English translation including amendments and the content of the following paper: Krüger, K., Rotering, N.: erfolgreich gestalten durch Pumpspeicherausbau. p. 37-44, VGB PowerTech, 09/2014.

Successful energy transition in by pumped storage expansion

Dr.-Ing. Klaus Krüger, Voith Hydro Holding GmbH & Co KG, Leiter F&E, Heidenheim;

Dr.-Ing. Niklas Rotering, Institut für Elektrische Anlagen und Energiewirtschaft RWTH Aachen, Forschungsgruppe Versorgungsqualität & Regulierung

1 Abstract

Operational flexibility in electrical energy generation and consumption as well as the provision of reliable available capacity are two major challenges of the German energy transition. The consistent deployment of cost-effective and proven pumped storage technology can provide significant contributions to meet both challenges. This paper shows that an expansion of pumped storage plants as part of the energy transition is a technically and macro-economically interesting option for Germany. Two future scenarios are investigated, one assumes an energy supply in 2030 with a 60% share of and another expects a renewable energy share of 80% in 2050. A central result of the investigations is that the appropriate operation of the existing pumped storage inventory and its further expansion can provide significant system adequacy and reduces the necessary fossil fuel power plant capacity for providing reliable available capacity. In a scenario with 80% renewable energy 23 GW pumped storage plants replace up to 16.6 GW thermal power plants. In addition, the pumped storage power plants significantly reduce renewable energy curtailment and substitute generation from fossil fuels when releasing the stored energy. This also contributes to an overall reduction of CO 2 emissions. Furthermore the fleet of pumped storage plants actively compensates the volatility of renewable energy from wind and solar generation and allows for a smoother and more economical operation of the remaining fleet of thermal power plants. This compensation of volatility allows a safer operation of the power system and thereby helps to avoid blackouts.

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2 Introduction

In Germany, there have already been "energy transitions" in the form of the replacement of coal by oil in the 1960s and 70s or the replacement of oil and coal by nuclear energy in the 1970s to 1990s. What these transitions had in common was that there was only a change in the primary energy source while the system architecture remained unchanged. In the past system architecture, energy storage did not have any important functionality, because a sufficiently high and permanently available reserve capacity was provided by coal and nuclear plants (base load capability with reliable available capacity) [1] and because the residual load was never below zero. Energy storage was previously performed by nature in the primary resources of coal, gas, uranium or oil, while electricity was generated according to demand, meaning that storage took place before production.

The production of renewable energy from wind and (PV) is detached from demand. As a consequence, in systems with a high share of production from volatile renewable sources, it becomes necessary to store electrical energy instead of fossil energy. This changes the sequence of storage and production. Currently, politicians assume that it will be possible to forego storage by focusing on grid expansion and the future flexibilisation of production and consumption. Many published articles (e.g. [6], [9]) propose compensating for the volatility of renewable energy by building controllable and highly flexible new thermal plants (e.g. gas power plants) and by promoting the use of demand side management (disconnecting consumers in the industrial and private sectors).

This paper presents a completely different approach to the two main challenges of energy transition relating to system technology: The provision of sufficient flexibility when feeding in significant amounts of renewable energy (RE) and ensuring system adequacy (reliable available capacity) during periods of low production from renewable sources.

In 2013, Voith Hydro commissioned a study with the Institute of Power Systems and Power Economics (IAEW) of RWTH Aachen University to examine scenarios in which pumped storage plants are used as "multifunctional power plants" to accomplish the necessary tasks as energy storages and for the provision of reliable available capacity. The study, which has since been published, is based on a simulation of the entire German power plant fleet using a dedicated plant scheduling optimization tool [2], which minimizes the costs of generation. A special feature of this study is the assessment of the combined usage options of pumped storage expansion from a macro- economical point of view. The study looks at two future scenarios offering a detailed analysis of a new role of pumped storage plants within the German electricity system. The first scenario considers power production in Germany in the year 2030 with an RE share of 60%, the second assumes an RE share of 80% in the year 2050.

