By Hans-Wilhelm Schiffer Executive Chair, World Energy Resources of the World Energy Council Consultant and Advisor to the Executive Board of RWE AG for Cornerstone
German energy policy is determined by different ambitious targets. That is especially true as far as the electricity sector is concerned. The main characteristics of electricity-sector policy are a complete phasing out of nuclear energy, the transition to a power supply based mainly on renewable energy, and the reduction of energy consumption by continuously increasing efficiency. The main purpose of these changes is to reach a nearly CO2-free power supply by 2050. The central challenges are keeping the power system stable and secure while maintaining consumer electricity prices at a competitive, affordable level.
CURRENT STATUS AND TRENDS
The German government´s energy policies have undergone a profound change over recent years. In September 2010, the government launched a comprehensive “Energy Concept” featuring a large number of policy goals for future decades concerning energy and electricity consumption, the share of renewable energy, and the reduction of greenhouse gas emissions. A central component of this concept was to extend the operation time of nuclear power plants, at that time seen as a bridge technology in the era of renewable energy.
Following the Fukushima nuclear disaster in March 2011, however, the German conservative-liberal government coalition made an abrupt U-turn by mandating the complete phase-out of 8.4 GW of nuclear capacity immediately, with the remainder (12.1 GW) to be decommissioned between 2015 and 2022. With the decision to shut down all nuclear capacity by 2022, the government returned to a phase-out schedule conceived in 2001 by the socialist-green government in power at the time. In the coalition contract of the new conservative-socialist government, signed in November 2013, the phasing-out decision for nuclear energy was confirmed. Furthermore, the coalition partners agreed on slightly modified targets concerning the reduction of greenhouse gas emissions, the consumption of electricity, and the increase of the share of renewables in the electricity supply for 2020 (35%), 2025 (40–45%), 2035 (55–60%), and 2050 (80%).
The decision to phase out all nuclear power plants is generally considered a final one due to public pressure that accompanied the nuclear debate over past decades.
The envisaged expansion of renewable energy is a technological and financial challenge. The principal objectives of the Energiewende (Germany’s transformational energy policy) are:
- Transitioning German power supply from a conventional-based system to one mainly based on renewable energy;
- Keeping power prices on a competitive level for industry and an affordable level for private households;
- Ensuring continuous, secure supply.
The main instrument being used to make renewable energy the backbone of the German power supply is the Renewable Energy Sources Act, last amended on 1 August 2014. This law provides guaranteed feed-in tariffs for renewable electricity for 20 years after a power plant is commissioned. Grid operators are obliged to purchase the entire quantity of renewable electricity with priority. The trade companies pass on the deficit (i.e., feed-in tariff minus market price) to customers by imposing a reallocation charge.
The renewable capacity for power generation increased from 12,330 MW in 2000 (less than 10% of total capacity) to 40,357 MW by the end of 2008 and to 84,404 MW by the end of 2013 (45%) (see Figure 1). In 2000, renewable energy’s share of consumption was less than 7%, then grew to over 25% by 2013. The total amount of renewable energy capacity on 31 December 2013 is shown in Table 1.
Within just the last five years (between the end of 2008 and the end of 2013) the capacity increase was 29,828 MW for photovoltaics (PV) and 10,845 MW for wind energy. This demonstrates that the funding system for renewables has been quite effective.
However, the growth of renewables in Germany has come at a cost. The total feed-in amounts based on subsidized renewables in Germany stood at 125.7 TWh in 2013. The remuneration paid to plant operators and premium payments totaled €20.4 billion in 2013. Deducting income from mar-keting, on balance, net subsidy payments were approximately €16.2 billion in 2013.
The subsidies are financed via a reallocation charge that is paid by electricity consumers through a markup on the grid-access fee. Starting on 1 January 2014, this reallocation charge was increased to €62.40/MWh. The reallocation charge has now reached a level at which it is twice as much as the wholesale price of electricity.
A comparison between electricity prices reveals the dilemma facing Germany today. Power prices for industry are on the same level as those in Japan. In fact, private customers in Germany pay even more for electricity than private consumers in Japan. Within the EU, Germany’s private consumers pay a higher price than any country except Denmark. Electricity prices in Germany are more than twice the OECD average and three times as high as in the U.S.
CHALLENGES FOR POWER PRODUCERS1
With the increase in renewable energy, power producers also face a new challenge. In the past a main focus was offsetting fluctuations in consumption between day and night, workdays and weekends, and seasonal variations. Today, feed-in intermittency has added a new source of fluctuations that are at least the same magnitude as those from changes in consumption.
These demand and renewable energy feed-in fluctuations must be continuously balanced to provide electricity grid stability, which is putting pressure on the conventional power generation portfolio. Power generation from conventional plants has to be able to flexibly adjust to the residual load at any time (i.e., to compensate for the difference between consumption and fluctuating renewable energy). This is a challenge for grid operators, especially when high wind feed-ins in northern Germany force the “redispatching” of thermal units intraday, often leading to lower coal-based output in the north and a ramp up of capacity in the south to keep the system in balance.
