Nuclear Power in Germany
(Updated August 2014)
- Germany until March 2011 obtained one quarter of its electricity from nuclear energy, using 17 reactors. The figure is now about 18%.
- 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.
- The cost of attempting to replace nuclear power with renewables is estimated by the government to amount to some EUR 1 trillion without any assurance of a reliable outcome, and with increasing reliance on coal.
- Public opinion in Germany remains ambivalent and at present does not support building new nuclear plants.
- More than half of Germany’s electricity was generated from coal in the first half of 2013, compared with 43% in 2010.
- Germany has some of the lowest wholesale electricity prices in Europe and some of the highest retail prices, due to its energy policies.
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)
IEA figures give Germany's electricity production in 2012 as 618 billion kWh (TWh) gross, down from 629 TWh in 2010. In 2012 coal provided 286 TWh (46%, more than half being lignite), nuclear 100 TWh (16%), gas 70 TWh, biofuels & waste 48 TWh (7.77%), wind 46 TWh (7.44%), hydro 28 TWh (4.5%), solar 28 TWh (4.5%). Electricity exports exceeded imports by about 20 TWh, compared with 4 TWh in 2011, 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 6400 kWh per capita.
Generating capacity in April 2014 was 169.6 GWe comprising 12.1 GWe nuclear, 5.6 GWe hydro, 33.7 GWe wind (0.6 offshore), 36.9 GWe solar, 28.2 GWe gas, 21.2 GWe lignite, 26.3 GWe hard coal and 5.6 GWe biomass, according to Fraunhofer Inst. In the first half of 2014 wind and solar PV had capacity factors of 18% and 11% respectively, compared with 85% for nuclear. In 2011 Russia provided almost 40% of the gas, followed by Norway, Netherlands and UK, while 14% was produced domestically.
The country's 17 nuclear power reactors, comprising 15% of installed capacity, formerly supplied more than one quarter of the electricity (133 billion kWh net in 2010). Many of the units are large (they total 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. (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.
German nuclear power units
|2010 agreed shut-down
||March 2011 shutdown
& May 2011 closure plan
|Total shut down (8)
|Total operating (9)
NB. The eight shut-down reactors are not yet defueled, nor decommissioned and written off by their owners.
E.ON has equity in the following nuclear plants:
Grafenrheinfeld 100%, Isar 1 100%, Isar 2 75%, Unterweser 100%, Grohnde 83.3%, Brokdorf 80%, Kruemmel 50%, Brunsbuettel 33.3%, Gundremmingen 25%, Emsland 12.5%.
RWE has equity in the following nuclear plants:
Gundremmingen 75%, Biblis 100%, Emsland 87.5%.
Vattenfall has equity in the following German nuclear plants:
Brunsbuettel 66.7%, Kruemmel 50%, Brokdorf 20%. It has written off SEK 10.2 billion (EUR 1.2 billion) on Brunsbuettel and Kruemmel.
Also in Sweden: Ringhals 70%, Forsmark 66%.
EnBW has equity in the following nuclear plants:
Neckarwestheim 100%, Phillipsburg 100%.
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 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 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 (Muelheim-Kaerlich, 1219 MWe) commenced decommissioning in 2003. It also prohibited the construction of new nuclear power plants for the time being and introduced the principle of on-site storage for spent 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 EUR 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 8-year licence extensions (from 2001-agreed dates) for reactors built before 1980, and 14-year extensions for later ones. The price exacted for this was several new measures: a tax of EUR 145 per gram of fissile uranium or plutonium fuel for six years, yielding EUR 2.3 billion per year (about 1.6 c/kWh), payment of EUR 300 million per year in 2011 and 2012, and EUR 200 million 2013-16, to subsidise renewables, and a tax of 0.9 c/kWh for the same purpose after 2016. However, utilities could reduce their contribution to renewables if safety upgrades to particular individual nuclear plants cost more than EUR 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.