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3 Methodology and assumptions

The ETG study [3] is recognized among specialists and is often cited. However, it only considers a simplified non-technology-specific storage model. It cannot be used to deduce detailed statements on pumped storage plants (PSPs). In addition, it assumes that a sufficient quantity of fossil-fuel power plants is always available to provide reliable available capacity. As a consequence, the potential contribution of storages to the provision of reliable available capacity has been underestimated. In contrast to the ETG study, the new IAEW study [2] does not assume that sufficient fossil-fuel power plant capacities are always available to cover the maximum national peak load. The new study rather aims to optimize the capacity of peak-load and storage power plants.

The central assumption of both of the above mentioned studies is that the future storage requirement following RE expansion will be largely determined by generation costs. This assessment is based on an approach that is macro-economical rather than micro-economical. The provision of additional system services by storage applications, such as spinning reserve (primary control), compensation of forecast errors, congestion management, voltage control, ensuring grid stability and supply quality as well as islanding operation, have not been analyzed.

The ETG study assumes a ratio of storage energy to power of 5Wh/W. In addition, the new IAEW study has also analyzed the ratios of 3Wh/W and 7Wh/W, arriving at the conclusion that a ratio of 7Wh/W is the most economical. Further assumptions are:

• No national transmission grid limitations • Limited to Germany, i.e. import/export = 0, • Other consumption based on ENTSO-E data [4], • RE production based on the IWES model and 2007 weather data [5], • RE installation costs and fuel cost model based on the 2010 BMU pilot study [6], • Perfect foresight and hourly resolution, • Investment costs for PSP extension: 1000 €/kW (power section), 50 €/kWh (storage section), • Ratio storage energy/power for extension 3 / 5 / 7 Wh/W, efficiency: 80%, service life: 60 years, • Mixed interest rate on capital of 4%.

In comparison with the ETG study, in the new study the investment costs for pumped storage and the interest rate on capital have been adopted to more realistic values. The analyses have been limited to Germany, as it was done in the ETG study, for the sake of simplification, because the focus is on the contribution of pumped storage to supply reliable available capacity. This is predominantly defined nationally and not Europe-wide in the current political context. However, in reality, scheduling takes place within the European electricity market (EEM). The shared peak load within the EEM is below the sum of the national peak loads. As a consequence, overcapacities are bound to develop if the nations involved ensure reliable available capacity by thermal power plants only. Thermal peak- load power plants with low efficiency or high variable costs would inevitably not be used and would

3 be unlikely to generate any profit contributions. In contrast to thermal peak-load power plants, PSP would also be used within the EEM and could consequently generate additional profit contributions [2].

2007 was chosen as the reference year for meteorological conditions for several reasons. Firstly, 2007 was a good wind year with a positive long-term average compared to 2006, 2009 and 2010. Secondly, 2007 featured some extreme weather events such as storms, but also some longer calm periods. For these reasons, the chosen reference year is well-suited as a conservative assumption for questions about storage requirements for the provision of reliable available capacity [2].

Fig. 1 shows the methodological sequence of the study. As a first step, the expected residual load (the residual load is essentially the load minus RE production and must-run power plants) which has to be covered by flexible thermal power plants and PSPs was calculated. Next, assessment of cost- effective expansion of storage capacity was performed. The potential contribution of PSP to reliable available capacity was calculated based on PSP expansion and the existing fleet of PSPs. Then the necessary power of the gas fuelled power plants according to the ETG study was reduced according to the determined contribution of the PSPs. Finally, an operation and scheduling analysis for an entire year considering the complete conventional and PSP fleet was performed in order to assess the costs and CO 2 emissions for the examined scenarios.