The need for load adjustments by flexible power plants is particularly critical when an increase in electricity demand occurs at the same time as the feed-in from wind power plants dramatically decreases.
There has been a need for load adjustments of >50 GW (i.e., >60% of the peak load) within an eight- to 10-hour period. This sort of demand fluctuation is generally random, but can be forecast up to two days in advance (e.g., via a wind forecast).
Thus, conventional power generation plants are faced with massive technical and economic challenges. Today, fluctuations in the feed-in of renewables-based electricity are already having a considerable impact on the load to be covered by conventional power stations. To illustrate the effect of such fluctuations, looking closely at electricity demand and sources can be helpful. Due to the high demand and low feed-in of electricity from renewable energies, on 24 January 2013 up to 74,335 MW—92% of the peak demand of 80,739 MW in Germany—had to be covered by conventional power plants. Conversely, on 24 March 2013, a Sunday with low electricity demand coupled with high feed-in from wind and solar, a minimum of 14,405 MW had to be covered by conventional power stations. This represents a tremendous shift in the role of conventional power plants.
Flexibility to Meet Load Fluctuations
The German electricity transmission network is part of the European synchronous zone and is connected with neighboring European markets. A regular exchange of electricity takes place with all adjacent countries (i.e., France, Netherlands, Denmark, Poland, Czech Republic, Austria, and Switzerland). However, since these markets are also expanding wind capacities and consumer behavior in all markets shows substantial similarity, the capacity to adjust imports and exports to meet German electricity market fluctuations is limited.
Therefore, the required flexibility to meet load fluctuations must be predominantly managed by existing national power plants. Existing power plants in Germany are all designed to cater for flexible operation, and these requirements are equally met by new NGCC plants and new coal-fired power plants.
Many of the conventional power plants operating in Germany today were built in the 1980s and 1990s, before expansion targets for wind and photovoltaic plants had been adopted. In many plants, measures to allow greater flexibility have been implemented subsequently, so that power plants can meet increased requirements for market load adjustments. As a result, there are very few dedicated German baseload power plants that do not allow for flexible operation.
The necessary operational flexibility of coal- and gas-fired power plants can be illustrated with an example from 1 and 2 January 2012 (see Figure 2). On Sunday, 1 January, power demand was relatively low due to low industrial demand and mild temperatures of approximately 8°C (46°F). Around the evening peak, a temporary daily maximum consumption of 56 GW was reached in the German power grid, after which demand decreased to a minimum value of less than 41 GW until the late evening.
At the same time, the amount of wind feed-in temporarily reached a very high level of more than 16 GW. Further feed-ins that day came from other renewable energy sources, including run-of-the-river hydro and biomass power plants, which also benefit from feed-in priority. The feed-in from those plants consistently amounted to about 5 GW. The power generation from photovoltaic plants was negligible due to the season as well as the cloudy weather that weekend.
On Sunday evening, after the renewable energy feed-ins were accounted for, only a residual load of 21 GW had to be temporarily covered by other power plants available according to schedule.
At 4:00 am on Monday, 2 January, power consumption soared and reached a demand level of approximately 73 GW at around noon. This corresponds to an increase of 32 GW within eight hours. At the same time the feed-in from wind power plants decreased in the early hours of the morning due to declining wind speeds and intermittently amounted to only 4 GW at around noon. In parallel, a decrease in feed-in of about 12 GW was registered on the supply side. Thus, overall, an additional power output of nearly 45 GW had to be provided by the thermal power plant portfolio within those eight hours.
The left-hand side of Figure 2 displays the parallel development of increased power consumption and decreased, intermittent wind feed-in, requiring a high degree of load adjustment from the conventional power generation portfolio.
Power generation from German nuclear power plants contributed, almost without interruption, a supply of about 12 GW. There is a degree of flexibility available from the German nuclear power stations, although their low-variable power generation costs ensure that this is only used once the load adaptability of the fossil-fired power plants has been exhausted. As seen in the right-hand side of Figure 2, the necessary load adjustment of about 50 GW on Monday morning was almost completely provided by the coal- and gas-fired power plants.
On Sunday night, almost 40% of the coal-fired power plants were still in operation, although the requirements for coal-fired power plants at that time had reduced to about 20–60% of their installed output capacity. Overall, their contribution was only about 10 GW.
The conventional gas-fired power plants were almost completely off the grid on Sunday night, since part-load operation of gas-fired power plants is considerably more expensive than it is for coal-fired power plants.
In the early hours of Monday morning the increase of residual load was initially covered by coal-fired power plants supporting the grid by means of less than full load operation. In parallel, additional coal-fired power plants went into operation that had previously been off the grid. Grid synchronization of fossil-fired plants commences approximately one to four hours after initial boiler firing. Subsequent to the grid synchronization, newly started coal-fired power plants met the required load increase until about midday.
