Nuclear Power in Germany
(Updated 8 February 2017)
- Germany until March 2011 obtained one-quarter of its electricity from nuclear energy, using 17 reactors. The figure is now about 14% from eight reactors, while 43% of electricity comes from coal, the majority of that from lignite.
- A coalition government formed after the 1998 federal elections had the phasing out of nuclear energy as a feature of its policy. With a new government in 2009, the phase-out was cancelled, but then reintroduced in 2011, with eight reactors shut down immediately.
- Public opinion in Germany remains broadly opposed to nuclear power with virtually no support for building new nuclear plants.
- Almost half of Germany’s electricity is generated from coal, and there are no plans to phase this out.
- Germany has some of the lowest wholesale electricity prices in Europe and some of the highest retail prices, due to its energy policies. Taxes and surcharges account for more than half the domestic electricity price.
In 2013 the share of electricity from gas declined 21% from 2012, and coal share rose before declining in 2014. In the first half of 2014 gas-fired input dropped a further 14% to 16.6 TWh, lignite provided 69.7 TWh, hard coal 51.9 TWh, nuclear 45.0 TWh, wind 26.7 TWh, solar 18.3 TWh, biomass 25.6 TWh and hydro 10.5 TWh. Total for six months: 264.3 TWh, of which 16.1 TWh was exported. (Fraunhofer Institute)
Preliminary IEA figures give Germany's electricity production in 2015 as 651 TWh gross. Of this, coal provided 282 TWh (43%, more than half being lignite), nuclear 92 TWh (14%), gas 61 TWh, biofuels & waste 58 TWh, wind 88 TWh, solar 38 TWh, hydro 25 TWh (IEA figures). Electricity exports exceeded imports by about 48 TWh, but Germany is one of the biggest importers of gas, coal and oil worldwide, and has few domestic resources apart from lignite and renewables (but see later section). Annual consumption is about 6300 kWh per capita. Gross consumption was 576 TWh in 2014, substantially below the peak 641 TWh in 2009.
Preliminary figures for 2016 show 648 TWh produced, demand of 593 TWh and net export of 55.5 TWh. Of the total, lignite provided 150 TWh, hard coal 110 TWh, nuclear 85 TWh (13%), gas 79 TWh, wind 80 TWh and other renewables 111 TWh (AG Energiebilanzen figures). The preponderance of coal makes the country Europe’s biggest emitter of carbon. The 2016 increase in renewables generation was the smallest since 2009.
Generating capacity at the end of 2014 was 198 GWe comprising 12.1 GWe nuclear, 11 GWe hydro, 39 GWe wind (0.6 GWe offshore), 38 GWe solar, and 97 GWe combustible fuels (IEA figures). Earlier in the year this comprised: 28.2 GWe gas, 21.2 GWe lignite, 26.3 GWe hard coal and 5.6 GWe biomass, according to the Fraunhofer Institute. In 2014 wind and solar PV had capacity factors of 17% and 11% respectively, compared with 92% for nuclear (IEA figures). In 2011 Russia provided almost 40% of the gas, followed by Norway, Netherlands and the UK, while 14% was produced domestically.
“Over the last decade, well-intentioned policymakers in Germany and other European countries created renewable energy policies with generous subsidies that have slowly revealed themselves to be unsustainable, resulting in profound, unintended consequences for all industry stakeholders. While these policies have created an impressive roll-out of renewable energy resources, they have also clearly generated disequilibrium in the power markets, resulting in significant increases in energy prices to most users, as well as value destruction for all stakeholders: consumers, renewable companies, electric utilities, financial institutions, and investors.” This is the introductory paragraph in a July 2014 report by Finadvice for the Edison Electric Institute and European clients. See later section with details of this.
In a 28 November 2015 Special Report The Economist, having pointed out that French households pay about half as much as German ones for electricity, commented: “Germany has made unusually big mistakes. Handing out enormous long-term subsidies to solar farms was unwise; abolishing nuclear power so quickly is crazy. It has also been unlucky. The price of globally traded hard coal has dropped in the past few years, partly because shale-gas-rich America is exporting so much. But Germany’s biggest error is one commonly committed by countries that are trying to move away from fossil fuels and towards renewables. It is to ignore the fact that wind and solar power impose costs on the entire energy system, which go up more than proportionately as they add more."
The country's 17 nuclear power reactors, comprising 15% of installed capacity, formerly supplied more than one-quarter of the electricity (133 TWh net in 2010). Many of the units are large (they totalled 20,339 MWe), and the last came into commercial operation in 1989. Six units are boiling water reactors (BWR), 11 are pressurised water reactors (PWR). All were built by Siemens-KWU. A further PWR had not operated since 1988 because of a licensing dispute. This picture changed in 2011, with the operating fleet being reduced to nine reactors with 12,003 MWe capacity, and then to eight reactors with 10,728 MWe. (See later sections.)
Responsibility for licensing the construction and operation of all nuclear facilities is shared between the federal and Länder governments, which confers something close to a power of veto to both.
When Germany was reunited in 1990, all the Soviet-designed reactors in the east were shut down for safety reasons and are being decommissioned. These comprised four operating VVER-440s, a fifth one under construction and a small older VVER reactor.
In 2000 the European Commission approved the merger of two of Germany's biggest utilities, Veba and Viag, to form E.ON, which owned or had a stake in 12 of the country's 19 nuclear reactors which were operating then. In 2016 E.ON spun off Uniper, which was to take over all its nuclear assets in 2016, but in the event left German nuclear plants with E.ON.
German nuclear power units
|2010 agreed shutdown
||March 2011 shutdown
& May 2011 closure plan
||shutdown June 2015
|Total shut down (9)
|Total operating (8)
NB. Most of the nine shutdown reactors are not yet defuelled and written off by their owners. No decommissioning licence had been granted to the end of 2016. Brunsbüttel and Krümmel were shut down in 2007, and not restarted, apart from a few weeks for Krümmel in 2009. Vattenfall started removing fuel from Krümmel in September 2016 to dry casks on site, and planned to start defuelling Brunsbüttel the following month. EnBW’s Phillipsburg 1 was defuelled by the end of 2016 and a permit for decommissioning and dismantling was expected in 2017. See Decommissioning section below for further information.
E.ON has equity in the following nuclear plants which from January 2016 will be managed by its subsidiary PreussenElektra: Isar 1 100%, Unterweser 100%, Krümmel 50%, Brunsbüttel 33.3% (all shut down), Grafenrheinfeld 100%, Gundremmingen B&C 25%, Grohnde 83.3%, Brokdorf 80%, Isar 2 75%, Emsland 12.5%. (From January 2016 E.ON spun off Uniper, which will take over E.ON’s “power generation in and outside Europe and global energy trading,” but “E.ON will retain responsibility for the remaining operation and dismantling of its nuclear generating capacity in Germany and not transfer it to Uniper” as originally envisaged. Uniper includes stakes in Swedish nuclear plants.)
RWE has equity in the following nuclear plants:
Gundremmingen 75%, Biblis 100%, Emsland 87.5%.
Vattenfall has equity in the following German nuclear plants:
Brunsbüttel 66.7%, Krümmel 50%, Brokdorf 20%. It has written off SEK 10.2 billion (€1.2 billion) on Brunsbüttel and Krümmel, and has applied to decommission both units.
Also in Sweden: Ringhals 70%, Forsmark 66%.
EnBW has equity in the following nuclear plants:
Neckarwestheim 100%, Phillipsburg 100%, and it has applied to decommission both units.
The Federal Ministry of Economics & Technology (BMWi) implements national energy policy.
Nuclear power policy
German support for nuclear energy was very strong in the 1970s following the oil price shock of 1974, and as in France, there was a perception of vulnerability regarding energy supplies. However, this policy faltered after the Chernobyl accident in 1986, and the last new nuclear power plant was commissioned in 1989. Whereas the Social Democratic Party (SPD) had affirmed nuclear power in 1979, in August 1986 it passed a resolution to abandon nuclear power within ten years.
The Grohnde nuclear power plant opened in 1989
The most immediate effect of this change of policy was to terminate R&D on both the high-temperature gas-cooled reactor and the fast breeder reactors after some 30 years of promising work, since much of the work was in North Rhine-Westphalia, which was governed by the SPD. A Christian Democrat (CDU) federal government then maintained support for existing nuclear power generation nationally until defeated in 1998.
In October 1998 a coalition government was formed between the Social Democratic Party (SPD) and the Green Party, the latter having polled only 6.7% of the vote. As a result, these two parties agreed to change the law to phase out of nuclear power. Long drawn-out "consensus talks" with the electric utilities were intended to establish a timetable for phase out, with the Greens threatening unilateral curtailment of licences without compensation if agreement was not reached. All operating nuclear plants then had unlimited licences with strong legal guarantees.