Fig. 1: Overview of the methodology sequence

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4 Assessment of cost -effective expansion of storage capacity

The graphs in Fig. 2 show the link between hours at full load and capacity expansion by PSP for the scenarios with an RE share of 60% and 80% according to the ETG study [3]. An average of 1,000 hours at full load in turbine mode was assumed as a constraint for an economically viable expansion. This is a typical calculation value which does not correspond to actual hours of operation. The turbine and pump operating hours are significantly higher, as the PSP has to deliver varying output within its control band. Additional utilization is added "on top" by the additional system services stated above, which were not considered here. This results in an economically viable expansion of 8GW of PSP output for the scenario with 60% RE and of 16GW for the scenario with 80% RE.

Fig 2: Full load hours versus power of PSP on basis of the ETG study

5 Determination of the storage capacity requirement for reliable available capacity

In order to determine the required storage capacity of the PSPs, the required contribution of the PSPs to the reliable available capacity was raised in the simulation model by increments of 1GW, while the output of the thermal power plant fleet was lowered accordingly. An iterative simulation over the 8,760 hours of the year was performed after the determination of the reliable available capacity by the PSPs. Each step included a testing whether the residual load exceeds or falls short of the thermal power plant output. If the residual load is exceeded, the upper reservoirs are lowered and power is generated by PSPs. The result of the energy balance decrease is cached. If the residual load continues to be greater than the thermal power plant output in the next time step, the deficit in the energy balance continues to increase. Otherwise, the upper reservoirs can again be restored and can potentially arrive at an even balance. In total, this procedure corresponds to the determination of the maximum reservoir capacity needed for a certain reliable available capacity to be provided by PSPs. 5

Fig. 3 shows an example of this procedure. The residual load is shown in blue, while the maximum output of the thermal power plant fleet of 50GW is marked as a continuous grey line. For this example, 10GW has been assumed as the reliable available capacity from storage. The residual load minus the thermal power plant output, i.e. the output relevant for storage dimensioning, is shown in red. In the example, the low residual load is insignificant until hour 19 because the upper basins have been assumed full at the beginning of the year. Between hour 19 and hour 23, 12GWh would be required from storage. Between hour 23 and hour 25, 9GWh could be restored. The energy requirement between hour 26 and 34 is 60GWh. Adding the 3GWh which could not yet be restored, this results in an energy requirement for the upper basins of 63GWh for this cycle. This calculation was then performed for the scenarios depicted in Fig. 4 for the entire year and the result is the maximum storage capacity which is needed to provide the necessary reliable available capacity by PSPs.

Fig. 3: Methodology to calculate the necessary energy storage capacity vs. reliable available capacity supplied by PSP

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Fig. 4: Energy storage demand vs. reliable available capacity via PSP

Fig. 4 shows three curves for the required capacity for the provision of reliable available capacity by PSPs for the RE scenarios of 40%, 60% and 80%. The reliable available storage by PSPs can be read according to RE expansion and energy stored in the upper basins. The black dot describes the situation with 40% RE and the currently available storage capacity in PSPs of 40GWh. In this scenario the current PSP fleet can provide its full capacity of 7 GW as reliable available capacity. In the scenario with 60% RE, the existing fleet and the expansion of 8GW at 7Wh/W with a total of 96GWh of maximum stored energy yield a reliable available capacity of 13GW by PSPs. Finally, in the scenario with 80% of RE, the existing fleet and the expansion of 16GW with a maximum stored energy of 152GWh can provide up to 16.6GW of reliable available capacity from PSPs.

The parabolic curves in Fig. 4 level off progressively as RE input increases. As a consequence, the potential for provision of reliable available capacity by PSPs increases together with a growing share of RE while the required energy storage capacity decreases.