The reactors affected are 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 Reaktorsicherheitkommission or Reactor Safety Commission (RSK) 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 leaves the eight oldest reactors closed, and promises to result in the remaining nine closing by the end of 2022. France, Poland and Russia (Kaliningrad) are expecting to increase electricity exports to Germany, mostly from nuclear sources, and Russia is expected to export significantly more gas.
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, currently 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 European Court of Justice, but a ruling is not expected until 2016. Since January 2011 nuclear power plants had paid around €1.5 billion through the tax over two years 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 EUR 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 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 May 2015 it will have operated almost 33 years. However if BNetzA rules that the plant is needed, E.On may be ordered to keep it in operation to the end of December 2015 as planned, with the costs passed on to consumers.
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 Fukushima in March 2011, despite safety assurances from the regulator.
RWE filed a lawsuit against the government regarding closure of its Biblis-B and said that the phase-out cost the company over EUR 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.
E.On is also seeking EUR 8 billion in compensation. Vattenfall in June 2012 contested the confiscation of generation rights for the Brunsbuttel and Krummel nuclear power plants, and filed the case with the autonomous International Centre for Settlement of Investment Disputes (ICSID), 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 (EUR 1.2 billion) write-off on those two plants. EnBW supports the legal actions brought by the other utilities, saying that the government’s actions infringe its property rights, but being almost completely publicly-owned it is unable to file a legal complaint. However, by May 2014 it had paid €790 million in the tax, so would welcome a refund. The four utilities have made provisions of over EUR 30 billion on account of the government decisions, and the German government appears to be facing claims of this magnitude.
In May 2013 EnBW submitted applications to finally decommission and demolish sections of its Neckarwestheim 1 and Phillipsburg 1 plants.
Bundesnetzgentur grid 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. "The historically singular simultaneous shutdown of power plants amounting to 5,000 MW capacity and the long-term lack of some 8,500 MW capacity bring the transmission grids to the edge of their resilience." Consequently there are many hours in which secure network operation is impossible, meaning that it is vulnerable to a single failure. "As a consequence, the original objective of competition-driven market results is replaced by a more or less centrally controlled planning approach. This is dubious in terms of energy economics, economically inefficient and ecologically harmful, but must be accepted for a transitional period and is unavoidable at the moment." Reserve capacity is fully utilised, no buffer is left, and "For this reason the risk of non-controllable network disturbances is increasing distinctly." The summer "risk will increase markedly during the winter semester due to higher load on the network linked to higher domestic and foreign power demand and significantly lower PV generation."
While PV and wind together sometimes contribute up to 28 GW, "leading to a manageable network situation" during favourable spring weather conditions, it is evident "that this capacity is not available in a reliable manner, but regularly disappears completely." Also, "The changed network load pattern due to the shutdown of the 7+1 nuclear power plants has already led to postponements of scheduled service and maintenance works in the transmission grid, because many such works can only be undertaken when there is little or no load." This has obvious implications for reliability. "Maintenance work at transformer station Großkrotzenburg, a major north-south network node close to Frankfurt, for instance, had to be postponed because the relevant circuits are indispensable." Bundesnetzagentur warned of very uncertain supply situations likely over winter, especially in southern Germany, along with increased costs. In case of a permanent shutdown of the eight nuclear reactors affected by the moratorium, Germany could no longer support security of supply in the European interconnected grid to the extent it had done so far. Grid stability is the major concern, along with generation and transmission capacity.
In May 2012 Germany announced plans to upgrade and expand its electricity grid over the next decade in order to help renewable energy sources fill the gap left by its phase-out of nuclear power. At the request of the government, the country's four grid operators (TSOs) – 50Hertz, Amprion, TenneT TSO and TransnetBW – drew up a joint network development plan which identifies the necessary grid expansions. The plan – co-ordinated by the federal network agency (Bundesnetzagentur) – would provide a basis for delivering the country's energy transition. In December 2012 cabinet agreed to accelerate this program for building 2800 km of new high-voltage transmission and achieve it in four years rather than ten. In addition, about 1500 km of the present grid would be upgraded. It was expected to cost about EUR 10 billion. The planned law aimed to speed up the grid construction by placing limits on what legal options opponents could take. State governments agreed to let the Bundesnetzagentur (BNetzA) coordinate plans, rather than asserting regional interests (though Bavaria later reneged on this).
