Germany's Energiewende

(Updated July 2020)

• Energiewende (energy transition) refers to Germany’s policy of increasing the share of renewables and phasing out nuclear power.
• Despite the very high cost acknowledged by the government, it represents a shared vision and enjoys public popularity.
• Germany has some of the lowest wholesale electricity prices in Europe and some of the highest retail prices, due to its Energiewende policies. Taxes and surcharges account for more than half the domestic electricity price.
• Germany until March 2011 obtained one-quarter of its electricity from nuclear energy, using 17 reactors. This provision has now halved and is due to be phased out in 2022.
• Coal-fired power generation, now meeting almost half of the load with substantial carbon dioxide output, is allowed to continue but is expected to diminish significantly by 2030.
• For practical purposes, from 2017 the government is restricting the addition of renewables capacity, in quantity and location.
• Introduction of wind and solar capacity was initially supported by feed-in tariffs, but this has largely given way to auctions.

The German policy of vastly increasing its dependence on highly-subsidised renewables is known as the Energiewende (energy transition) and is based on the Energiekonzept (energy concept) policy published late in 2010, as well as the Renewable Energy Sources Act (Erneuerbare Energien Gesetz, EEG) passed in 2000. The policy takes in all energy, but the focus in this paper is on electricity.

The Energiewende policy includes: greenhouse gas reductions of 40% by 2020 and 80-95% by 2050 relative to 1990; a fall in primary energy consumption by 20% to 2020 and 50% to 2050; a renewable energy target (including biomass) of 60% by 2050; and the shutdown of the country's nuclear reactors, even though they are the main source of carbon-free electricity. Electricity is to be 40-45% renewables by 2025, 55-60% by 2035, and at least 80% from renewables by 2050, “which requires new solutions to provide ancillary services,” according to the German Energy Agency (Deutsche Energie-Agentur, DENA). It also requires a major increase in energy efficiency: compared with 2008, electricity consumption is intended to be 10% lower by 2020 and 25% lower by 2050. However by 2015 it was only 3% lower.

Despite the operation of thermal power plants being increasingly uneconomic, and many closing, this capacity is still needed. The Uniper CEO said in March 2017: “This winter has proved that supply from wind and solar alone does not work. In peak hours on January 24 renewable energy delivered just 1% of overall German demand. Conventional plants carried almost the entire load.” Furthermore, “political framework conditions continue to prevent the cost-effective operation of ultra-efficient gas-fired power stations.” Such Uniper units, commissioned in 2010-11, were “particularly well suited” to balancing intermittency in the short-term, yet this optionality “is not given appropriate remuneration. In fact, statutory requirements force owners to provide these services at prices below cost – a situation that owners find untenable.”

Increasingly faced with having to prioritise nuclear phase-out or reduction of CO₂ emissions, the government has chosen the former, despite some internal dissent. It has encouraged Vattenfall, RWE and other coal producers to keep their mines open, as considerable new coal-fired generation capacity is built to replace nuclear capacity due to be retired by 2022. In August 2016 black coal and lignite power plants provided 42% of the country’s electricity, having taken over the main base-load role from nuclear. The DENA scenario for 2033 has 12 GWe of lignite and 20 GWe black coal capacity out of 259 GWe total – 12% of capacity, plus 41 GWe fuelled by natural gas, making 28% of capacity compared with 44.6% in 2014. This 28% of system capacity as synchronous, dispatchable capacity as well as interconnection with neighbouring countries will be needed to maintain stability. (DENA is 50%-owned by federal government ministries and 50% by German financial institutions.) By 2014 Germany had achieved a 27.7% reduction on 1990 CO₂ emission levels, but since then emissions have increased and the 2020 target of 40% emissions reduction is not achievable if reliable generating capacity is to be maintained. Early in 2017 the government was backing off its extravagant CO₂ emissions reduction targets and talking up consistency with the rest of Europe, hence 20% by 2020. In June 2018, the government projected that it was on track to achieve a total CO₂ emissions reduction of 32%, some 100 million tonnes short of its target.

An October 2016 report commissioned by the Düsseldorf Institute for Competition Economics (DICE) on behalf of the Initiative New Social Market Economy (Initiative Neue Soziale Marktwirtschaft, INSM) provided the first full-cost estimate of Energiewende to 2025. This amounted to over €520 billion in the electricity sector alone. The main component was €408 billion for the EEG levy, while the expansion of transmission and distribution networks totaled €55.3 billion. At the end of 2015, €150 billion had already been spent on Energiewende, excluding network expansion costs.