Although this is admittedly a completely new approach, PSPs could in fact provide reliable available capacity if the entire PSP fleet is operated as described in the study, i.e. used as short-term storage for 2 to 3 days, and the "provisioning" of the storage basins is carried out depending on the residual load by RE and/or the thermal power plant fleet. Of course, PSPs are not capable of covering the base load in the way thermal power plants can. The maximum national load relevant for the dimensioning of the reliable available load to be held available, however, is always composed of the base load and a variable peak load. Consequently, PSPs can very well reduce the capacity to be held available by fossil-fuel power plants by covering the peak load and, in doing so, can contribute to the provision of reliable available capacity. A requirement for this is that the output of thermal power plants during nighttime is always enough to cover the load and, in addition, to fill the upper basins of the PSPs to the greatest possible extent, even if – and this is of crucial importance in this context – no RE input at all is available.

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The first important result of the study is the realization that the provision of reliable available capacity from all PSPs can rise, if sufficiently expanded, from 7GW today to 13GW in 2030 and up to 16.6GW in 2050. With this, a similarly dimensioned expansion of a fossil-fuel power plant reserve (gas power plants) could be avoided.

6 Effects of the use of pumped storage at 60% share of RE (2030)

Fig. 5 shows the typical load profile for one week for the 2030 scenario (top without PSP use and bottom with PSP fleet and expansion of 8GW). The share of RE plus must-run power plants is marked in grey, the share of thermal power plants is marked in yellow and the curtailment of RE is marked in red. In this scenario, 10GW are assumed as must-run power plant output for the stabilization of the transmission grid. The yellow share in the upper part of the figure is not the result of a plant scheduling optimization tool, but the difference between load profile and the share of RE plus must-run. This representation was chosen to give an impression of the volatile use of the thermal power plant fleet that would be necessary if neither energy imports/exports were possible nor pumped storage available. In contrast, in the figures including use of PSPs, the yellow load curves are always the result of a plant scheduling optimization tool.

Without the use of PSPs, excess production from RE regularly occurs which cannot be compensated even if fossil-fuel electricity production is almost completely shut off. In this situation, the PSP fleet receives the excess production from RE and returns it to the grid several hours later. This avoids curtailing wind and photovoltaics installations, creating a win-win situation for the PSP fleet and RE.

Fig. 5: Typical week load profile in 2030 (60% EE)

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Fig. 5 illustrates another win-win situation between PSPs and the thermal power plants because the consistent use of PSPs as short-term storage levels off the capacity curve of the fossil-fuel power plants, as well as reducing their peak load. This in turn leads to the following advantages for the thermal power plants:

• The number of start-up/shut-down processes is reduced, as are the load gradients. This reduces wear and tear of high-load components such as the steam generator and steam turbine including the connecting steam lines.

• This also significantly reduces start-up and shut-down costs. The macro-economical analysis of the study considers theses costs for the thermal power plants as well as their load-dependent efficiency.

• In addition, PSP expansion causes the yellow areas to become smaller, i.e. the use of PSPs spares the use of gas and/or coal as a fossil long-term storage. The actual reduction is significantly larger than shown in the figure because the start-up and shut-down losses incurred by the thermal power plants are not taken into account in the yellow areas.

The optimized interaction between the PSP fleet and the thermal power plants becomes particularly evident during weekends. On this Saturday, the yield from RE is very small, therefore the thermal power plants increase their output between 9 am and 4 pm to store energy. From 4 pm onwards, this energy is returned to the grid, leading to a reduction of thermal peak load. On Sunday, the situation is totally different: Excess production from RE cannot be completely accommodated during the day because, for some hours, it is even slightly higher than the entire installed PSP capacity of 15GW. In this case, curtailing the remaining difference surplus is more cost-effective than curtailing thermal power plants or even shutting them down completely and starting them up again a few hours later. The more cost-efficient thermal power plants even store energy in the upper basins of the PSPs during the day (the area of the blue hump in the lower diagram is considerably larger than the area of the red hump representing RE in the upper diagram) in order to have a sufficient amount of energy to release on Sunday evening and to prevent the activation of cost-intensive peak load power plants.