In June 2000 a compromise was announced which saved face for the government and secured the uninterrupted operation of the nuclear plants for many years ahead. The agreement, while limiting plant lifetime to some degree, averted the risk of any federally-enforced plant closures during the term of that government.
In particular, the agreement put a cap of 2623 billion kWh on lifetime production by all 19 operating reactors, equivalent to an average lifetime of 32 years (less than the 35 years sought by industry). Two key elements were a government commitment to respect the rights of utilities to operate existing plants, and a guarantee that this operation and related waste disposal will be protected from any "politically-motivated interference".
Other elements included: a government commitment not to introduce any "one-sided" economic or taxation measures, a recognition by the government of the high safety standards of German nuclear plants and a guarantee not to erode those standards, the resumption of spent fuel transports for reprocessing in France and UK for five years or until contracts expire, and maintenance of two waste repository projects (at Konrad and Gorleben).
In June 2001 the leaders of the 'Red-Green' coalition government and the four main energy companies signed an agreement to give effect to this 2000 compromise. The companies' undertaking to limit the operational lives of the reactors to an average of 32 years meant that two of the least economic ones – Stade and Obrigheim – were shut down in 2003 and 2005 respectively, and the one non-operational reactor (Mülheim-Kärlich, 1219 MWe) commenced decommissioning in 2003. Brunsbüttel was shut down in 2007, as was Krümmel, apart from a few weeks operation in 2009. The agreement also prohibited the construction of new nuclear power plants for the time being and introduced the principle of on-site storage for used fuel.
The agreement was a pragmatic compromise which limited political interference while providing a basis and plenty of time for formulation of a national energy policy. An industry leader reminded his government that "Reliable and cost-effective energy supply must remain an important component of German economic policy". Some speculation centred on the future of the agreement and the revised Atomic Energy Act which followed it under any new government. Parliamentary opposition party leaders said that they would reverse the decision when they could – in the event, eight years later*.
Utilities wanted to extend the lifetimes of all 17 reactors initially to 40 years (from average 32 years) and then individually seeking extensions to 60 years as in the USA.
The new Christian Democrat (CDU) and Liberal Democrat (FDP) coalition government elected in September 2009 was committed to rescinding the phase-out policy, but the financial terms took a year to negotiate. If reactor lifetimes were extended from average 32 years to 60 years, the four operating companies would have reaped additional gross profit of €100 billion or more, and the government was keen to secure more than half of this – much more than its extra tax revenue.
In September 2010 a new agreement was reached, to give eight-year licence extensions (from the dates agreed in 2001) for reactors built before 1980, and 14-year extensions for later ones. The price exacted for this was several new measures: a tax of €145 per gram of fissile uranium or plutonium fuel for six years, yielding €2.3 billion per year (about 1.6 c/kWh), payment of €300 million per year in 2011 and 2012, and €200 million 2013-16, to subsidise renewables and for funding rehabilitation at the Asse salt mine waste repository. A tax of 0.9 c/kWh for the same purpose would follow after 2016. However, utilities could reduce their contribution to renewables if safety upgrades to particular individual nuclear plants cost more than €500 million. At the end of October these measures were confirmed by parliamentary vote on two amendments to Germany's Atomic Energy Act, and this was confirmed in the upper house in November 2010.
All these arrangements were thrown into doubt when in March 2011 the government declared a three-month moratorium on nuclear power plans, in which checks would take place and nuclear policy would be reconsidered. Chancellor Angela Merkel decreed that the country's nuclear power reactors which began operation in 1980 or earlier should be immediately shut down. Those units then closed and were joined by another unit already in long-term shutdown, making a total of 8336 MWe offline under government direction, about 6.4% of the country's generating capacity. This decision was not based on any safety assessment, and did not result in removal of the nuclear fuel tax.
The reactors affected were Biblis A, Neckarwestheim 1, Brunsbuettel, Biblis B, Isar 1, Unterweser, Phillipsburg 1. Already in a long-term shutdown was Kruemmel and this was included despite having started up in 1984.
In May 2011 the Reaktor-Sicherheitskommission (RSK, Reactor Safety Commission) reported that all German reactors were basically sound, and safe. It had reviewed all 17 reactors and evaluated their robustness with respect to natural events affecting the plants, station blackouts and failure of the cooling system, precautionary and emergency measures as well as man-made events affecting the plant, e.g. plane crashes.
However, despite this safety assurance, on 30 May 2011, after increasing pressure from anti-nuclear federal states, the government decided to revive the previous government's phase-out plan and close all reactors by 2022 but without abolishing the fuel tax, thus reneging on the new fuel tax trade-off. The Bundestag passed the measures by 513 to 79 votes at the end of June, and the Bundesrat vote on 8 July confirmed this. Both houses of parliament approved construction of new coal and gas-fired plants despite claiming to retain its CO2 emission reduction targets, as well as expanding wind energy. This policy of replacing nuclear power with extra fossil fuel capacity and vastly expanding highly-subsidised renewables is known as the Energiewende. This is detailed in a companion information paper.
This left the eight oldest reactors closed, and promised to result in the remaining nine closing by the end of 2022. France, Poland and Russia (Kaliningrad) expected to increase electricity exports to Germany, mostly from nuclear sources, and Russia started to export significantly more gas.
The fuel tax expired at the end of 2016, and accordingly utilities had delayed refuelling five units until January and February 2017, resullting in about 3 TWh being lost from mid-December to the end of February.
Legal claims following March 2011
The country's four nuclear power utilities are pressing claims for compensation and in particular are suing the government over continuing with the nuclear tax introduced in relation to the 8- and 14-year licence extensions agreed in September 2010. Claims for compensation are also on the basis of write-down of plants, cancelled upgrades which were in train following the September 2010 policy change, and decommissioning costs brought forward. While RWE and E.On are public companies, Vattenfall is owned by the Swedish government, and EnBW 46.55% by the Baden-Wuerttemberg government, then a Social Democrat-Green coalition. Another 46.55% of EnBW is owned by the state’s municipalities.
In September 2011 the government's continuing tax on nuclear fuel was rejected by the Hamburg Tax Court. The Court expressed "serious doubt" that the nuclear fuel tax was compatible with the German constitution. It granted a request from E.On to refund some €96 million, and nuclear fuel tax collections were to be suspended. The first lawsuit had been brought by EnBW, which had paid the tax when it refuelled a reactor in July and quickly launched legal action, claiming the tax was unconstitutional and contrary to EU law. The court's judgement said that the tax does not qualify under the constitution as a consumption tax, and anyway those should not be applied to single-purpose supplies like nuclear fuel. The court took its decision based on these constitutional points and did not consider other areas the utility had contested: whether the tax violated equality laws or EU directives on taxation. In October RWE and E.ON were refunded €74 and €96 million respectively. However the government then challenged the ruling and resumed collections of the tax.
In January 2013 the Hamburg Tax Court ruled more definitely that the German tax on nuclear fuel is simply "to siphon off the profits of the nuclear plant operators" and therefore unconstitutional. It referred the question to the Federal Constitutional Court and the EU Court of Justice (ECJ). E.ON, RWE and EnBW have said the tax, of which they have paid about €5 billion, is illegal and favours other electricity sources, and have called for the tax to be repaid. Since January 2011, E.ON had paid €2.3 billion in nuclear fuel taxes, EnBW had paid €1.1 billion, and RWE had paid €1.6 billion by the end of 2015, as well as bearing much greater costs with reduced revenue from the government's policy U-turn in March 2011. In April 2014 the Hamburg Tax Court upheld a demand from nuclear operators to refund about €2.2 billion, on the basis that the tax was a levy on profits and unconstitutional. But the court also allowed the matter to be referred to the Federal Fiscal Court (in addition to the cases pending at the Constitutional Court and the European Court of Justice).
In a non-binding preliminary opinion in February 2015, the EU Court of Justice found that the German nuclear fuel tax on utilities “that will be used to pay for decommissioning power reactors in the country” was legal, and that it did not violate EU taxation rules on electricity. Then in June 2015 judges at the Luxembourg-based Court of Justice of the European Union (ECJ) ruled “that EU law does not preclude a duty such as the German duty on nuclear fuel." The court also said the duty on nuclear fuel did not constitute illegal state aid to non-nuclear sources. The three utilities are now awaiting the outcome of their lawsuit filed with the Federal Constitutional Court, which could still rule the tax impermissible under German law.
An extended comment on the legal situation by a German energy law specialist was published by World Nuclear News (10 June 2015).
