atw Vol. 64 (2019) | Issue 2 ı February FEATURE | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER 78 reality of power flows and power grid limitations. This study tackles this limitation by introducing a coupled market and grid system analysis. This innovative method enables a good estimation of grid management measures volumes and costs required to realize an optimized power mix. However, it contains some simplification worth mentioning. First, the evaluation is performed at the European level as a proxy for the German grid management measures. Since the origin of the effect – early closure of NPPs – would occur in Germany, this approximation seems realistic. Second, real life grid management measures and redispatch contain some meta-heuristic characteristics: at the level of transmission system operators (TSOs), responsible to ensure the stability of the power grid, human-based decisions requiring engineering judgment are often made. This aspect makes the evaluation of redispatch volume and costs via a modelling tool particularly difficult. To quantify the associated bias, a possible way forward would be an analysis of grid management measures and costs in previous years with the couple BID3 – PSS/E approach. 5 Conclusion This study investigates the effects of nuclear power plants (NPPs) premature phase-out early 2020 on the German power system for the years 2020–2022 by carrying out a model-based market analysis in iterative conjunction with a power grid system simulation. Results are generated according to market dispatch which consequently are adapted to adhere to network constraints through grid management measures. According to market dispatch analysis, the early closure of NPPs early 2020 would reduce the social welfare by ~2 billion EUR per year. This loss is carried by consumers. Producers would gain as their higher cost of generation are overcompensated by the increased wholesale price. The increase in wholesale prices is in the range of 4–7 EUR/MWh which feeds through to large consumers directly and is slightly reduced to a lower EEG levy for smaller consumers. Capacity margins are reduced by up to ~25 % (1.5 GW) without NPPs from early 2020 onwards. Those results are obtained with simulations performed using the reference weather year of 2013. The choice of that specific weather year is made to remain as objective as possible since 2013 had average temperatures and RES generation. Some effects are worsened considering other weather year with more extreme behavior. A sensitivity study is performed with the weather 2012 where the cold spell already puts the system under further stress. CO 2 emissions are also adversely affected by a premature nuclear phase-out with an additional 89.9 million tons of CO 2 emitted additionally over the three years. With regards to power grid effects with and without NPPs in the German system, diverging effects occur. The thermal redispatch costs increase without NPPs by 78 million EUR over the period 2020-2022. In parallel the generation from renewable energy sources first increases before decreasing in 2022. In total the grid management costs decrease by 219 million € over the period 2020–2022, remaining minor compared to the above-stated loss of social welfare. The system is stressed additionally by the departure of NPPs as transmission losses increase (2–10 % per year) and north to south flows increase by up to 4.7 TWh per year in specific regions. The study reviewed solely the effects of an accelerated closure of NPPs early 2020. An extension of nuclear power plant lifetime beyond the current phase-out timeline stated in the nuclear power law of 2011 is out of the scope of this work. Acknowledgement The authors would like to acknowledge Pöyry Management Consulting GmbH and PreussenElektra GmbH efforts to enable this work. A special thank goes to the ENTSO-E organization and the German TSO Tennet TSO GmbH, Amprion GmbH, TransnetBW GmbH, 50Hertz Transmission GmbH, for their support. References [1] O. Renn and JP Marhsall. Coal, nuclear and renewable energy policies in Germany: From the 1950s to the “Energiewende”. Energy Policy, volume 99 p224-232, 2016. [2] OECD/Nuclear Energy Agency. The Full Costs of Electricity Provision. NEA report No. 7441, 2018. [3] International Monetary Fund (IMF), World Economic Outlook, April 2017. [4] Backcasting the GB Balancing Mechanism with BID3. O. Stoica and T. Poffley. Poyry and national Grid join report, Sept 2017. [5] https://www.siemens.com/global/en/home/products/energy/services/transmissiondistribution-smart-grid/consulting-and-planning/pss-software/pss-e.html [6] Audit of the BID3 Pan European Market Model for National Grid. K. Bell and I. Stafell, National Grid, Oct 2016. [7] Netzenwicklungsplan Strom, 4 TSOs, Marktmodell BID3 (Kapitel 3.1), 2015. Authors Denis Janin Volker Raffel PreussenElektra GmbH Dr. Eckart Lindwedel Pöyry Management Consulting (Deutschland) GmbH Prof. Graham Weale Ruhr Universität Bochum James Cox Pöyry Management Consulting (UK) Ltd Geir Bronmo Pöyry Norway AS Feature | Major Trends in Energy Policy and Nuclear Power Contribution of Nuclear Power Plants to the Energy Transition in Germany ı Denis Janin, Eckart Lindwedel, Volker Raffel, Graham Weale, James Cox and Geir Bronmo