The existing lignite power plants benefit most from this situation by achieving a higher utilization of capacity. One can also see in Fig. 5 that the use of PSPs creates a continuous yellow base load strip for the thermal power plant blocks for this typical week. In the scenario with 60% RE, cheap fuels replace expensive fuels, i.e. coal replaces gas and the prevented curtailment of RE replaces gas if the energy is released again by PSPs. The estimation performed shows that the PSP fleet with an installed capacity of 15GW (7GW at present + 8GW expansion) prevents curtailment of 6TWh of RE (72.5% of 8.3TWh of RE overproduction).

In this 60% scenario, PSPs are used intensively. The hydraulic machines of the entire storage fleet including the existing inventory produce up to 1,100 full load hours in turbine mode and 1,400 full load hours in pumping mode.

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7 Effects of the use of pumped storage at 80% share of RE (2050)

Fig. 6 illustrates the same typical load profile for a week for the 2050 scenario. Excess production from RE happens regularly, almost daily, which cannot be compensated even by a complete shut- down of fossil-fuel energy production. According to the BMU pilot study, the share of must-run power plants has been set to zero, i.e. full flexibilisation of combined heat and power (CHP) and run-of-river power plants is assumed [6]. During the hours of RE excess production, the PSP fleet receives the surplus from RE and returns it to the grid a short time later. In this scenario, it frequently happens that no electrical energy at all is produced by thermal power plants (e.g. on Thursday). During the day, RE excess production is even markedly higher than the installed total PSP capacity of 23GW, meaning that even in the system with PSPs (bottom diagram) some small curtailment is necessary.

Similar to the 2030 scenario, there is also a win-win situation between PSPs and the remaining thermal power plants in the 2050 scenario (Fig. 6). Following the BMU pilot study [6] it is based on, lignite power plants are no longer included in the 80% scenario. The remaining coal power plants are fuelled with black coal. The consistent use of PSPs as short-term storage levels off the load profile of the fossil-fuel power plants and reduces their peak load in this case too. The associated benefits for the thermal power plants are the same as in the 60% scenario. However, it is of particular interest which sections of the thermal power plant fleet benefit from the use of PSPs. In contrast to the 2030 scenario, in which lignite is benefited, in this case the full load hours of efficient combined heat-and- power systems and of black coal power plants increase (according to merit order sequence). This is emphasized by the calculated figures for the CHP fleet: Coal CHP yields 1303h instead of 1237h, gas CHP yields 1987h instead of 1915h and biomass CHP yields 3758h instead of 3680h. The total production from CHP rises by 2.5TWh in 2050.

Fig. 6: Typical week load profile in 2050 (80% EE)

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For this scenario, it was estimated that the entire PSP fleet with an installed capacity of 23 GW (7 GW at present + 16 GW expansion) can prevent curtailing of 17.6TWh of RE (64.5% of 27.3TWh of RE overproduction). In this case, natural gas is replaced to a significant extent by released RE.

In the 80% scenario, PSPs are used even more intensively that in the 60% scenario. The hydraulic machines of the entire storage fleet including the existing inventory produce up to 1,400 full load hours in turbine mode and 1,800 full load hours in pumping mode. To also reach the required flexibility by means of continuous controllability in pumping mode, PSP expansion has to make use of machines that can operate in hydraulic short-circuit mode.

Fig. 7: Worst case scenario in December 2050, i.e. 2 weeks with less or no wind conditions

Fig. 7 shows 2 weeks (arranged in the centre) in the winter time with few or now generation from renewable sources, this means, the conventional thermal power plant fleet has to provide the necessary power, because the contribution of wind & solar drops almost to 0 MW in this situation. Only run-of-river, geothermal and biomass power plants have some contribution from renewables. The PSP fleet can reduce the maximum peak load for the thermal power plants at this point by approx. 10%. Furthermore, the PSP fleet helps avoiding inefficient short term operation of thermal power plants. Like in the other shown scenarios, PSPs have a smoothening and peak shaving effect for the thermal power plant loading. This diagram illustrates clearly, that for such weather conditions a large installed base of thermal power plants is necessary. Wind and solar installations cannot reduce this necessary reserve power of thermal power plants. A PSP extension up to 23 GW can reduce the necessary thermal power plant reserve by 16.6 GW.