In March 2014 E.On announced to BNetzA that its 1275 MWe Grafenrheinfeld nuclear power plant in Bavaria would close earlier than December 2015, due to the fuel tax of some EUR 80 million making it uneconomic to refuel for that last period. In June 2015 when it closed it had operated 33 years.
Apart from contesting the fuel tax, all the nuclear generators are seeking compensation for the effective confiscation of generating rights from the eight reactors ordered shut after March 2011, despite safety assurances from the regulator as noted above.
RWE filed a lawsuit against the government regarding closure of its Biblis-B and said that the phase-out cost the company over €1 billion in 2011 alone. In February 2013 the administrative court in Hesse found that the government had had acted illegally in ordering the closure of Biblis A & B in March 2011. In January 2014 the German Supreme Administrative Court endorsed this by ruling that the forced closure of the Biblis plant by the state was "formally unlawful because [RWE] had not been consulted and this constituted a substantial procedural error." Biblis A and B, total 2407 MWe net, had been licensed to operate until 2019 and 2021 just two months before the shutdown order. Claims for damages will be decided subsequently and are expected to be over €2 billion.
E.On is also seeking €8 billion in compensation. In July 2016 a regional court in Hannover ruled that the company was not entitled to €382 compensation for the early closure of Isar 1 and Unterweser units. The decision was based on EnBW’s failure in April in a Bonn court, and due to the company’s failure to seek immediate legal action against the moratorium.
Vattenfall in June 2012 contested the confiscation of generation rights for the Brunsbüttel and Krümmel nuclear power plants, and filed the case with the autonomous International Centre for Settlement of Investment Disputes (ICSID) in Washington, which was designed in 1965 by the World Bank and established by a convention now signed by 143 countries. It had previously said simply that it expects full compensation for its costs, which it noted as SEK10 billion ($1.5 billion) for the first half of 2011 alone. In mid-2013 it announced a SEK 10.2 billion (€1.2 billion) write-off on those two plants. In October 2014 the energy minister said Vattenfall was seeking €4.7 billion compensation, the company saying that this was based on the Energy Charter Treaty which provides security to corporate investments against political risks. The ICSID opened its hearing in October 2016.
EnBW supports the legal actions brought by the other utilities, saying that the government’s actions infringe its property rights. By May 2014 it had paid €790 million in the fuel tax for its two closed reactors. In December 2014 EnBW said it would file suit against the federal and state governments, on the same basis as RWE, which was awarded €235 million (which has been appealed by the Hesse state government). It sought compensation of €261 million, but a regional court in Bonn ruled in April 2016 that the claim could not be allowed to stand because EnBW had not immediately used “all legal means available” to avert having its two reactors – Neckarwestheim 1 and Phillipsburg 1 – shut down.
The four utilities have made provisions of over €30 billion on account of the government decisions, and the German government appears to be facing claims of this magnitude.
Reuters reported in October 2015 that: “Since Fukushima, shares in Germany's top three energy groups – E.ON, RWE and EnBW – have lost an average 56 percent, or €50 billion in combined market value, while racking up €65 billion in net debt, about twice their current combined market value. They have filed lawsuits against the government, claiming more than €24 billion related to Merkel's nuclear policy, which they claim is unfair and has rid them of one of their main profit centres overnight.”
In May 2013 EnBW submitted applications to finally decommission and demolish sections of its Neckarwestheim 1 and Phillipsburg 1 plants. In late 2012 Vattenfall Europe submitted an application to decommission and dismantle Brunsbüttel, and in August 2015 it applied similarly for Krümmel, to be undertaken over a 15-20 year period.
Transmission and supply implications
The German federal network agency and grid authority, Bundesnetzagentur (BNetzA), reported at the end of May 2011 on the implications of plans to close down nuclear generation. It strongly warned of resulting vulnerability to major failures and also unreliability especially in the south. Grid stability was the major concern, along with generation and transmission capacity.
A bill introduced to the Bundestag in March 2013 identified 36 transmission projects costing some €10 billion as high priorities. The government wanted to reduce the timeframe for new power lines to four years on average, and the Federal Administrative Court would handle any legal cases arising from the power line developments, a measure to speed up the projects. Previously lawsuits could be brought in local or regional courts. Meanwhile Germany depends on neighbouring countries to route its power from north to south. The Czech government in 2012 complained it was close to a blackout because the German wind farms overloaded its grid. Early in 2014 the Bavarian government called for a moratorium on TenneT’s and TransnetBW’s SuedLink proposal linking Schleswig-Holstein in Germany's north to connect with the southern grid at the Grafenrheinfeld nuclear plant which closed down at the end of June 2015. This is near Schweinfurt in northern Bavaria.
More broadly, onshore high-voltage grids in Germany will have to undergo considerable expansion in the next decade to facilitate Energiewende and the development of the European electricity market. The network upgrades and additions would require investment of some €20 billion by 2022. The four TSOs estimate that expanding wind power on the North and Baltic Seas would cost another €12 billion TenneT expects to invest at least €22 billion by 2025 (not all in Germany), and another of the transmission companies estimates its own costs until 2025 to be €10 billion. While these investments "account for only a fraction of the cost of the energy transition, much success depends on their implementation." Failure to upgrade the electricity transmission grid would cause higher costs elsewhere. In May 2016 BNetzA put the cost of the required 7000 km of new transmission lines at €35 billion, with priority given to the three north-south links by 2022 when the last nuclear plant is due to close.
Early in 2016 grid projects were broadly covered either by the energy network expansion law Energieleitungsausbaugesetz (ENLAG) of 2009 or by the 2015 federal transmission system needs act, BBPlG (Bundesbedarfsplangesetz). ENLAG aimed to expedite 22 urgent transmission projects identified by DENA, and nearly all of these should be completed by 2020. Completion of the Thüringer Strombrücke line (or Südwest-Kuppelleitung) from Lauchstädt to Redwitz, at the end of 2015 was a major landmark for TenneT. Another 43 projects are identified in the BBPlG, based on the 2014 version of the Network Development Plan (NEP) presented annually by TSOs to the BNetzA. BBPlG projects are subject to accelerated planning procedures carried out by the regulator, and BBPlG brings legal force to a mid-2015 decision to prioritize underground cabling of HVDC cables over overhead lines, where previously the opposite had been the case. The change arose largely from Bavarian opposition to overhead lines. In October 2015 the government approved plans for about 1000 km of high-voltage transmission lines from the north and close to populated areas to be built underground. The energy ministry estimated that the underground option would cost €3 to 8 billion more than overhead lines, to be added to consumers’ bills, but was expected to speed up approvals. TenneT warned of cost and schedule delays to the SuedLink project (corridor C).
Maintaining grid stability in 2015 cost more than €1 billion, due to redispatch* where prioritised renewable power causes transmission congestion and conventional power stations are paid to reduce output. The four TSOs said that redispatch costs could rise to €4 billion per year by 2020, and BNetzA agreed that this was not unrealistic, given slow progress with transmission expansion. The German Chambers of Commerce and Industry (DIHK) estimates redispatch costs at €30 billion over 2016 to 2025.
* Redispatching is an intervention in the market-based operating schedule of generating units in order to shift feed-ins from power stations. Based on the contractual obligations of TSOs, power stations are instructed to reduce their feed-in power, while other power stations are simultaneously instructed to increase their feed-in power. Redispatching is used by network operators to ensure the safe, reliable operation of electricity supply networks. It is carried out to prevent power lines becoming overloaded or to relieve overloading on power lines. The network operator must reimburse the power stations participating in the redispatch for the costs they incur.
There is considerable cross-border trade as neighbouring countries are called upon to take cheap power when there is temporary surplus, mostly from wind. This is low-cost, and may affect the markets in those countries. During 2015, the main exports were 23.7 TWh to Belgium (half going onto the Netherlands), 14.5 TWh to Austria, 12.5 TWh to Switzerland, 11.5 TWh to France, 8.2 TWh to the UK, 10.7 TWh to Poland. The main import was 5.8 TWh from Norway’s hydro. In addition, a lot of northern renewable power is routed south through Poland and Czech Republic. This loop flow is leading to proposals for a north-south price zone split.
Replacing and closing down conventional generating capacity
Bundesnetzagentur (BNetzA) has received numerous requests from operators to retire coal- and gas-fired plants which have become unprofitable, and it has approved many of these as over 10 GWe of new coal-fired capacity comes online. However, particularly in the south, plant closures have exceeded new capacity coming online. E.On’s 1275 MWe Grafenrheinfeld nuclear reactor was closed in mid-2015. This gave rise to a net reduction of southern capacity of 1.7 GWe, and by the end of 2018 BNetzA predicts a 5.6 GWe net deficit in the south, rising to 7 GWe in 2020.