More broadly, on-shore 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. In addition to the upgrading of 4400 km of existing transmission lines, some 3800 km of new high-voltage lines will be needed over the next ten years. These 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, and one 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. For example, it could lead to regional shutdowns of renewable energy producers and power consumers, as well as costly interventions on the production side to reinforce the network. After public consultation a revised draft of the plan was to be submitted to Bundesnetzagentur in August 2013.
A bill introduced to the Bundestag in March 2013 identified 36 transmission projects costing some EUR 10 billion as high priorities. The government wanted to reduce the time frame 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 is set for closure in 2015. This is near Schweinfurt in northern Bavaria.
In November 2013 the TSOs estimated that peak load for 2014 would be 81.8 GWe, with capacity margin 9.4 GWe above this, and rising to 2016. The margin figures assumed that 99% of wind and solar capacity would be unavailable.
Replacing and closing down generating capacity
BNetzA reported that 10.35 GWe of conventional power plant capacity is to be commissioned by 2015, but only 2 GWe of this is in southern Germany. Utilities plan to close 4.9 GWe by 2015, of which 3.7 GWe is in the south, including E.ON’s 1275 MWe Grafenrheinfeld nuclear reactor. This will give 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 August 2013 RWE reported that 3.1 GWe of its own fossil fuel capacity had been closed down in Germany (most) and Netherlands and in March 2014 as it announced a EUR 2.76 billion loss, it said it planned to close or mothball another 6.6 GWe, out of 52 GWe across Europe. E.ON had shut down 6.5 GWe and had a further 4.5 GWe under review. Statkraft decided to close two 6-year old gas-fired plants totalling 1.2 GWe due to their being no longer profitable. These closures are attributed to high prices of gas, reduced wholesale prices due to Europe's economic slowdown (20% drop in first half of 2013), and policies supporting the expansion of renewable power, which erode the viability of conventional generation. In February 2014 Statkraft said its three German gas-fired units (1.4 GWe) were losing EUR 20 million per year, as production halved to 1 TWh in 2013. It called for capacity payments if the units were to avoid shutdown. Also RWE announced it was closing its 1.3 GWe Dutch Claus C CCGT plant in July, less than two years after its commissioning, due to subsidised renewable supply across the border from Germany. In August 2014 RWE said it was shutting down a further 1000 MWe of coal and lignite capacity on top of the 12.6 GWe already closed down or discontinued since January 2013. Vattenfall has 860 MWe of its new Magnum CCGT plant in Netherlands shut down.
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 at 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.
Economic and CO2 implications of nuclear policy changes 2010-11
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.
Meanwhile Germany spends some EUR 2.5 billion per year subsidising its coal mines to produce about 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 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 were to continue with its nuclear phase-out policy and maintain 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 being built, 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.
Meanwhile, in September 2010 then March and May 2011 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.
In February 2013 the Energy & Environment minister said that the costs of Energiewende – reforming and restructuring Germany's energy sector by the end of the 2030s – could reach EUR 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. Hence the government proposes to reduce feed-in-tariffs for new projects, saving up to EUR 200 billion over the next 20 years. Also, in response to the four major German utilities and the Federal Network Agency and Grid Authority (BNetzA) raising the EEG surcharge or Umlage charged to customers by utilities by 47% in 2013, the government threatened to put a cap on the surcharge until the end of 2014 and then allow only 2.5% pa increases. However, in October 2013 the utilities and BNetzA announced a further 18% rise to 6.24 c/kWh in 2014, taking the annual surcharge on consumers to about EUR 23.6 billion. It also plans to tighten industry exemptions. In 2012 renewable power producers collected some EUR 20 billion for electricity having a wholesale market value of EUR 3 billion. The difference between projected feed-in tariffs and market revenues forms the essential part of the EEG surcharge applied to most consumers.