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8 Main results of pumped storage expansion

The investigations on the basis of the 2030 60% scenario have shown that the PSP fleet with 15GW (7GW at present + 8GW expansion) can provide 13GW of reliable available capacity and renders the same amount of gas power plant capacity expendable. In addition, the PSP fleet prevents that the entire yearly production of 900 2.5MW class wind turbines (6TWh) has to be curtailed and subsequently discarded.

For the 2050 80% scenario, a 23GW PSP fleet (7GW at present + 16GW expansion) would raise the provision of reliable available capacity by PSPs to 16.6GW, meaning that the same quantity of gas power plants would be unnecessary. In addition, curtailing and discarding the entire yearly output of 2,640 wind turbines of the same type (17.6TWh) would be prevented.

It has also been suggested to exceed expansion of RE systems to avoid temporary RE storage and to reach the scenarios of 60% RE and 80% RE earlier. This overlooks the fact, however, that wind can only provide 1% of the installed capacity as reliable available capacity, while the contribution of photovoltaics to reliable available capacity is zero [7]. As has been demonstrated in this paper, PSPs on the other hand can contribute significantly to the provision of reliable available capacity.

A high-tech nation such as Germany should not allow RE created by complex production methods to go to waste by curtailing it, but should use surpluses reasonably and efficiently, e.g. by "recycling" them via PSPs – particularly when these intelligent solutions are also cost-effective from a macro- economical point of view. Various other suggestions of how to use RE surpluses (e.g. power-to-gas, power-to-heat) have been put forward, but their efficiency levels are significantly lower than with PSPs and these solutions do not yield a reliable available capacity in the dimension of 13 to 16.6GW as a "by-product".

A large PSP with a capacity of 1.3GW can prevent the loss of 1TWh of wind power by curtailment. This would correspond to the yearly production of 150 2.5 MW class wind turbines, which would then not be built only to stand still (Fig. 8). Moreover, RE expansion with PSPs can prevent the provision of gas power plant capacity (see symbolic representation in fig. 8, bottom right), but RE expansion without PSPs cannot.

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Fig. 8: One PSP of 1.3 GW prevents the curtailment of 1 TWh wind and simultaneously provides 1 GW of reliable available capacity

Fig. 9 illustrates the macro-economical investment and the changes in electricity production costs with and without PSP expansion for both scenarios. The graphic is to be understood as follows: If no new PSPs are built, additional gas power plants have to be constructed at a cost of EUR 102 million p.a. in the 2030 scenario or EUR 179.2 million p.a. in the 2050 scenario. The installation of 8GW of new PSPs (while eliminating the need for gas power plants) would necessitate and investment of EUR 477 million p.a., while 16GW of PSPs would cost around EUR 955 million. The total investment costs are the result of adding the first two columns. On the other hand, PSP expansion would yield lower variable energy costs, as shown in column 4. The following distribution roughly applies to both scenarios: 80% of the variable energy costs are avoided gas fuel costs, while the remaining 20% are costs for CO 2 certificates. Analyzed from the opposite point of view, this means: If the PSPs are not built, in 2050 the power plant operators of Germany would have to pay EUR 764 million p.a. for gas supplies and would have to calculate expenses of EUR 191 million for CO 2 certificates [2].

Fig. 9: Impact on investments and on the levelized cost of electricity (LCOE) in Germany

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The final column shows the changes in electricity production costs in Germany resulting from the difference between columns 3 and 4. PSP expansion also may results in lower electricity costs for consumers because electricity production costs decrease (as shown in fig. 9 on the right).