In March 2015 E.On and co-owners applied to BNetzA to close down two state-of-the-art almost new CCGT plants, Irsching 4&5 (550 & 846 MWe) in southern Germany from April 2016. They have thermal efficiency of about 60%. They have been running under an arrangement which is break-even, but due to the increase in subsidized renewables’ output and low wholesale power prices, the two CCGTs “have no prospect of operating profitably when the current contract with the network operator expired in March 2016,” the owners said. Nevertheless in September 2015 TenneT TSO prohibited the planned closures by declaring the units to be system-relevant (as Irsching 3 and another E.On unit have been), so that they therefore need to be kept operational though run at a loss. The Bundesverband der Energie- und Wasserwirtschaft (BDEW) said that the economic viability of more than half of Germany’s planned power plants was called into question by government policies.
Most coal capacity is not likely to be shut down before 2020. While gas plants fit better as back-up for expanded renewables, they are less economic than coal, and gas supplies are uncertain, especially since sanctions applied due to Russia’s annexation of Crimea. About 35% of Germany’s gas is imported from Russia, and fracking is banned.
BNetzA in October 2013 received requests from operators to retire 28 power plants with a combined capacity of nearly 7 GWe, and it approved the closure of 12, with 5 GWe – ten in North-Rhine Westphalia and two in Lower Saxony in the northwest. However, the following month BNetzA said that through to 2018 it expected 10.9 GWe to come on line – mostly coal – and 9.94 GWe to be decommissioned, mostly coal and gas but including the Grafenrheinfeld nuclear plant of 1275 MWe by the end of 2015 and the Gundremmigen B plant of 1284 MWe two years later.
In July 2014 planned closures exceeded conventional capacity under construction by 4.7 GWe, and the difference in southern Germany was 5.7 GWe. Only 62% of the planned closures had been authorised then, with some utilities awaiting confirmation of plans for a capacity market. RWE said it supports plans for capacity markets designed by industry associations BDEW and VKU to guarantee security of supply. However proposals for a capacity market were rejected in 2015.
Economic and CO2 implications of nuclear policy changes
Fuelling the earlier dispute within the grand SDP-Green coalition government then in power, a January 2007 report by Deutsche Bank warned that Germany would miss its carbon dioxide emission targets by a wide margin, face higher electricity prices, suffer more blackouts and dramatically increase its dependence on gas imports from Russia as a result of its nuclear phase-out policy, if it were followed through. The Economy Minister and utility owners called for urgent review of the policy. The Bank estimated that 42 GWe of new generating capacity would need to be constructed by 2022 if shutdowns proceeded.
In May 2007 the International Energy Agency warned that Germany's decision to phase out nuclear power would limit its potential to reduce carbon emissions "without a doubt." The agency urged the German government to reconsider the policy in the light of "adverse consequences." If Germany both continued with its nuclear phase-out policy and maintained carbon emission reductions, by about 2020 it would need to depend on some 25,000 MWe of base-load electricity capacity across its borders. The country already has significant interconnection with France, Netherlands, Denmark, Poland, Czech Republic and Switzerland. Connection with Russia's Kaliningrad Baltic exclave, where a 2400 MWe Russian nuclear plant was planned, was envisaged and Russia expected to export half the output of that plant to Germany until confronted with political realities which caused the Baltic plant construction to be put on hold. In any case, increased nuclear capacity in several of those neighbouring countries – and pre-eminently France – could easily, by 2020, supply 25,000 MWe through much-expanded interconnection. This would put Germany in 2020 in much the same position as Italy, being dependent on neighbours for electricity (which would be mostly nuclear) and being a price-taker.
However, in September 2010 then March and May 2011 as described above, policy changed again twice, and in September 2011, a study from KfW Bankengruppe, which supports domestic developments, said that about €25 billion per year would be required to meet the government's Energiewende nuclear phase-out goals. It put the total capital investment at €239-262 billion by 2020. This included up to €10 billion on fossil fuel plant, €144 billion on renewables plant and up to €29 billion on 3600 km of high-voltage transmission lines. The bank noted that large capital-intensive projects have a tendency to go over budget.
Meanwhile Germany spends some €2.5 billion per year subsidising its coal mines to produce almost half of its electricity (cf nuclear 31% to 2011 with no subsidy). Well over half of this power is from brown coal, which produces about 1.25 tonnes of carbon dioxide per MWh. Arising from the Kyoto accord, and as part of the differentiated EU 'bubble', Germany was committed to a 21% reduction of greenhouse gas emissions by 2010.
In February 2013 the Federal Minister for the Environment, Nature Conservation and Nuclear Safety said that the costs of Energiewende by the end of the 2030s could reach €1000 billion. Feed-in tariffs subsidising renewables alone would cost some €680 billion by 2020, and that figure could increase further if the market price of electricity fell, he warned.
In 2012 renewable power producers collected some €20 billion for electricity having a wholesale market value of €3 billion. The difference between projected feed-in tariffs and market revenues forms the essential part of the EEG surcharge applied to most consumers. In 2016 the difference between payments to operators of renewable energy plants and their revenue from selling electricity was expected to be €24 billion. This excludes transmission costs and redispatch costs, and takes no account of losses incurred by reduced utilization of conventional nuclear and fossil fuel capacity.
The wholesale electricity price is based on marginal cost pricing, and with the output from wind and solar PV being often virtually zero marginal cost, increasing proportions of these has driven down average wholesale prices since 2008, and in 2016 it was about 60% below the average 2011 level. Hence many power stations with higher marginal costs are displaced from the market by merit-order effect, and this has been seen most acutely with gas-fired plants, where average capacity factor had dropped to 23% in 2016. Coal-fired plants require more EU ETS emissions certificates, but while these have been cheap it is more economic to keep these coal-burners in operation to supply nearly half the country’s electricity in defiance of Energiewende, and in 2016 the government backed off on plans to close them down.
The retail picture is in contrast to wholesale electricity prices. The prices of electricity for private and most commercial customers have risen sharply as Energiewende took hold. Early in 2016 the price for private households was more than 90% above the average level of 2000, due largely to the EEG surcharge or Umlage which now comprises 21% of the total, adding to taxes comprising 23% of the total. Over 2005-14 residential electricity prices in Germany increased by more than the average total residential cost in the USA.
Germany's decision to shut its nuclear plants means that back-up for its massive investment in intermittent new renewables needs to be from coal and gas, which will create an extra 300 million tonnes of CO2 to 2020 from increased fossil fuel use. That will virtually cancel out the 335 Mt savings intended to be achieved in the entire European Union by the 2011 Energy Efficiency Directive from the European Commission. But Energiewende locks Germany into long-term dependence on lignite and black coal for dispatchable capacity, contrary to a major aspect of the popular sentiment driving that policy, and its predecessors.
In 2015 Germany’s electricity exports doubled to 60 TWh, mainly from low-cost lignite and surplus wind generation – it was a windy year. These exports have a similar effect in neighbouring countries as in Germany, depressing wholesale power prices and compromising the profitability of gas-fired generation. Hence German coal-fired plants maintain high CO2 emissions quite broadly.
Germany's CO2 emissions from industry and power stations have diminished very little from 2008 to 2015, suggesting that the 2020 target of 20% reduction from 2007 levels by 2020 is not attainable.
German Generating costs 2013 (Fraunhofer Inst)
||Full-load hours per year
||Consequent capacity factor (%)
||7.8 - 14.2
||4.5 - 10.7
||11.9 - 19.4
||13.5 - 21.5
||3.8 - 5.3
||6.3 - 8.0
||7.5 - 9.8
|Household retail price
Electricity from renewable energy, feed-in tariffs
As Germany's attitude to nuclear energy became ambivalent, policies were adopted to promote renewable sources, notably solar and wind, though Germany is not well placed geographically in relation to either. Such policies are primarily to reduce carbon dioxide emissions. By 2020 it is planned that wind and solar renewables should contribute 20% of electricity supplies, compared with 11% at present (7.5% wind, 4.5% solar). Due to the feed-in tariffs of the Renewable Energy Sources Act (EEG – Erneuerbare Energien Gesetz) passed in 2000, wind power has become the most important renewable source of electricity production in Germany. From 12,000 MWe in 2002, at the end of 2015, 44.9 GWe of wind capacity was installed, 32% of EU total, according to the Global Wind Energy Council. Solar PV capacity was about 40 GWe in 2015. Of the total 647.1 TWh gross generation in 2015, wind provided 86.0 TWh (13.3%) and solar 39.5 TWh (5.9%).