The government has set up five model regions to address the challenges of Energiewende and test smart grid technology. A leading one is Enera in the northwest, with high wind potential and relatively low population.

Background to the nuclear phase-out

German government 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, a major protest against construction of a reactor at Wyhl in 1975 started to focus opposition. The national policy involving substantial reliance on nuclear power backed by Germany’s world-class engineering faltered after the Chernobyl accident in 1986, and the last new nuclear power plant was commissioned in 1989. 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. These two parties agreed to change the law in order to phase out nuclear power.

After intense discussion with utilities, 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 operational lifetimes to around 32 years, averted the risk of any federally-enforced plant closures during the term of that government. 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 Act on the Structured Phase-out of Nuclear Power for the Commercial Production of Electricity entered into force on 27 April 2002.

The 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. 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 including a fuel tax designed to take one-half of operational profit. In October these measures were accepted 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 overturned after the Fukushima accident when in March 2011 the government ordered the shutdown of the country's nuclear power reactors which began operation in 1980 or earlier. Those seven 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 was not compensated by removal of the nuclear fuel tax.

In 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 still without abolishing the fuel tax. The Bundestag passed the measures by 513 to 79 votes at the end of June, and the Bundesrat vote in July confirmed this. Both houses of parliament approved construction of new coal and gas-fired plants despite claiming to retain CO₂ emission reduction targets, as well as expanding wind energy. The nuclear phase-out then became part of the push to increase the share of renewable energy generation through subsidies.

Renewables priority and subsidies

The Renewable Energy Sources Act (EEG) of 2000 launched a major promotion of renewable energy, notably solar and wind, though Germany is not well placed geographically in relation to either. For electricity it meant that any source of solar power or wind energy could sell power to the grid (with priority access over conventional power), receiving a generous 'feed-in tariff' (FIT) guaranteed over 20 years. The costs were passed onto electricity consumers, so that there are no subsidies by the government itself.* The tariffs were different for specific technologies and subject to a reduction of about 5% each year as an incentive for price reductions in new plant. Renewables capacity grew ten times faster than the OECD average from 1990 to 2010 and by 2015 renewables (including hydro – 4%) accounted for 32% of the country's electricity production.

* The FIT payments were made by the four transmission system operators (TSOs) for the renewable generation they received The TSOs then sell the renewable energy on the wholesale market. In addition to wholesale revenues, they collect a renewables levy or EEG surcharge (Umlage) from their customers except some large consumers. They set this levy amount from year to year. Renewables are now sold into wholesale markets directly and the generators receive a premium over market prices, still funded as before. From 2017 an auction system will set prices from renewable sources above 750 kW, with FITs continuing for small plants.

This incentive was boosted by the 2010 Energy Concept policy which took the form of Energiewende. Germany gets more electricity from wind and solar renewable sources than any other major country. This has resulted in a dispersal of electricity supply, from four major companies to a multitude of sources, and a dramatic erosion of profitability for the former major suppliers. Intermittent wind and solar power creates a need for backup generators, but the business models that justified investing in them have been overturned. Occasional high renewables supply (accepted preferentially) means that flexible gas-fired generation is cut back to subeconomic levels, and wholesale power prices have diminished (this effect from German renewables not being confined to Germany). Energiewende aims to make base-load generation, the provision of continuous, reliable supply on a large scale, obsolete. Energy consumption increasingly needs to match availability, and there is supposed to be a focus on “flexible dispatchable supply” though this is not in evidence yet.

Wind power has become the most important renewable source of electricity production in Germany. From 12 GWe in 2002, at the end of 2015 almost 45 GWe of wind capacity was installed, 31.7% of the European Union (EU) total and 10.4% of the world total, according to the Global Wind Energy Council. Solar PV capacity was about 40 GWe in 2015. Of the total 648 TWh gross generation in 2016, wind provided 77 TWh (12% of the total) and solar 38 TWh (6%) – IEA figures. In 2015 capacity factors were at 21.8% and 11.3%, respectively. Hydro produced 21 TWh in 2016, and biofuels & waste 52 TWh, both of these being dispatchable sources which thus comprise almost 40% of total renewables supply. There is little potential for expanding hydro-electric production.