Some readers might ask how large the substantial investment in PSP expansion is compared to the other costs of the German energy transition. Fig. 10 shows the yearly levelized cost of electricity (LCOE) production costs (based on [6]) for the 2030 and 2050 scenarios broken down into variable energy costs (fuel costs + CO 2 certificates) and investment costs for storage and investment costs for power plants (RE and conventional). It is easy to see that the investment in storage forms a relatively small fraction of the total investment needed but is cost-effective, as demonstrated in fig. 9.

Fig. 10: Levelized cost of electricity for the 60% RE and 80% RE scenario

9 Pumped storage potentials in Germany

Currently, 23 PSPs with a capacity of over 7,000MW are in the planning and approval stages, which could more than double the German PSP fleet (see table 1). Considering the studies presented in this document, one can conclude that the demonstrated necessary expansion of about 8,000MW of PSP capacity for the 2030 scenario is today already matched by a sufficient number of projects, which are moreover well distributed geographically:

• : Leine Valley • North Rhine-Westphalia: PSP Lippe • : Schmalwasser • : expansion project Waldeck II+ • Rhineland-Palatinate: RIO • Bavaria: Riedel • Baden-Wuerttemberg: Forbach, Atdorf 14

Sufficient location options are also available for the continuously increasing demand in future energy production 80% of which, according to the 2050 scenario, will be met by RE. Site screenings have yielded the following PSP potentials: 6GW are available in the operational area of RWE, 19GW with EnBW, 4.8GW in Thuringia [11].and 11GW in Bavaria [12].

Name of the power Power [MW] Status Corporation station

Atdorf 1.400 Plan approval procedure Schluchseewerk AG

Stadtwerke Ulm/Neu-Ulm GmbH, Blautal 60 Regional planning procedure Eduard Merkle GmbH & Co. KG

Forbach 200 Regional planning decision received EnBW AG

Sorpeberg- Mark-E Aktiengesellschaft, 420 Planning Ermecketal Grünwerke GmbH

RIO 300 Regional planning decision received Stadtwerke Trier

RWE Innogy GmbH, RAG Montan Halde Sundern 10-15 Feasibility study Immobilien GmbH

Energiespeicher Riedl 300 Plan approval procedure Donaukraftwerk Jochenstein AG

Waldeck 2+ 300 Investment decision pending E.ON SE

Einöden 150 Planning Pumpspeicherwerk Einöden GmbH

Lippe 320 Feasibility study HOCHTIEF AG

Energieallianz Bayern GmbH & Co. Jochberg 700 Planning KG

Regional planning decision and Nethe 390 Trianel GmbH regional planning modification received Leinetal 200 Regional planning decision received HOCHTIEF AG

Rottachsee 40-60 Planning Allgäuer Überlandwerk GmbH

Breitenstein 60 Planning Allgäuer Überlandwerk GmbH

Leutenberg 380 Planning STRABAG AG

Ellrich 640 Planning STRABAG AG

Schmalwasser Über 1.000 Regional planning procedure Trianel GmbH Heimbach 280-320 Regional planning procedure Stadtwerke Mainz AG

Naturstromspeicher 16 Plan approval procedure MBS Naturstromspeicher GmbH Gaildorf

Osser n.s. Planning Visprion Engineering GmbH

Hainleite 240-500 Regional planning procedure HOCHTIEF AG

Max Aicher Poschberg Projekt Poschberg 450 Feasibility study GmbH 7.856 – Summation 8.181 MW Table 1: Planed PSP locations in Germany

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10 Conclusion

The provision of flexibility and reliable available capacity are two essential challenges of Germany’s energy transition. The consistent deployment of a technology as cost-effective and reliable as pumped storage for short-term storage can provide significant contributions to meet these challenges.

Pumped storage can reduce the share of reliable available capacity to be provided by fossil-fuel power plants. 15GW PSPs with a storage capacity of 96GWh replace up to 13GW from gas power plants in a 60% scenario. In an 80% scenario, 23GW PSPs with a storage capacity of about 152GWh replace even up to 16.6.GW from thermal power plants.