Renewable electricity fed into the grid was paid for by the network operators at fixed feed-in tariffs (FITs), the costs being passed onto electricity consumers, so that there are no subsidies by the government itself. The tariffs are different for specific technologies and subject to a reduction of about 5% each year as an incentive for price reductions in new plant. The price is guaranteed for 20 years after completion of the plant, so that the operators have confidence in their planning criteria.
Capacity factors for wind and solar PV were 17% and 11% respectively in 2012, and solar was 9.5% in 2013 and 12.3% in 2015. The coalition parties in the new government from late 2013 agreed to reduce the capacity targets from those set in 2010 and to revise the EEG law to reduce subsidies for renewable energy projects (see below). It appears that this will take priority over reforming the EU’s Emissions Trading Scheme (ETS), which Germany took a lead role in establishing.
Since 2013 Germany has had occasions of negative spot power prices due to reduced demand and windy weather. Month-ahead base-load prices were then over €40/MWh.
The Finadvice report in July 2014 said that the lessons learned from the German Energiewende included:
- Policymakers underestimated the cost of renewable subsidies and the strain they would have on national economies.
- Retail prices to many electricity consumers increased significantly, more than doubling 2000 to 2013.
- The rapid growth of renewable energy reduced wholesale prices in Germany, with adverse consequences on markets and companies.
- The wholesale pricing model changed as a result of the large renewable energy penetration, now reacting to the weather.
- Fossil and nuclear plants are facing stresses to their operational systems as they are now operating under less stable conditions.
- Large-scale deployment of renewable capacity does not translate into a substantial displacement of thermal capacity.
- Large-scale investments in the grid are required.
- Overgenerous and unsustainable subsidy programmes resulted in numerous redesigns of the renewable support schemes, which increased regulatory uncertainty and financial risk for all stakeholders in the renewable energy industry.
Revised Renewable Energy Sources Act 2014, and subsequent revisions
Following the September 2013 elections, the CDU-led government pledged to reform the 2000 Renewable Energy Sources Act (EEG – Erneuerbare Energien Gesetz), diminishing the reliance on feed-in tariffs for new solar and wind power output and favouring dispatchable generation which can respond to demand. The Federation of German Industries (BDI) and other industry groups had been lobbying for a curb on feed-in tariffs, and household consumers were being hurt by high prices. This also raised the possibility of shifting some of the cost burden onto industries which had been exempt from the EEG surcharge or Umlage.
After consultations with 16 states, the federal government in April 2014 announced draft revisions of the EEG to limit energy price rises. The new law would hold the EEG surcharge at 6.24 c/kWh through to 2017, the renewable energy caps announced earlier were confirmed: offshore wind 6.5 GWe by 2020 and 15 GWe to 2030, onshore wind 2.5 GWe net added per year, solar PV also 2.5 GWe per year added. The caps are designed to allow about 11 TWh renewables growth each year. Renewables support continues to be granted for a 20-year operating period, albeit at much lower rates after the first five years.
Except for small plants, most renewables power sales are to be by ‘direct marketing’ by generators, with revenue supplemented by premiums calculated as the difference between the fixed feed-in tariff and the average wholesale price of electricity. The new arrangement is in place of feed-in tariffs, which the EC had ordered to be phased out over 2016-20. The new law took effect in August 2014. In October 2014 the TSOs reduced the EEG surcharge slightly to 6.17 c/kWh for 2015, but for 2016 it is set at 6.354 c/kWh.
One major issue is whether industry on-site power generation should be subject to the EEG surcharge. Some 50 TWh/yr is now generated by individual industry autoproducers to ensure reliability of supply, about 25% of the power used in industry. In the draft act, established autoproducers continued to be exempt, as were businesses which are fully independent of the grid, but other industry sources will pay 50% of the 6.24 c/kWh, or 15% in certain situations. This exemption was changed in the amended legislation after EC involvement. Other changes included reduced subsidies for renewables, and from 2017 those sources will have to compete.
At the end of 2015 the EEG was again revised for 2016 onwards, with renewables limited to 45% in 2025 and 60% in 2035 in order to synchronize with network expansion, to secure planning and development of the conventional (fossil and nuclear) power station fleet and so that Germany’s neighbours can adapt their own electricity systems to predictable renewable energy additions. The proposals for EEG 2016 say support for onshore wind, offshore wind and large PV plants with more than 1 MWe will be fixed in an auction system from 2017, to cover 80% of renewables generation produced in newly-installed plants each year. For other plants, no change from EEG 2014.
The process of revising the EEG was carried out as part of a broad consultation on the future electricity market, referred to by the Federal Ministry for Economic Affairs and Energy (BMWi) as 'Electricity Market 2.0'. This commenced with the publication in October 2014 of a green paper, followed in July 2015 by a white paper titled An electricity market for Germany’s energy transition. This led to the new Act on the Further Development of the Electricity Market (Gesetz zur Weiterentwicklung des Strommarktes), which was passed by both houses of parliament in July 2016, heralded by the energy minister as “the biggest reform of the power market since the liberalization in the 1990s.” Also referred to as the Electricity Market Act (Strommarktgesetz), it establishes the primacy of energy-only markets and replaced politically-set feed-in tariff support with competitive tenders for renewables. The legislation reinforces the central role of the wholesale power market by allowing uncapped scarcity pricing for electricity, and outlines various capacity reserves to assist security of supply while reducing sector emissions of CO2. These reserves include the provisions of the June 2013 regulation on reserve power plants to counter the transmission restriction from north to south, and new capacity and security (lignite) reserves.
Electricity from new coal-fired plants
With low EU ETS carbon prices, coal is more profitable than gas, and there is an incentive to use lignite, despite its higher CO2 emissions. In August 2016 Germany's black coal-fired capacity was 28 GWe (providing 18% of power) and lignite capacity was 21 GWe (providing 24%). Gas-fired capacity was 28.5 GWe (providing 14%).
Coal-fired capacity under construction and expected online by 2016 includes: RWE – Hamm Westfalen 750-800 MWe; RWE, EnBW & MVV Energie – Mannheim 900 MWe; E.ON – Datteln 1000-1100 MWe. Vattenfall Europe in December 2010 secured approval for a 1,640 MWe coal-fired plant at Moorburg after two years of opposition by agreeing to environmental measures which will curb profitability. In addition RWE and E.ON have 2650 MWe in the Netherlands. Some old coal-fired plants have been kept in service to avert shortages, while others have closed.
An insight on the continued reliance on lignite can be gained from RWE, which in 2012 commissioned BoA units 2&3 in North Rhine-Westphalia near Cologne, 2200 MWe billed as “the world’s most advanced lignite-fired power station” and costing €2.6 billion. Each unit can drop from full power by 500 MWe in 15 minutes and then recover as required, “demonstrating the power station’s ability to offset the intermittency of wind and solar power.” RWE said: “BoA 2&3 is an important element of our strategy, for modern coal and gas-fired power stations are indispensable. Unlike wind and solar sources, they are highly flexible and capable of producing electricity 24/7, which makes them the trump card of energy industry transformation.” The state premier said that the plant was “an important contribution to security of supply.”
In total, 10.7 GWe of new coal-fired capacity was to come online over 2011-15, much of this as a result of plans predating March 2011, rather than as a response to nuclear phase-out plans.
In July 2015, after months of intense negotiations, the government scrapped its proposed levy on coal-fired plants and resolved that as part of the revised capacity mechanism regime within the Electricity Market 2.0 some 2.7 GWe of lignite-powered generating capacity (representing about 13% of installed lignite power) would be gradually transferred to a 'security standby reserve' (Sicherungsbereitschaft). This would be over 2016 to 2020 by negotiation with RWE (1.5 GWe), Vattenfall (1.0 GWe) and Mibrag. This capacity would be brought online when needed and then progressively shut down after four years. The three utilities would receive €230 million per year compensation over seven years, total €1.6 billion. The EC approved the arrangements in May 2016 under state aid rules.
In Germany, 178 million tonnes of lignite was mined in 2014. To achieve this, 879 Mt of overburden was removed, so total earthmoving on one year was 14 times that for building the Suez canal. The heat value of German lignite ranges from 7.8 to 11.3 MJ/kg, and has around 50% water content. It is used almost entirely for electricity production domestically or in nearby countries, though some is used for industrial heat. RWE is the largest lignite power producer, and electricity costs from lignite can be as low as €15/MWh (typically €18-24, compared with black coal €22-32 marginal costs/MWh). Pulverised lignite (LEP) has water reduced to about 11% and correspondingly higher calorific value, so is increasingly traded for industrial heat applications and municipal CHP plants. Vattenfall is a leading player in this along with Mibrag Mining Corporation which rails lignite up to 400 km, and Rheinbraun Brennstoff which supplies a Swiss cement factory 600 km away with lignite.