Given that wind and solar input to the grid is taken when available, the focus is now on net demand, which is more variable and less predictable than total demand from consumers, but must be met from dispatchable sources with greater flexibility than when simply meeting traditional base-load demand. This has cost implications.

Apart from the direct costs of power supplied to the grid, the increased proportion of that power from variable renewable sources gives rise to significant integration costs, notably ancillary services required to maintain voltage and frequency. Wind and solar integration costs become high as their proportion of supply increases, mostly due to the effect on utilisation of thermal plant, as noted above, while the balancing costs are small (less than €3/MWh in Germany to 2015). Ancillary services controlling voltage and frequency coupled with rapid ramp up and down are the main challenges arising from the increasing share of variable renewables, and sufficient dispatchable synchronous generation capacity is required in order to maintain frequency.

The cost of subsidies and other support for Energiewende is mostly paid by small and medium-size consumers, households and small business, with major industries to a large extent exempt so as to minimise the effect on the ecomomy and the incentive for them to move abroad. In fact many have done so, as retail power costs rose significantly anyway. Energy poverty is a major problem. In 2014, German electricity suppliers sent 6.3 million letters regarding delayed payments, and disconnected 351,802 households from the electricity grid for not being able to pay their electricity bills, according to the federal network agency and grid authority Bundesnetzagentur (BNetzA).

In July 2012 The Economist opined: “It is hard to think of a messier and more wasteful way of shifting from fossil and nuclear fuel to renewable energy than the one Germany has blundered into. The price will be high, the risks are large and some effects will be the opposite of what was intended.”

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), switching the incentive from feed-in tariffs for new solar and wind power capacity and favouring dispatchable generation which can respond to demand. The Federation of German Industries (Bundesverband der Deutschen Industrie, BDI) and other industry groups had been lobbying for a curb on feed-in tariffs, and househ old 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 (Umlage) and were effectively cross-subsidised by residential customers.

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 (Umlage) at 6.24 c/kWh through to 2017, and 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; and solar PV also 2.5 GWe per year added. The caps are designed to allow about 11 TWh renewables growth each year. In 2013 payments for established renewables averaged 17 c/kWh, and for new plants 14.6 c/kWh. The latter was 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 (lower 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 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 European Commission (EC) had ordered to be phased out over 2016-20. The new law took effect in August 2014. In October 2014 the transmission system operators (TSOs) reduced the EEG surcharge slightly to 6.17 c/kWh for 2015, but for 2016 it was set at 6.35 c/kWh, accounting for about 22% of customers’ bills. For 2017 the EEG rose to 6.88 c/kWh, and will drop slightly to 6.79 c/kWh in 2018.

One major issue is whether industry onsite 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 were to 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.

2017 Renewable Energy Sources Act, Electricity Market 2.0

While the EC cleared EEG 2014 under state aid law, several conditions were attached, including that a new law concerning financial support for renewables would be required after 2016. The process of further 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'. The consultation 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.

The consultation process led to the adoption in July 2016 of the 2017 Renewable Energy Sources Act (EEG 2017), the Act on the Further Development of the Electricity Market (also referred to as the Electricity Market Act), and the Act on the Digitisation of the Energy Transition. The legislation replaces politically-set feed-in tariff support with competitive auctions from 2017 to determine funding rates for onshore wind, offshore wind, PV plants over 750 kWe, and biomass over 150 kWe, covering 80% of renewables generation from new plants each year. It excludes hydro and geothermal power, which continue to have FITs. It was heralded by the energy minister as “the biggest reform of the power market since the liberalization in the 1990s” and was approved by the EC in December 2016.

The new rules establish a “deployment corridor” for new capacity. This limits new onshore wind capacity to 2800 MWe/yr rising to 2900 MWe/yr from 2020. Offshore wind beyond the 6500 MWe target for 2020 is limited to 500 MWe addition per year in 2021 and 2022 in the Baltic Sea, rising through 700 MWe to 840 MWe from 2026 to reach a 15,000 MWe target set for 2030. Solar is limited to 600 MWe/yr for projects over 750 kW. For other plants, there is no change from EEG 2014, and small-scale solar PV is unrestricted until a total solar capacity of 52 GWe is reached. The rules are aimed at limiting the share of electricity coming from renewables in 2025 to 45% and 60% in 2035 in order to synchronize with network expansion, to secure planning and development of the conventional power station fleet, and so that Germany’s neighbours can adapt their own electricity systems to predictable renewable energy additions.