The studies showed that PSP expansion of 8GW by 2030 and of 16GW by 2050 can be macro- economically viable. The investment costs are paid off from a macro-economical point of view by a reduced consumption of natural gas and by fewer investments in gas power plants. Additional macro- economical benefits lie in the cost-optimized & smoothened operation of the remaining thermal power plant fleet and the coverage of additional system services that ensure a safe operation of the power, which have however not been monetarily assessed here. PSP expansion to 23GW also offers benefits in, for example, exceptional situations such as grid reconstruction since PSPs, unlike thermal power plants, are generally capable of a black start.

The use of pumped storage reduces CO 2 emissions by up to 2 million t/a as the storages prevent curtailment and replace fossil-fuel based production by using the stored energy [2]. In addition, efficient CHP systems are better utilized in long-term and will reach higher full load hours.

The use of PSPs significantly prevents the curtailment of renewable energies. In comparison with the scenario without any PSPs, wind power and photovoltaic systems would have to be curtailed 72.5% less in 2030 (60% RE) and 64.5% less in 2050 (80% RE). In addition, the stored RE surplus can be released later without any CO 2 emissions. The PSP fleet compensates the volatility of RE and allows for a smoother and more economical operation of the remaining thermal power plants. Because of the absorption of RE volatility, disconnecting consumers in the industrial and private sectors becomes for the most part unnecessary. By linking the continued expansion of RE with the additional expansion of PSPs, energy transition can more easily become a reality.

However, these benefits can only be achieved, if some factors regarding regulation and legislation are adopted: a) The majority of existing studies on the development of the power plant fleet in Central Europe only consider a provision of reliable available capacity by flexible thermal generating systems, i.e. gas turbines and gas power plants. However, as is shown here, PSPs can provide reliable available capacity as well. Therefore PSPs should be considered, when potential capacity mechanisms are discussed. This is state of the art in other European countries [4].

16 b) Changes in electricity market design should focus more on the value of short-term available flexibility. PSPs will also benefit from such measures, as they are multifunctional power plants (reliable available capacity, balance energy in case of forecast errors, extremely steep load gradients etc.) c) Explicit consideration of energy storage in legislation and exemption from load duties. These measures should affect the existing PSP fleet as well as planned expansions. d) Present and future net export of German RE surpluses to neighboring countries (often at very low prices) should be significantly reduced in order to substitute Germany's own fossil fuels consumption. Presently these RE exports replace fossil and nuclear energy carriers abroad and

improve the CO 2 balance of the neighboring countries at the cost of the German parties paying the EEG surcharge (German renewable energy surcharge). One of the consequences thereof is that one of the main goals of the energy transition is presently being missed [10].

From a political point of view, the expansion of pumped storage can also be of interest beyond the context presented here. Firstly, the associated investments result in macro-economical benefits (e.g. additional jobs) especially compared to the consumption of fossil energy carriers. Secondly, another obvious political benefit is the reduced dependence on gas imports.

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11 References

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[9] Netzentwicklungsplan Strom (NEP) 2013 bestätigt durch die Bundesnetzagentur, Online: www.netzausbau.de/nep-ub2

[10] Bettzüge M.-O.: Nationaler Hochmut oder cui bono? Physik Journal 13 Nr. 5, 2014.

[11] Thüringer Ministerium für Wirtschaft, Arbeit und Technologie, Pumpspeicherkataster Thüringen, 2011, Online: http://www.wir-thueringen.de/publikationen/pumpspeicherkataster-thuringen

[12] Bayrisches Landesamt für Umwelt, Analyse der Pumpspeicherpotential in Bayern, München 2014, Online: http://www.stmwi.bayern.de/fileadmin/user_upload/stmwivt/Themen/Energie_ und_ Rohstoffe/Dokumente_und_Cover/2014-Pumpspeicher-Potenzialanalyse.pdf.

Contacts: [email protected], [email protected]

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