From 1946 to 1990, some 220,000 tonnes of uranium (260,000 t U3O8) was mined in the former GDR, in Saxony and East Thuringia, notably at Wismut, with substantial environmental damage. Much of this was used in Soviet weapons programs, and for fuel in Eastern Europe. In 1991, 1207 tU was produced, in 1992: 232 tU and thereafter small amounts resulting from decommissioning and mine closure activities.
A small mine. Ellweiler, operated in West Germany 1960-89. All uranium is now imported, from Canada, Australia, Russia and elsewhere, a total of 3800 t/yr U.
Annual demand for enrichment is about 2.2 million SWU, most of which is provided by Urenco's Gronau plant, with capacity of 1.8 million SWU/yr being expanded to 4.5 million SWU/yr, following 2005 approval by the government coalition. Over 2006-09 the Gronau plant processed about 4500 tonnes per year of UF6, generating about 4000 t/yr of tails. This will double when the new capacity is on line. The licence for expansion limits tails storage to 38,000 t UF6 and 59,000 t deconverted to U3O8.
Most of the depleted uranium tails from the Gronau plant have been sent to Novouralsk in Russia for re-enrichment, but these arrangements finished in 2010. Over 2007 to 2009 Urenco sent 6500 t of tails assaying 0.30% U-235 to Novouralsk for re-enrichment, and 402 tonnes assaying 0.235% to Eurodif in France for re-enrichment. From Russia 270 tonnes of enriched uranium product was returned in this period.
In 2008 & 2009 Urenco shipped 518 tonnes of tails assaying 0.26% or less from Gronau to Areva's W Plant at Pierrelatte in France for deconversion. To the end of 2009, 1700 tonnes of UF6 from Gronau had been deconverted there and returned to Gronau as U3O8.
Fuel fabrication is undertaken by Areva, mostly at Lingen in Germany.
Thirteen German reactors are licensed to use Mixed Oxide (MOX) fuel, using plutonium recycled from spent fuel. A MOX plant at Hanau in Hesse has never been allowed to operate, so all MOX fuel is imported.
Until 1994 utilities were obliged to reprocess spent fuel to recover the usable portion and recycle it. From 1994 to 1998 reprocessing and direct disposal were equally acceptable to the federal government, but the policy of the coalition government from 1998 to 2009 was for direct geological disposal of spent fuel and no reprocessing after mid-2005 (although firm contracts for reprocessing, totalling US$ 7.3 billion, were in place with BNFL and Areva).
Radioactive Wastes – policies
In 1963 the federal government issued a recommendation to use geological salt formations for radioactive waste disposal. In 1973 planning for a national repository started, and in 1976 the Atomic Energy Act (AtG) was amended to make such disposal a responsibility of the federal government.
In July 2013 two acts were passed, the Repository Site Selection Act (StandAG) and another to establish a Federal Office for the Regulation of Nuclear Waste Management (Bundesamt für kerntechnische Entsorgungssicherheit, BfE) under the Ministry for Environment, Nature Conservation, Building and Nuclear Safety (BMU). The BfE regulates the site selection process and supports the ministry in relation to final disposal of radioactive wastes. Its initial task was to ensure the refinancing of the site selection process, and then supervise site selection, evaluate proposals, certify that selection is properly undertaken according to the StandAG, oversee environmental assessment and present a final proposal for a site. Following the commissioning of the Konrad final repository for low- and intermediate-level wastes and approval for decommissioning of Morsleben, it will grant relevant licences and permits to proceed with final waste disposal.
The federal government through the Federal Office for Radiation Protection (Bundesamt für Strahlenschutz, BfS) has been responsible for building and operating final repositories for high-level waste, but progress in this has been hindered by opposition from Länder governments. The BfS is responsible for licensing all nuclear waste transports.
In 2013 the federal environment ministry (BMU) announced that the federal government and all 24 states had finally reached agreement on drafting a repository law (see above), and that the power utilities should spend €2 billion to find and develop a new repository. The industry body representing the companies responded that they were not prepared to do so, having already invested nearly that much in Gorleben. However, the new Repository Site Selection Act (StandAG) which was passed in July 2013 created a 33-member commission in May 2014 to develop ‘basic principles’ for site selection, including safety and economic requirements, and selection criteria for rock formations. The commission included representatives from parliament, academia, civil society organizations, industry, the environment and trade unions. Its initial recommendations offering a "comprehensive approach to responsible and safe disposal of all radioactive waste" were adopted by the cabinet in August 2015, with the plan to be submitted to the EC for approval. The commission’s final report was submitted to the government in July 2016.
According to the commission's final report, the site with "the best safety" is to be determined in a three-phase process and defined by federal law. The site selection should be accompanied by extensive public participation with bodies at regional, inter-regional and national level. The repository could be located in salt, clay or crystalline rock. The commission said the "controversial" Gorleben rock salt formation in Lower Saxony has not been excluded in its report.
The report projects some 10,500 tonnes of used fuel from the operation of nuclear power plants, which could be stored in about 1100 containers. A further 300 containers of high- and intermediate-level wastes are also expected from the reprocessing of used fuel, as well as 500 containers of used fuel from research and demonstration reactors. While the former Konrad iron ore mine in Salzgitter is favoured for low- and intermediate-level wastes (see below), another as yet undetermined site for high-level wastes remains to be identified. The German Atomic Forum (Deutsches Atomforum, DAtF), said: "In addition to the process and criteria, the commission has also developed a comprehensive and extremely ambitious involvement process that should give citizens, particularly in affected regions, far-reaching opportunities for participation. A consistent and targeted approach is needed to arrive at a solution to this long-disputed issue.”
In December 2016 the Bundestag in a 581-58 vote resolved to create a €23.6 billion state-owned fund to pay for the interim storage and disposal of all German used fuel and nuclear wastes. The four nuclear utilities will provide the funding and will then have no further financial responsibility. The total includes a 35% risk premium in case costs are greater than anticipated. Earlier the energy minister said that the legislation "clarifies responsibility for nuclear waste. It ensures the long-term financing for decommissioning, dismantling and disposal without the transfer of costs to society or jeopardizing the economic situation of operators." It is reported that RWE and E.On will pay €16.7 billion between them, and Vattenfall €1.75 billion, leaving €5.15 for EnBW. The companies have already set aside some €38 billion for decommissioning their reactors – see section below.
Radioactive wastes – sites and operations
The utilities are responsible for interim storage of spent fuel, and have formed joint companies to build and operate offsite surface facilities at Ahaus and Gorleben. However, current policy is for interim storage at reactor sites. In mid-2013 the licence for interim storage at Brunsbüttel was revoked, having been granted for 40 years in 2003. The facility was commissioned in 2006. In 2016 BfE gave EnBW permission to move used fuel from the shutdown Obrigheim plant to interim storage at Neckarwestheim, to allow decommissioning at Obrigheim to proceed. In September 2016 Vattenfall was given permission by the state government to transfer 990 fuel assemblies from the storage pool at Krümmel into CASTOR dry storage casks onsite. It has applied to build a warehouse there for low- and intermediate-level wastes which will later go to the Konrad repository.
GNS Gesellschaft für Nuklear-Service mbH (GNS) set up in 1977 and owned by the four nuclear utilities is responsible for all operations regarding the transport and disposal of waste in Germany, at nine sites. It also offers products and services outside Germany – it secured a €1.52 million contract with Sogin in Italy in 2015 for decommissioning and waste disposal. Its 75%-owned subsidiary Deutsche Gesellschaft zum Bau und Betrieb von Endlagern für Abfallstoffe mbH (DBE) constructed and operatesd repositories, notably Konrad and Gorleben, while decommissioning Morsleben. GNS developed the various types of CASTOR and CONSTOR casks for transporting and storing used fuel.
Following an exhaustive site selection process the state government of Lower Saxony in 1977 declared the salt dome at Gorleben to be the location for a national centre for disposal of radioactive wastes. It is now considered a possible site for geological disposal of high-level wastes. These will be about 5% of total wastes with 99% of the radioactivity. A pilot conditioning plant is there. The site could be available as a final repository from 2025, with a decision to be made about 2019. Some €1.5 billion was spent over 1979 to 2000 researching the site, and the investment in it from the power utilities now stands at about €1.6 billion. Work stopped in 2002 due to political edict, but in October 2010 the BfS on behalf of the federal government applied to resume studies and extend the operating licence to 2020. Lower Saxony allowed this, and in 2013 it agreed that Gorleben should not be ruled out in further considerations proposed then.