Generally, available gas-fired power plants are returned from downtime to meet the load peaks on Monday. The first feed-ins from gas-fired plants are normally in the early morning, from 5:00 am onward. Over the course of the day, load balancing is mainly regulated by gas-fired power plants, and the coal-fired power plants remain at full load until the evening.
On the particular Monday being evaluated, load adjustments were made by a combination of available coal- and gas-fired power plants. In doing so, the coal-fired power plants provided about 75% of the required flexible output.
Flexible Use of Coal- and Gas-Fired Power Plants due to Fluctuations of PV Feed-In
The average cycle between strong and weak wind phases is about three to five days in northwest Europe. Even in the event of short-term changes, as portrayed in the first example, the thermal power plant portfolio has several hours in which to adjust load.
Short-term feed-in fluctuations are also triggered by the output of widely developed solar photovoltaic power plants in Germany. The effects can be seen from the beginning of spring as the daily level of solar radiation increases.
The timing of the increase in solar radiation in the morning does not coincide with the increase in power consumption. While electricity demand increases between 4:00 and 8:00 am, the increase in photovoltaic feed-in occurs between 8:00 am and 1:00 pm. Similarly, photovoltaic feed-in decreases in the evening, some hours before the decline in power consumption. Consequently, thermal power plants have to kick in at short notice twice—in the morning and in the evening—on days with a high photovoltaic generation.
16 March was one of the first days in 2012 with intensive solar radiation in Germany. The feed-in from photovoltaic plants increased by about 16 GW between 8:00 am and 1:00 pm. Between 2:00 and 6:00 pm, it decreased. On that day, wind levels were extremely low (see Figure 3).
To cover peak consumption in the morning, coal- and gas-fired power plants started operation. In order to accommodate the temporarily high photovoltaic feed-in around midday, and afterward provide full load to cover the evening peak, the gas-fired and coal-fired power plants were intermittently operated between partial and full-load operation.
Figure 3 shows the course of intermittent feed-ins and the adjusted operation of conventional power plants (new gas and steam power plant, new coal-fired power plant, and an existing coal-fired power plant with optimized flexibility parameters), following changes in demand and available generation from renewable energy sources. In the case of 16 March 2012, German coal- and gas-fired power plants were able to accommodate photovoltaic feed-in variations mutually because of their short-term flexible operating capability.
Flexibility Characteristics of German Coal- and Gas-Fired Power Plants
In the regular configuration of two gas turbines and one steam turbine, the minimum load of a new gas-fired combined-cycle plant is typically around 60% of its installed capacity. An even lower minimum load is achievable by switching off one gas turbine; this, however, causes a substantial decrease in efficiency, and thus is rarely employed.
In contrast, a new coal-fired power plant has a lower minimum load capability of approximately 40%, with further potential to reduce this to 20–25%. The reason is that the output of the coal boiler is controlled via direct fuel combustion and not, as is the case with a gas combined-cycle power plant, via a heat recovery steam generator with an upstream gas turbine.
German power plant operators have also made it possible to reduce the minimum load of operation at existing power plants by optimizing the boiler-turbine system using modern control systems. Today’s optimized coal-fired power plants are able to operate at a partial-load level of less than 20% of full-load capacity.
The change (i.e., ramp) between partial load and full load at power plants involves load changes of approximately three percentage points per minute, and the change in mode of operation can therefore be achieved at all plants in less than half an hour (see Table 2 and Figure 4).
Despite the continued increase in renewable capacity, the role of fossil fuels for power generation in Germany will be more or less the same in 2023 as in 2013 (see Figure 5).
The fundamental reason is the complete phasing out of nuclear power capacity by the end of 2022. By 2034 the total capacity on the basis of renewables is expected to be approximately 173 GW, which is twice as much as the peak load in Germany.2 However, a conventional capacity of 82 GW will still be needed (compared to 100 GW in 2012) to cover the demand when the wind is not blowing and/or the sun is not shining.2 The required flexibility to meet the fluctuations is being fulfilled just as well by coal-fueled as by gas-fueled power plants. These plants are being made increasingly flexible, ensuring that they can continue to serve their important role in Germany’s electricity market.
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The content included in Cornerstone is based on the opinion of the authors, and does not necessarily reflect the views of the World Coal Association or its members.
- IEA Coal Industry Advisory Board. (2013). 21st century coal: Advanced technology and global energy solution. Paris: OECD/IEA. www.iea.org/publications/insights/21stcenturycoal_final_web.pdf
- 50Hertz Transmission/Amprion/ TenneT TSO/TransnetBW, Grid development plan electricity 2014, Berlin/Dortmund/Bayreuth/Stuttgart, 2014. (in German)