atw Vol. 64 (2019) | Issue 2 ı February Serial | Major Trends in Energy Policy and Nuclear Power Wind Energy in Germany and Europe Status, potentials and challenges for baseload application: European Situation in 2017 Thomas Linnemann and Guido S. Vallana Introduction Wind power is a cornerstone of rebuilding the electricity supply system completely into a renewable system, in Germany referred to as “Energiewende” (i. e. energy transition). Wind power is scalable, but as intermittent renewable energy can only supply electrical power at any time reliably (security of supply) in conjunction with dispatchable backup systems. This fact has been shown in the first part of the VGB Wind Study, dealing with operating experience of wind turbines in Germany from 2010 to 2016 [1],[2]. This study states among other things that despite vigorous expansion of on- and offshore wind power to about 50,000 MW (92 % onshore, 8 % offshore) at year-end 2016 and contrary to the intuitive assumption that widespread distribution of about 28,000 wind turbines, hereinafter referred to as German wind fleet, should lead to balanced aggregate power output, no increase in annual minimum power output has been detected since 2010, each of which accounted for less than 1 % of the relevant nominal capacity. The annual minimum power output reflects the permanently available aggregate power output (secured capacity) of the whole German wind fleet by which conventional power plant capacity can be reduced on a permanent basis. Or in other words: In every year since 2010 there was always at least one quarter of an hour in which more than 99 % of the nominal capacity of the German wind fleet was not avail able and, for all practical purposes, a requirement for 100 % dispatchable backup capacity prevailed, although its nominal capacity had almost doubled at the same time. Intuitive expectations that electricity generation from widespread wind turbines would be smoothed to an extent which in turn would allow the same extent of dispatchable backup capacity to be dispensed with has therefore not been fulfilled. Dispatchable backup capacity is essentially necessary to maintain a permanently stable balance between temporal variations of outputs from wind turbines and other power plants fed into the power grid and consumerdriven temporal demand variations extracting power from the grid (frequency regulation). To maintain power grid stability, ancillary services such as primary control capacity or large rotational inertia are also necessary to limit widely oscillating frequency deviations (grid oscillations) − properties that con ventional power plants with their turbo generators per se possess [3], but which must be provided separately as additional ancillary services in case of a largely renewable power supply system based on wind and solar energy ( photovoltaics). For grid stability, a secured capacity of power plants including grid reserve and standby capacities for backup purposes of currently about 84,000 MW is required in Germany at the time of annual peak load occurring between 17:30 and 19:30 during the period from November to February [4]. If electricity generation from wind power is further expanded in line with the objectives of the German federal government, the nominal capacity of the German wind fleet should exceed this secured capacity of power plants in several years’ time. From that point on, the dispatchable backup capacity to be maintained would have to be capped at about the level of this secured capacity of power plants which is sufficient for grid stability reasons. Solar energy (photovoltaics) as a further scalable and politically designated cornerstone of the German Energiewende is always 100 % unavailable during the times of year and day relevant for the annual peak load, as well as year-round at night, and therefore per se cannot make any contribution to the secured power plant capacity [4]. At year-end 2017, almost 1.7 million photovoltaic systems with around 42,400 MW nominal capacity (peak) were installed throughout Germany, supplying 40 TWh of electricity year-round [5]. By comparison, net power consumption amounted to around 540 TWh. This amount does not include the balance of electricity imports and electricity exports of almost 55 TWh [6], the auxiliary electric load of power plants of about 34 TWh [7] or grid losses at all voltage levels of around 26 TWh [8]. Photovoltaics therefore contributed around 7.4 % towards meeting the domestic net power requirement. Analyses of quarter-hourly time series of power output from wind turbines and photovoltaic systems in Germany over several years, scaled up to a nominal capacity of an average 330,000 MW to obtain 500 TWh electricity from these two intermittent renewable energy systems (iRES) per year, lead to a continued high need for dispatchable backup capacity of 89 % of the annual peak load [9],[10]. This average iRES nominal capacity includes 51 % of onshore wind power, 14 % of offshore wind power and 36 % of photovoltaic systems. The annual electrical energy amount of 500 TWh reflects Germany’s net electricity consumption plus grid losses minus predictable renewable energy systems (RES) such as run-of-river and pumped storage power plants, biomass and geothermal power plants. The saving in backup capacity of 11 % of the annual peak load under these conditions is essentially attributable to the regular night-time load reduction, as high backup capacities are seldom necessary during the daytime with electricity generation from solar power. From 2015 to 2017, an average 13 % of the annual hours in which iRES power outputs of less than 10 % of the iRES nominal capacity arose were accounted for by daytime hours between 08:00 and 16:00. As, at around 130 TWh, slightly more than one quarter of the iRES annual electric energy would occur at times of low demand (surplus) and therefore not be directly usable, the dispatchable backup system would have to provide the equivalent of these surpluses temporally delayed with a very low capacity factor of a maximum 20 %. From one year to the next, weather-related fluctuations of iRES annual electric energy of at least ±15 % would have to be factored in [9], with repercussions on the backup capacity in case of continued efforts to maintain the current high level of security of supply. According to annual outage and availability statistics compiled by the Forum Network Technology/Network Operation of VDE as German Association for Electrical, Part 1 * *) Part 2 to be published in atw 3 (2019) SERIAL | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER 79 Serial | Major Trends in Energy Policy and Nuclear Power Wind Energy in Germany and Europe ı Thomas Linnemann and Guido S. Vallana
Change language