Other proposals are for a HLW repository in opalinus clay, which occurs in a number of places in Germany. In July 2009 new repository criteria came into force, replacing rules dating from 1983. Authorities may now license a high-level waste (HLW) repository only on the basis of scientific demonstration that the waste will be stable in the repository for a million years. In addition, all HLW disposed of in any German repository must be retrievable during the entire period the repository is operated.
Separated high-level wastes from past reprocessing in France and UK are expected to be returned to Germany over 2017 to 2022 and stored. A total of 166 large casks of glass canisters will be involved, and following the last shipment from La Hague in November 2011, 50 of these are already in storage at Gorleben. Each holds 28 tonnes of vitrified HLW. A further 300+ casks with canisters of compacted wastes from reprocessing could immediately go to a final repository, the canisters possibly into boreholes. In June 2015 the environment ministry announced a plan for some of this separated HLW, whereby 26 casks will be held at four interim storage sites. Five will be at Phillipsburg, and 21 at Biblis, Brokdorf and Isar nuclear power plants. These sites were selected as being "best placed from technical, legal and procedural aspects as well as from a political perspective." The German utilities – EnBW, E.ON, RWE and Vattenfall – welcomed the ministry's proposal and said they will now examine it in detail "with location, economic efficiency and inter-site aspects." E.ON said: "The four companies expressly declare their readiness to implement common solutions that can be legally approved, are economical and acceptable under corporate law and are legally secure."
A pilot reprocessing plant known as WAK (Wiederaufarbeitungsanlage Karlsruhe Betriebsgesellschaft) operated at Karlsruhe from 1971 to 1991, processing 206 tonnes of used fuel using the PUREX process. The separated HLW from this was 60 m3 in liquid form, and after a series of political delays it was vitrified in 2009-10. The 122 canisters of vitrified waste are stored at Greifswald while awaiting disposal in a geological repository. The low- and intermediate-level wastes from WAK were disposed of in the salt mine repository at Asse in Lower Saxony, and comprised about half of the wastes emplaced there.
The Asse salt mine repository, licensed by federal and state agencies in the 1960s and 1970s, is now closed. It received wastes from 1967 to 1978, it is in poor condition and is seen to represent a failure of proper licensing process. The BfS decided in 2010 that the wastes should be moved from it, and rejected an alternative of filling it with concrete to provide a stable matrix for the 126,000 drums there. About 200,000 cubic metres of mostly low-level wastes are likely to be moved to Konrad, along with about 100,000 cubic metres of wastes from Urenco’s Gronau enrichment plant.
The Konrad site (a former iron ore mine) has been under development as a repository since 1975, and was licensed in 2002 for intermediate- and low-level waste disposal to 2022, but legal challenges were mounted. These were dismissed in March 2006 and again in April 2007. A construction licence was issued in January 2008. Konrad will initially take some 300,000 cubic metres of wastes - 95% of the country's waste volume, with 1% of the radioactivity. DBE plans for it eventually to accommodate 650,000 cubic metres of wastes from the operation and decommissioning of nuclear power plants as well as from industry, medicine and research. It was expected to be operational by 2014 with storage chambers on six levels from 800 to 1300 metres depth. The August 2015 program did not seek an extension to the Konrad repository licence, as previously proposed, due to local opposition. Hence another repository will need to accommodate all intermediate- and low-level wastes produced by 2022, when Germany's last nuclear power reactor is set to shut under the government's nuclear phase-out policy.
The Ahaus facility is used for storing intermediate-level wastes, including some used HEU fuel from research reactors. In 2010 the BfS approved shipment of 951 used fuel elements from the Rossendorf reactor in 18 sealed containers to Mayak in Russia for reprocessing, on the basis of the Russian Research Reactor Fuel Return Program. Rossendorf, in east Germany, was closed in 1991.
The salt dome repository at Morsleben in east Germany for low and intermediate-level wastes was licensed in 1981, re-licensed post reunification, and was closed in 1998. It is in poor condition and is being stabilised with concrete at a cost reported to be €2.2 billion.
Konrad, Asse and Morsleben are all in central Germany between Hanover and Magdeburg, Gorleben is about 100 km southeast of Hamburg. Ahaus is in western Germany.
Up to 2012, 19 experimental and commercial reactors had been shut down and were being decommissioned. Five of these are VVER-440 units at Greifswald, closed in 1990 following reunification (unit 6 was complete but did not operate), with 235 unused fuel assemblies being sold to Paks in 1996. Unit 5 had a partial core melt in November 1989, due to malfunctioning valves (root cause: shoddy manufacture) and was never restarted.
Five are various BWRs, two are HTRs, one is the large and relatively modern Muelheim-Kaerlich PWR shut down since 1988 due to licensing difficulties, one is Stade PWR closed in November 2003, one is Obrigheim PWR closed in May 2005, one is a prototype GCHWR and one is a prototype VVER. Gundremmingen A BWR was shut down following an accident in 1977. High tension lines from the plant short circuited requiring rapid shutdown of the plant, which resulted in pressure relief valves flooding it with slightly radioactive water. Repairs and modernisation were deemed uneconomic.
Eleven of the 19 involve full demolition and site clearance. These will create about 10,000 cubic metres of decommissioning waste.
Two units of a four-unit VVER-1000/V320 power station were under construction at Stendal, but halted in 1990. Unit 1 was about 85% complete.
In 2012 eight reactors were prematurely shut down by government edict, for political reasons. This meant that the contributions to their respective decommissioning funds were truncated, rather than being allowed to accumulate for a full 40 or more years. The four operators in 2015 had a total of about €38 billion reserves set aside for decommissioning and waste disposal.* However, it is not yet clear if and when these eight units will be decommissioned.
* E.ON €14.6 billion, RWE €10.25 billion, EnBW €7.66 billion, Vattenfall €1.6 billion, Krümmel €1.8 billion, total €36 billion at the end of 2013.
EnBW announced that its two reactors – Neckarwestheim 1 and Phillipsburg 1 – will be directly dismantled without any safestor period, and in May 2013 EnBW submitted applications to decommission and dismantle them. In February 2017 EnBW received a decommissioning and dismantling licence for Neckarwetheim 1; work will begin in 2017 and take 10-15 years.
In late 2012 Vattenfall Europe submitted an application to decommission and dismantle Brunsbüttel, which had been closed since 2007, and in August 2015 it applied similarly for Krümmel, which had not run since 2009. The work would be undertaken over a 15-20 year period.
In January 2017 E.ON’s PreussenElektra received a decommissioning and dismantling licence for Isar 1, the first since 2011. Work will begin in 2017 and is expected to take 15 years at a cost of about €1 billion.
In December 2016 RWE applied for a permit to decommission and dismantle Emsland when it closes in 2022.
Decommissioning of the 17 nuclear units operating to 2011 and six other commercial units (total 23) was expected to cost €48 billion. The federal government ordered a review of the four utilities’ decommissioning provisions, and after it reported in October 2015 the government said that the companies concerned had made sufficient provisions to cover all of the costs and had done so in compliance with the relevant rules. Their combined assets of about €83 billion would cover the costs of decommissioning the power plants and disposing of radioactive waste, and the expert opinion did not point to any need for additional action to be taken beyond these steps. The expert opinion found that the €38.3 billion of provisions made by the companies was based on higher cost estimates than the international average. Nevertheless, in April 2016 the 19-member Commission on the Review of the Financing of the Nuclear Phaseout (KFK) called for utilities to provide an extra €23.3 billion “risk premium” and pay all provisions into a state-run fund
In May 2015 E.On and Vattenfall Europe (VENE) signed an agreement to cooperate on decommissioning "in order to make the decommissioning and dismantling process of their joint venture nuclear power plants as economical as possible." They said that the main objective of the agreement "is to incorporate experience, especially from the largely-completed dismantling of the E.On nuclear power plant in Stade, in the planning and implementation of the decommissioning of the VENE power plants."
Decommissioning the currently operating reactors is expected to produce some 115,000 cubic metres of decommissioning wastes.
Power and experimental reactors shut down to 2006
||Up to 16
|Kalkar KNK 2
||dismantling since 2004
||dismantling since 2013
Energiewerke Nord GmbH (EWN) is wholly-owned by the German government and is responsible for the decommissioning of publicly-owned nuclear facilities and for managing the resulting radioactive wastes. In addition to decommissioning the Greifswald nuclear power plant and the Rheinsberg experimental reactor in eastern Germany following the country's reunification, EWN is also involved in decommissioning the AVR reactor, which is adjacent to the research centre at Jülich.