The new legislation also includes provisions of the June 2013 regulation on reserve power plants (ResKV), to counter the transmission restriction from north to south, and new capacity and security (lignite) reserves. Reserve capacity consists of power plants where owners have applied to close them but been denied this by TSOs because they are system-relevant and they therefore need to be kept operational though run at a loss. The plants, including some fairly new but now uneconomic gas-fired capacity, are activated compulsorily if needed. The capacity and security reserves are related to removing old lignite capacity from the system (see later section on The continuing role of coal). From 2019-20 the reserve must grow to about 4.4 GWe with capacity selected by auction and costing €100 to €220 million per year.

Auctions have been successful in driving down costs, and tenders have been oversubscribed. Government policy determines the capacity to be auctioned each year. The June 2017 solar PV auction cleared at €56.60/MWh for 201 MWe, 14% down from the previous round in February and 38% down from April 2015. Successful bidders have up to two years to bring their project into operation and so far have done so – i.e. 100% realisation rate, due to bonds and pre-qualification of bidders. The June 2017 price would indicate a direct subsidy of around €26/MWh assuming an average German day-ahead price of €30/MWh.

The first offshore wind auction in 2017 delivered prices well below expectations – average €4.4/MWh (as premium on the wholesale price) for 1490 MWe. The capacity needs be online in seven years. The low bids, involving virtually no subsidy, reflect assumptions that wholesale prices by the mid-2020s will have have responded to widespread plant closures, reducing overcapacity of conventional plant.

Transmission and supply

Germany has a major need for increased transmission capacity, due to its traditional fossil fuel and nuclear power generation plants – with much of the industrial load – being in the south, with lines spreading from there to the rest of the country, while the main wind power sources are along its northern Baltic coast. Hence its existing north-to-south lines have become bottlenecks, incapable of transmitting sufficient wind-generated power from the north to replace closed capacity in the south. In addition, the German grid must allow for increasing international transit as part of European electricity trading.

While the main challenge in grid function is in transmission capacity, most solar PV systems are connected to the distribution grid, providing a distinct set of challenges for reliability at that level of distributed generation. Also, when in 2005 domestic sources were encouraged to feed surplus into the distribution grids it was assumed that this would be consumed locally, thus reducing the need for transregional transmission. However, it turned out “that volatile renewables such as solar and wind power do not help eliminate the need for grid expansion; on the contrary, they create the need for it,” according to the Federal Ministry for Economic Affairs and Energy (BMWi).

Maintaining grid stability in 2018 cost more than €1.4 billion, due to redispatch* where prioritised renewable power causes transmission congestion and conventional power stations are paid to reduce output. The redispatch costs have risen since 2015 despite a new east-south grid link. The country's four transmission system operators (TSOs**) said that redispatch costs could rise to €4 billion per year by 2020, and the German federal network agency and grid authority Bundesnetzagentur (BNetzA) agreed that this was not unrealistic, given the slow progress with transmission expansion. The Association of German Chambers of Industry and Commerce (Deutscher Industrie- und Handelskammertag, 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.

** TSOs are responsible for ensuring adequate supply to meet demand regardless of weather conditions, for system stability, and for coordination with other TSOs in the European integrated grid.

As well as redispatch the grid operator can decide to curtail excessive renewable power from individual installations, in which case the producer is compensated with 95% of its lost FIT revenues. The number of such curtailments on the grid has increased significantly in recent years, so that balancing payments of €485 million were made by grid operators to renewable energy (mostly wind) producers between 2009 and the end of September 2015, with rising amounts anticipated for the future. The incurred costs are passed onto ratepayers. Curtailment of wind and solar energy in 2018 due to grid congestion amounted to 5.4 TWh, with compensation payments of €635 million. The figure had risen by around 50% in 2017 (5.5 TWh curtailments, with €610 million compensation payments).

BNetzA reported at the end of May 2011 on the implications of plans to close down nuclear generation and greatly ramp up the contribution of wind and solar sources. 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. Increased capacity from the north is essential to cope with occasional high input from wind and solar, and this will be very expensive (see below), but the average utilisation will be low.