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.
The Bundesnetzagentur in September 2012 said that 25 new power plants with total 12 GWe were under construction, 67% powered by black coal and 17% by brown coal – 10.1 GWe coal – adding to 55 GWe already operating and most of it 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.
Germany's CO2 emissions from industry and power stations in 2012 were 450 million tonnes, the same as 2011, according to the Federal Environment Agency (UBA). A higher rate of coal-fired power generation was offset by lower industrial CO2 emissions due to an economic slowdown in the euro zone.
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 2012, 31,308 MWe of wind capacity was installed, 29.5% of EU total according to the Global Wind Energy Council. Renewable electricity fed into the grid is paid for by the network operators at fixed feed-in tariffs (FITs). The costs are passed on to 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.
In April 2014 installed wind capacity was 33.7 GWe, of which 616 MWe was offshore. Solar capacity was 36.9 GWe. Capacity factors for wind and solar PV were 17% and 11% respectively in 2012. 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.
Over Christmas 2013 Germany had negative spot power prices due to reduced demand and windy weather. Month-ahead base-load prices were over EUR 40/MWh. To mid-2014 there have been ten periods with negative prices for six hours or more.
Revised renewable energy sources act 2014
Following the September 2013 elections, the CDU-led government pledged to reform the 2000 Renewable Energy Sources Act (EEG – Erneuerbare Energien Gesetz), possibly diminishing feed-in tariffs for solar and wind power and favouring dispatchable generation which can respond to demand. The BDI industry federation and other industry groups had been lobbying for a curb on feed-in tariffs, and household consumers were being hurt by high prices. This 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 will hold the EEG surcharge at 6.24 c/kWh through to 2017, the renewable energy caps announced earlier are 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. In 2103 payments for established renewables averaged 17 cents/kWh, and for new plants 14.6 c/kWh. The latter is expected to reduce to 12 cents in 2015 with new support rates: 19.4 c/kWh for offshore wind, 8.9 c/kWh for onshore wind and 9.23 c/kWh for solar PV (less for large installations). 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’, with payment supplemented by premiums similar to the support rates. This is in place of feed-in tariffs, which the EC has ordered to be phased out over 2016-20. Following consideration by parliament the new law is expected to take effect in August 2014.
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 new 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.
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. Germany's lignite capacity is some 20 GWe, with about 3 GWe of more efficient plants added since 2011. German power producers envisaged adding 5.3 GWe of new-build coal capacity by the end of 2013, according to statistics from the federal grid agency (BNetzA).
In mid-2013: Three old power generating blocks at Datteln were given an operating extension for 2013 by the state after utility E.ON and Deutsche Bahn said delays to E.ON's new 1050 MWe Datteln 4 block – held up by legal wrangling – threatened power supply to the railway operator. E.ON’s plant at Staudinger is now reduced to the relatively modern 510 MWe block 5. Unit 1, a block built in 1965, closed at the end of April, but the regulator now wants this in reserve. Plans for a modern 1100 MWe plant have been dropped. At Kiel, plans to replace a 40-year old 354 MWe coal-fired plant were shelved by Kiel city and partner E.ON, and this plant will close by 2015. (Also E.ON is to mothball its new 430 MWe Malzenice combined cycle gas plant in western Slovakia because it is no longer economic.)
Vattenfall Europe in December 2010 secured approval for a 1,600 MWe coal-fired plant at Moorburg after two years of opposition by agreeing to environmental measures which will curb profitability. Initial supply to the grid was to be in 2013 and full commercial production in 2014. Utility network Trianel says its 750 MWe, EUR 1.4 billion coal-fired plant at Luenen will start up in the third quarter of 2013 but is expected to make losses due to market conditions. At Krefeld, it dropped plans for coal in favour of gas for a 1,200 MWe plant. Mannheim Utility MVV and its power plant unit GKM are building an EUR 1.2 billion coal-fired unit for 2015.