From 1956 a number of nuclear research centres were set up in West Germany, and most of these as well as university institutes were equipped with research rectors. Most of these reactors are now shut down and the centres have changed their roles. In 2015 the nuclear expertise of Forschungszentrum Jülich (Jülich Research Centre) was merged with the Experimental Reactor Consortium (AVR) under state-owned Energiewerke Nord GmbH (EWN), with the federal ministry of finance as a shareholder. Its focus is on nuclear power and associated activities. The new organization, with some 300 employees, will have the full range of expertise in nuclear decommissioning, dismantling and waste disposal gained at Jülich over the past five decades. Jülich is in North Rhine-Westphalia.
In 1960 a 16 MWe experimental nuclear power plant ordered in 1958 was started up. Then in 1961 the AVR 13 MWe experimental high temperature reactor at Jülich was ordered, with fuel as a pebble bed. It operated for over 750 weeks from 1967 to 1988, most of the time with thorium-based fuel.
The 300 MWe THTR reactor at Uentrop was developed from the AVR and operated 1985-88 also using thorium-based fuel. Fuel fabrication was on an industrial scale. Several design features made the AVR unsuccessful, though the basic pebble bed concept was again proven. It drove a steam turbine.
An 80 MWe HTR-modul was then designed by Siemens and licensed in 1989, but was not constructed.
A fast breeder reactor, the 17 MWe Kompakt KNK 2 was built by Siemens and ran from 1978 to 1991. The much larger SNR-300 was also constructed by Siemens in the 1970s but for political reasons was never commissioned. The 1500 MWe SNR-2 was designed by KWU but not built.
In East Germany a research institute opened in 1956 and its research reactor started operation the following year. The first East German power reactor, the 70 MWe Rheinsberg PWR (VVER 220/V210), was connected to the grid in 1966, operating until it was closed by political decision in 1990.
In 1969 Siemens and AEG merged their nuclear activities to form Kraftwerk Union (KWU). KWU developed a series of PWR units culminating in the standardised 1300 MWe Konvoi design, of which only three were built (though six preceding ones were similar).
Through the 1990s Siemens-KWU with utilities worked with EdF and Framatome to develop the 1600 MWe EPR, marketed by Framatome ANP (formed from Framatome-Siemens nuclear merger), then Areva NP.
At Jülich, Urenco maintains a centrifuge development and manufacturing centre.
The European Commission’s Joint Research Centre focused on nuclear energy is at Karlsruhe, in Baden-Württemberg near the French border. This is being upgraded with a new laboratory to “enable the JRC to continue carrying out state-of-the-art nuclear research... The new laboratory will also be instrumental for maintaining EU expertise and skills in the nuclear field by providing training and open access to students and researchers." It is funded by the Euratom Research and Training Program, with an emphasis on nuclear safety and security.
Regulation and safety
In 1955 the West German government established an Atomic Ministry (BfA) with strong European links. The Atomic Energy Act was promulgated in 1959 and is the core legislation relevant to licensing and safety. The Radiation Protection Ordinance, Nuclear Licensing Procedure Ordinance and six other ordinances support this.
The Federal Ministry of Environment (BMU) is the main national body involved with licensing and supervising nuclear facilities, and is supported by the Federal Office for Radiation Protection – Bundesamt fur Strahlenschutz (BfS). However, licensing of nuclear power plants and other facilities is actually done by the states, which are responsible for implementing federal laws. The BMU supervises this and can issue binding directives.
Under BMU, the Reaktorsicherheitkommission or Reactor Safety Commission (RSK) conducts safety review of nuclear power reactors.
Also under BMU, the Entsorgungskommission (ESK) or Waste Management Commission operates. However, following passage of the new waste repository law in mid-2013, a new independent regulator – the Federal Office for Nuclear Waste Disposal – will be established.
The BfS is responsible for construction and operation of nuclear waste facilities. Individual utilities are responsible for setting aside funds for waste disposal and decommissioning. As of 2003, some EUR 35 billion had been set aside – about 55% of this for wastes and 45% for decommissioning.
The Verband der Grosskessel-Besitzer e V was founded in 1920 as the federation of the owners of large boilers. VGB PowerTech e.V. (VGB) is the European technical association for power and heat generation and works in close co-operation with Eurelectric on the European level and with the corresponding energy and water industries association (BDEW) on the national level. It undertakes research relevant to nuclear plant safety.
Following protests concerning nuclear power plants in the 1970s, notably against construction of a plant at Whyl, by the end of the decade German public opinion was turning against nuclear power and embracing the notion of energy from nature.
The background to this in Germany is the long-standing influence of romanticism with love of forests and religious or mystical regard for nature which carried through into the 20th century as a complex reaction to industrial capitalism. In the 1960s it became coupled with far-left activism which transferred across to the formation of the Greens, the world's first major environmentalist political party. The politics of anti-nuclear protest gained an appeal to middle-class Germans, by conflating anti-NATO missile sentiment from being in the front line of a feared World War III and transferring this to the excellent plants that produced a third of their electricity very cheaply, while promoting idealistic visions of wind and solar potential.
In 1986 the Chernobyl accident caused great concern in Germany and made the negative image worse, thus consolidating opposition to nuclear power. Green politics gained new momentum: 'Red-Green' coalitions of Social Democrats and Greens were formed in the German states and eventually, in 1998, gained representation at federal level. Anti-nuclear activism came to define the heart and soul of the environmental movement, expressing a foundational myth. Climate change then became the headline public issue for Greens, which complicated but did not counter negative perceptions of nuclear power’s clean energy credentials in the public mind.
So for nearly four decades German public sentiment has been split in relation to support of nuclear energy. A poll late in 1997 showed that some 81% of Germans wanted existing nuclear plants to continue operating, the highest level for many years and well up from the 1991 figure of 64%. The vast majority of Germans expected nuclear energy to be widely used in the foreseeable future. The poll also showed a sharp drop in sympathy for militant protests against transport of radioactive waste.
After the crucial October 1998 election a poll confirmed German public support for nuclear energy. Overall 77% supported the continued use of nuclear energy, while only 13% favoured the immediate closure of nuclear power plants.
In November 1998 Germany's electric utilities issued a joint statement pointing out that achievement of greenhouse goals would not be possible without nuclear energy. A few days later the Federation of German Industries declared that the "politically undisturbed operation" of existing nuclear plants was a prerequisite for its cooperation in reaching greenhouse gas emission targets. Nuclear energy then avoided the emission of about 170 million tonnes per year of carbon dioxide, compared with 260 Mt/yr being emitted by other German power plants.
A poll early in 2007 found that 61% of Germans opposed the government's plans to phase out nuclear power by 2020, while 34% favoured a phase out. Another poll in mid 2008 (N=500) showed that 46% of Germans wanted the country to continue using nuclear energy; another 46% said they supported the nuclear phase out policy, and 8% were undecided.
Following the Fukushima accident, in September 2011 a GlobeScan survey showed 52% of Germans thought that nuclear power was dangerous and plants should be closed as soon as possible (compared with 26% in 2005), i.e. they supported the government phase-out policy, 38% supported continuing use of existing plants but no new build (47% in 2005), and 7% supported use with building more (22% in 2005). Hence 90% opposed building new nuclear plants (73% in 2005). In response to the proposition that Germany could almost entirely replace coal and nuclear energy within 20 years by becoming highly energy efficient and depending on power from sun and wind, 62% agreed and 26% disagreed.
In June 2012 a poll by the Institut für Demoskopie Allensbach asked: “Do you think the federal government took the right decision for Germany to phase out nuclear by 2022?” Here 73% agreed that it took the right decision, and 16% answered no.
An opinion poll commissioned by the German Atomic Forum (DAtF) and carried out by Forsa in September 2013 asked whether nuclear power plants should be shut down as planned (or even earlier) “or should the effects on a secure supply of electricity and on costs for consumers and industry be considered prior to future shut downs?” Here 59% opted for a conditional approach and 39% for the unconditional approach. However, this is not considered to represent a change in the underlying antipathy.
An opinion poll commissioned by the DAtF and carried out by Forsa in April 2014 showed that 72% supported a unified European energy policy and 56% opposed Germany reviewing its energy policy goals, i.e. the nuclear phase-out, the limitation of lignite mining and the ban on shale gas extraction in the light of energy security of supply concerns raised by the Ukrainian political crisis.
Germany is a party to the Nuclear Non-Proliferation Treaty (NPT) as a non-nuclear weapons state. Its safeguards agreement under the NPT came into force in 1977 and it is also under the Euratom safeguards arrangement. In 1998 it signed the Additional Protocol in relation to its safeguards agreements with both IAEA and Euratom. It is also a member of the Nuclear Suppliers Group.
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