Ancillary services: voltage and frequency control

Some definitions of ancillary services include redispatch and curtailment, along with load-following, among other services to achieve reliable operation of the grid. They are a new phenomenon arising from excessive solar and wind capacity which normally has priority. (Hydro as a renewable source can be turned off without loss of the potential energy, which remains available on demand as a dispatchable source.)

Grid management needs to achieve frequency and voltage control, in the course of supplying demand which is constantly varying. Hence there must be dispatchable synchronous generation capacity available for TSOs to call upon. Traditionally this is dispatched in merit order, i.e. according to lowest marginal cost. However, with the establishment of preferential access for intermittent renewables, this is increasingly compromised. Where there is large intermittent renewable capacity connected to the grid, supply from it may meet much of the demand and even exceed it at times, which means that reliable, low-marginal cost capacity providing ancillary services is then shut down. DENA points out that such plants “will have far shorter operating hours in future.” Since that kind of plant is often high-capital, low-running cost equipment, its economic viability is subverted.

In 2014 DENA reported on its Ancillary Services Study 2030 “to identify the need for action to guarantee secure and reliable grid operation between now and 2030 in a power supply system with a high percentage of electricity generation from fluctuating renewable energy sources.” The study assumed 66.3 GWe of onshore wind capacity, 25.3 GWe offshore, and 65.3 GWe solar PV in 2033, as well as about 73 GWe of coal and gas-fired capacity. Penetration of renewables in neighbouring countries was assumed to be less than Germany.

The DENA study showed how the 80% renewables by 2050 target “significantly changes the requirements and the technical and economic options available to provide ancillary services to guarantee a secure and stable operation of the electricity grids between now and 2030,” but presented solutions, regulatory and technical. For frequency control, with less instantaneous reserve from rotating conventional generators in 2033, the electronics of the feed-in inverters from wind turbines can emulate this. Balancing energy requirements will increase, but be covered by a variety of options. For voltage control there will need to be several new means of providing increased reactive power in the grid, including phase shift transformers, and some redispatch can be used. Also provision of reactive power via inverter stations of planned HVDC lines is envisaged.

Some use is made of batteries which are bid into the primary control reserve market on a weekly basis. Operators are reported to have received an average price of €17.8/MWh over 18 months to November 2016.

Grid upgrade and expansion

In May 2012 the government 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 transmission system operators (TSOs) – 50Hertz, Amprion, TenneT TSO and TransnetBW – drew up a joint network development plan which identified the necessary grid expansions. State governments agreed to let BNetzA coordinate plans, rather than asserting regional interests (though Bavaria later reneged in this).

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 (from ten years), 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 the north to connect with the southern grid at the Grafenrheinfeld nuclear plant (near Schweinfurt in northern Bavaria) which closed down at the end of June 2015.

More broadly, onshore high-voltage grids in Germany will have to undergo considerable expansion to facilitate Energiewende and the development of the European electricity market. 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. 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 (Bundesbedarfsplangesetz, BBPlG). ENLAG aimed to expedite 22 urgent transmission projects identified by the German Energy Agency (Deutsche Energie-Agentur, DENA) and 85% of these (of 1800 km total) should be completed by 2020, with the balance by 2025, and then a link with Poland in 2030. 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. BBPIG projects are subject to accelerated planning procedures carried out by the regulator, and BBPIG 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. TSO TenneT expects the costs to be much higher, and has announced an 80% increase in its transmission fees from 2017, partly due to delays.

The change to undergrounding has caused target completion dates to slip substantially. With the key SuedLink (corridor C, 2.6 GW DC) to Bavaria, by the end of 2015, only 614 km of the required 1816 km distance had been covered, and the likely completion date is now 2025, three years after the last nuclear reactor has been retired. TenneT and TransnetBW aim to file a planning application early in 2017 for SuedLink and SuedOstLink (corridor D, 2 GW DC) and complete this process in 2021, with four years of construction to follow. Overall costs for 4 GW of DC capacity to the south including SuedLink corridor C could rise to €16.7 billion according to TenneT, due to requirements for underground cabling along part of the route. DIHK puts the total cost of grid expansion over 2016-2025 at €50 billion.

In an October 2016 study by the Düsseldorf Institute for Competition Economics (DICE), overall expenses of €55.3 billion have been calculated for transmission and distribution expansion by 2025.