RWE in 2011 applied to replace four old brown coal-fired Niederaussem blocks with new coal-fired units worth EUR 1.5 billion in a process that may take seven years altogether. In mid-2013 Steag started taking online a new 725 MWe block, Duisburg Walsum 10, and EnBW started commissioning its 912 MWe RDK8 plant. At Wilhelmshaven GDF Suez is building an 800 MWe plant with BKW to come on stream later in 2013. (Source: EMP Weekly Market Review)
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 finish 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).
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 was amended to make such disposal a responsibility of the federal government.
The utilities are responsible for interim storage of spent fuel, and have formed joint companies to build and operate off-site 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 Brunsbuettel was revoked, having been granted for 40 years in 2003. The facility was commissioned in 2006.
The federal government through the Federal Office for Radiation Protection (BfS) is responsible for building and operating final repositories for high-level waste, but progress in this has been hindered by opposition from Länder governments. Gesellschaft für Nuklear-Service (GNS) 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. Its 75%-owned subsidiary Deutsche Gesellschaft zum Bau und Betrieb von Endlagern für Abfallstoffe mbH (DBE) constructs and operates repositories, notably Konrad and Gorleben, while decommissioning Morsleben. GNS developed the various types of CASTOR 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 EUR 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 EUR 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.
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, and that the power utilities should spend another EUR 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 law was passed in July and creates a 33-member commission to develop ‘basic principles’ for site selection, including safety and economic requirements, and selection criteria for rock formations. The commission includes representatives from the parliament, academia, civil society organizations, industry, the environment and trade unions and will forward its repository site criteria for parliament to endorse. Its recommendations will also go to parliament.
Separated high-level wastes from past reprocessing in France and UK are expected to be returned to Germany by 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 in to boreholes.
A pilot reprocessing plant known as WAK (Wiederaufarbeitungsanlage Karlsruhe Betriebsgesellschaft) operated at Karlsruhe from 1971 to 1991, processing 206 tonnes of used fuel. The separated HLW from this is stored there in liquid form, and after a series of political delays was to be vitrified in 2009-12. The vitrified waste is to be 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. The wastes are likely to be moved to Konrad.
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, 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. It is expected to be operational about 2014.
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 EUR 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 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 4-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 shut down by government edict, for political reasons. The four operators at the end of 2013 had a total of about €36 billion reserves set aside for decommissioning and waste disposal.* However, it is not yet clear if and when most of these will be decommissioned, though EnBW has announced that its two reactors – Neckarwestheim-1 and Phillipsburg-1 – will be directly dismantled without any safestor period.
* E.ON €14.6 billion, RWE €10.25, EnBW €7.66 billion, Kruemmel €1.8 billion.
Decommissioning the currently operating reactors is expected to produce some 115,000 cubic metres of decommissioning wastes.
Decommissioned power and experimental reactors
||MWe net each
||Years operating each
||Up to 16
|Kalkar KNK 2
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 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 Juelich 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, now marketed by Framatome ANP (formed from Framatome-Siemens nuclear merger).
At Juelich, Urenco maintains a centrifuge development and manufacturing centre.
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 European level and with the corresponding water association (BDEW) on the national level. It undertakes research relevant to nuclear plant safety.
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 want the country to continue using nuclear energy; another 46% said they support the nuclear phase out policy, and 8% were undecided.
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.
Nuclear Engineering International, Feb 1996; July 2004;
NEI World Nuclear Industry Handbook 2004;
IAEA 2003, Country Nuclear Power Profiles.
Bundesnetzagentur, May 2011, Update of report on the impact of nuclear power moratorium on the transmission networks and security of supply.
Konrad Mazur, 5/10/11, Coal and gas power plants to replace part of nuclear power plants in Germany by 2014. OSW Centre for Eastern Studies.
BDEW, Jan 2013, Developments in the German electricity and gas sector in 2012.