 phase-out date until the middle of the 1990s, but an active debate on the country’s nuclear future continued and led to a new inter-party deal to start the phase-out earlier but abandon the 2010 deadline. The first reactor (Barsebäck-1) was shut down in 1999 and the second one (Barsebäck-2) went off line in 2005.

On 5 February 2009, the parties of Sweden’s conservative coalition government signed an agreement on energy and climate policy that defines ambitious renewable energy and energy efficiency targets and calls for the scrapping of the Nuclear Phase-Out Act. In June 2010, the parliament voted by a tight margin (174/172) to abandon the phase-out legislation. [185] As a result, new plants could again be built—but only if an existing plant is shut down, meaning that the maximum number of operating units will not exceed the current ten. This puts Sweden many years away from potential new construction. Trade journal Nuclear Intelligence Weekly notes: “In 2012 Vattenfall asked the regulator for more clarity regarding the newbuild process, but 2025 is the earliest date for any new units.” [186] In the meantime utility Vattenfall envisages to extend lifetimes of five of its seven units at Forsmark and Ringhals to 60 years. The objective for Ringhals-1 and -2 is a 50-year lifetime. [187]

Operators have pushed uprating projects to over 30 percent: at Oskarshamn-2 a 38 percent capacity increase is under way while a 33 percent uprate has been implemented at Oskarshamn-3 with a two-year delay. Work at Oskarshamn-2 is also seriously delayed and not now expected to be completed before April 2014. [188]

Swedish public opinion remains split over general nuclear power acceptance. A 2012-update to a 24-country survey gives proponents a scant 52 percent majority. [189]

The United Kingdom operates 16 reactors as of 1 July 2013. Nuclear plants provided 64 TWh or 18.1 percent of the country’s electricity in 2012 (down from a maximum of 26.9 percent in 1997). The first-generation Magnox reactors, with 11 stations, have all been retired, except for one at Wylfa, which is to close by the end of 2014. [190] The seven second-generation stations, the Advanced Gas-cooled Reactors (AGR), are also at or near the end of their design life, although the owners now plan to extend their life by seven years to 40 years with retirements only in 2016–29. The newest plant, Sizewell-B, is the United Kingdom’s only PWR and was completed in 1995.

The industry has a long history of economic and technical problems. (See the chapter Economics of Nuclear Power), right up through the past decade: In 2004 the government prevented privately owned nuclear generator British Energy from going into liquidation. While the state-owned nuclear fuel and technology company BNFL was also effectively bankrupt because it could not meet its liabilities, the Government split up the company, passing the physical assets (and its costly decommissioning obligations) to a new agency, the Nuclear Decommissioning Authority (NDA), while the capabilities were privatized.

The NDA is now responsible for decommissioning all Britain’s civil nuclear facilities except those owned by British Energy, a discounted liability [191] estimated in 2013 to be in excess of £58 billion ($90 billion) [192], up from less than £34 billion ($53 billion) in 2007. The NDA inherited negligible funds for this task, relying partly (and increasingly) on government grants and partly on income from the facilities still in operation, including one remaining Magnox reactor, the THORP reprocessing plant, and the Sellafield MOX Plant (SMP) a plutonium fuel manufacturing plant. Both of the latter facilities, however, have been plagued by very serious technical problems that have kept their operation significantly below expectati