Imports and exports

Energiewende depends heavily on neighbouring countries for back-up power and as dumping grounds for occasional surplus. With high input from solar or wind sources the supply may exceed demand, forcing the power surplus into the adjacent grids of neighbouring countries, and obliging those countries to compensate for German intermittencies by running their own conventional plants at less than economic levels. During 2015, the main exports were 23.7 TWh to Belgium (half going on to the Netherlands), 14.5 TWh to Austria, 12.5 TWh to Switzerland, 11.5 TWh to France, 8.2 TWh to the UK, and 10.7 TWh to Poland. The main import was 5.8 TWh from Norway’s hydro. In addition, a lot of surplus northern renewable power is routed south through Poland, Hungary, the Czech Republic and Slovakia. This loop flow is leading to proposals by the European Agency for Cooperation of Energy Regulators (ACER) for a north-south price zone split. Since 2002 the Austrian power market has been integrated with Germany’s, making the largest cross-border power market in Europe.

In October 2016 BNetzA announced that from July 2018 the Austrian power market would be split from Germany. This “has become necessary, because power grid transmission capacity in Germany, Austria, Poland and the Czech Republic no longer has the technical capacity to transport the power traded within the current common price zone even if a successful grid expansion is assumed in the long term,” it said, adding that at present TSOs had to carry out large-scale costly redispatching to ensure system security. “The need for redispatching measures has largely come from our inability to manage this transport capacity at the Austrian border. Congestion management is in place at other borders,” BNetzA said.

The Czech Republic is one of the adjacent countries affected by Germany’s grid problems. Since mid-2012 the 2 GWe Temelin plant has operated about 100 MWe below capacity as instructed by grid operator CEPS because of grid security issues caused by power surges due to renewable power production in Germany. The Czech Republic and Poland have installed phase-shifting transformers* on their German border to block German electricity dumping; France Netherlands and Belgium already had them. The Czech Republic is also boosting its lignite-fired generation capacity by 660 MWe at Ledvice, and CEZ has allocated €3.65 billon to refurbishing 11 coal and lignite power plants.

* These change the effective phase displacement between the input voltage and the output voltage of a transmission line, thus controlling the amount of active power that can flow in the line.

The Austrian power grid has difficulty in balancing unpredictable supply from wind and solar PV to demand requirements, though it does have substantial pumped hydroelectric storage capacity, including the new 430 MWe Reisseck II plant in Moelltal. However, adequate balancing power is still needed, requiring dependable sources such as gas-fired generating units to be available. In Austria most of these are now out of service, unable to compete economically, and hence the country has high reliance on uncertain German supply.

Replacing and closing down conventional generating capacity

An objective of Energiewende is to close down Germany’s nuclear generation capacity, which comprised 17 reactors and 20,339 MWe early in 2011, providing one-quarter of the country’s electricity. Eight reactors (8336 MWe) were closed in or by mid-2011, another in mid-2015, and another at the end of 2019, making a total of 11,003 MWe shut down. The remaining six operating reactors are due to close progressively in 2021 and 2022.

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 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 2014 as RWE announced a €2.76 billion loss, it said it planned to close or mothball 6.6 GWe capacity, 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 six-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 power 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 €20 million per year, as production had halved to 1 TWh in 2013. It called for capacity payments if the units were to avoid shutdown. Also RWE closed its 1.3 GWe Dutch Claus C CCGT plant in July 2014, less than two years after its commissioning, due to subsidised renewable supply across the border from Germany.

In March 2015 E.ON and co-owners applied to BNetzA to close down two state-of-the-art almost new CCGT units, Irsching 4&5 (550 and 846 MWe) in southern Germany from April 2016. They have thermal efficiency of about 60%. 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 expires 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/Uniper unit have been), so that they therefore need to be kept operational though run at a loss. The owners then commenced legal action. The two units were then closed and the owners expect them to remain so until near the end of 2020 apart from occasional use under redispatch contracts for ancillary services. The owners claim that this operation is at a loss. The German Association of Energy and Water Industries (Bundesverband der Energie- und Wasserwirtschaft, BDEW) have said that the economic viability of more than half of Germany’s planned power plants was called into question by government policies.

While gas-fired power plants fit better as flexible back-up for expanded renewables, they have been less economic than coal. Gas prices are high and supplies are uncertain, especially since sanctions were applied due to Russia’s annexation of Crimea. About 35% of Germany’s gas is imported from Russia, and fracking is banned. About 54% of gas-fired plants (some 30 GWe) are cogeneration, with their operation determined by demand for heat and hence less flexible. They have priority grid access. Apart from smaller open-cycle peaking plants built by TSOs, the only new gas-fired plants under construction are cogeneration.

However, late in 2016 the economics of gas-fired plants was positive for the first time in four years, and RWE notified its intention to restore Emsland B&C gas-fired units (359 MWe each) to continuous operation. Over 2017-18 the average load factor for gas-fired power-only plants was 23%, and in early 2019 about one-fifth of gas capacity was either mothballed or in a reserve scheme.

The major utilities have changed their core business to focus on demand-side management, energy services, and so-called 'intelligent' technologies such as smart grids, smart homes, smart meters, smart appliances, smart virtual power plants (accumulating renewable power generated from different sources into a single virtual power plant). All these technologies are based on software programs able to handle a large amount of data, and result in energy savings by those bearing the main cost burden of Energiewende. A new law for nationwide rollout of smart meters was approved in July 2016.

The integration of intermittent renewables with conventional base-load generation is a major challenge facing policymakers in Germany and elsewhere in the EU. Without resolution, investment in base-load generation capacity is likely to remain insufficient. In April 2018, the German Association of Energy and Water Industries (BDEW) announced that the country's power companies see a potential gap between conventional electricity supply and demand by the early 2020s. The companies urged policymakers to help investors plan better by rewarding conventional capacity.

The continuing role of coal

In 2016 lignite provided 150 TWh, 23% of Germany’s electricity (648 TWh total generation), and black coal provided 112 TWh (17%), but these figures had dropped by 2020. Legislation to begin closing down hard coal and lignite capacity became law in July 2020, subject only to EU state aid approval. It is expected to result in the closure of over half of the coal and lignite capacity by 2030, balanced by up to €50 billion compensation paid to mining districts. In the first phase to 2022, 3 GWe of lignite (Niederaussem and Neurath) and 6 GWe of hard coal capacity (using imported coal) is set to close.

With low EU ETS carbon prices and low coal prices, coal is more profitable than gas for power generation, and there is 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%). Whereas early drafts of the German climate action plan had pledged to end coal use “well before 2050”, this target was dropped in September 2016, but resurfaced in mid-2020 legislation. It is not clear how this provision of dispatchable capacity to meet base-load demand and also provide some load-following will be replaced. An earlier DENA scenario for 2033 had 20 GWe black coal and 12 GWe of lignite capacity out of 259 GWe total – 12% of capacity – plus 41 GWe fuelled by natural gas, making 28% of capacity being dispatchable.

An insight on the continued reliance on lignite can be gained from RWE, which in 2012 commissioned BoA units 2&3 at Neurath 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.” RWE planned a third such plant with supercritical technology designed to give 45% thermal efficiency nearby at Niederaussem but cancelled this in April 2019.

In 2019 Uniper reported that its new €1.5 billion 1100 MWe Datteln 4 coal-fired plant was expected to be commissioned early in 2020, despite opposition from Germany's Coal Commission. Its construction started in 2007 and it came online in May 2020.

Since the 1990s German coal-fired plants, including lignite, have been built to operate flexibly in load-following, and energy companies have invested heavily in retrofitting older ones to do the same, mainly with electronic operating systems. These plants then can adjust to variations in renewable energy generation and grid demand. Retrofits (costing up to €500/kW) have led to higher ramp rates, lower minimum loads and shorter start-up times, albeit with increased maintenance costs. Flexible operation of some plants is constrained by cogeneration commitments for district heat, and by the need to maintain ancillary services for the grid. State-of-the-art hard coal plants can operate at 25-40% of nominal load, and lignite power plants at 35-50%, according to Agora Energiewende. This compares with 40% for hard coal and 60% for lignite in the 1990s. Meanwhile, ramp rates can reach 6% of nominal load per minute, equal to or above the ramp rate of the most common CCGT plants. Lignite plants were running for at least 6000 hours per year (68% load factor), and hard coal plants for 3000-4500 hours.

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. 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 up to €230 million per year compensation over seven years, total €1.6 billion. The European Commission approved the arrangements in May 2016 under state aid rules.

In April 2016 RWE applied to BNetzA to close Voerde A&B coal-fired plants (700 MWe total), and in November 2016 Steag applied to close 2.5 GWe of 1970s coal-fired capacity: Voerde West 1&2, Herne 3 in North-Rhine-Westphalia, and Bexbach and Weiher in the western Saarland region. If allowed, the closures would take place 12 months after application. Output in October 2016 was 9.6 TWh from black coal in load-following, and 12 TWh from lignite as base-load.

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. 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.

Germany’s last black coal mine closed in December 2018, though black coal imports continue and new lignite mines are being opened.

Economic and CO₂ implications of Energiewende

In May 2007 the International Energy Agency (IEA) 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 capacity across its borders, according to the IEA. The country already had significant interconnection with France, Netherlands, Denmark, Poland, Czech Republic and Switzerland. This would put Germany in 2020 in much the same position as Italy, being dependent on neighbours for electricity (which would be substantially nuclear) and being a price-taker.

In February 2013 the energy and environment minister said that the costs of Energiewende could reach €1000 billion by the end of the 2030s. 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.

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 integration costs comprising the 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 has dropped to 23%. Coal-fired plants require more emissions trading system (ETS) 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, as noted above.

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. Total taxes, levies and surcharges in 2016 amount to almost 16 cents/kWh. Over 2005-14 residential electricity prices in Germany increased by more than the average total residential cost in the USA, and are now about three times the US average. In 2016, more than 330,000 households, predominantly low-income, had their electricity cut off.

The shortcomings of the EEG surcharge were laid bare once again during storm Herwart in October 2017. At the height of the storm, the price for electricity was minus 83.06 euros per megawatt hour, as wind energy with zero marginal cost was fed into the grid. Perversely, in such a situation when electricity producers have to pay their customers to 'sell' electricity, private consumers do not benefit. If the price of electricity is negative, the difference between the guaranteed rate and the market price increases, leading to a corresponding rise in the subsidy cost – which is ultimately paid for by German consumers. Instead, neighbouring countries such as Switzerland and Austria benefit, by utilising the free electricity to fill pumped storage reservoirs.

Nuclear phase-out plans mean that back-up for the 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 coal for dispatchable capacity, contrary to a major aspect of the popular sentiment driving that policy, and its predecessors.

In 2015 Germany’s net 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 varied very little from 2008 to 2015, suggesting that the 2020 target of 20% reduction from 2007 levels by 2020 is not attainable, nor that of the original 40% reduction from 1990 levels by 2020. In 2016, CO₂ emissions were about 916 million tonnes, against a 2016 target of 812 Mt.

A Finadvice report in July 2014 said that the lessons learned from Energiewende to then 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 programs resulted in numerous redesigns of the renewable support schemes, which increased regulatory uncertainty and financial risk for all stakeholders in the renewable energy industry.

An April 2017 report by the think tank Agora Energiewende highlighted the extent of taxes on electricity. Taxes, levies, fees and surcharges amount to 18.7 c/kWh for electricity, versus 7.3 c/kWh for petrol, 4.7 for diesel, and 2.2 for natural gas. Electricity users pay an implicit carbon price of €185/tCO₂, versus €18/tCO₂ for natural gas. Germany is ranked second highest in Europe for its household electricity prices (after Denmark), but near average for natural gas.

A further study by Agora Energiewende released in September 2017 stated that the country is set to miss its 2020 carbon emissions cutting goal “drastically”. The study found that current policy would result in emissions reductions of 30-31% in 2020, versus the 40% target on 1990 levels.

In 2017 the question of a carbon floor price was made acute by impending elections and coalition disagreement on the matter. The CDU/CSU major party is concerned about high energy costs and prioritises grid expansion, while the minor party SPD is keen to have a carbon price. The new French government promotes a €30/t CO₂ carbon price – while this would have a small effect in France, a floor price of €30/t would increase German wholesale prices by €15/MWh to about €50, according to Pöyry. Average costs for a coal-fired plant would increase from €35 to €55/MWh, and for modern gas-fired plants from €39 to €47.

The social context of Energiewende

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, forged under the influence of the Romantic tradition. This matured in the 19^th century and carried through into the 20th as a complex reaction to industrial capitalism. After resurgence in the 1930s, 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 promoting 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 the Greens, which complicated but did not counter negative perceptions of nuclear power’s clean energy credentials in the public mind.

Details of German attitudes to energy and especially nuclear matters are in the information paper on Germany.

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Notes & references

References

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Related information

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