TY - JOUR A1 - Ruhnau, Oliver A1 - Bannik, Sergej A1 - Otten, Sydney A1 - Praktiknjo, Aaron A1 - Robinius, Martin T1 - Direct or indirect electrification? A review of heat generation and road transport decarbonisation scenarios for Germany 2050 JF - Energy N2 - Energy scenarios provide guidance to energy policy, not least by presenting decarbonisation pathways for climate change mitigation. We review such scenarios for the example of Germany 2050, with a focus on the decarbonisation of heat generation and road transport. In this context, we characterize the role of renewable electricity and contrast two rivalling narratives: direct and indirect electrification. On the one hand, electricity directly provides heat and transport, using electric heat pumps, electric heaters, and battery electric vehicles. On the other hand, electricity, heat, and transport are indirectly linked, using gas heat pumps, gas heaters, fuel cell electric vehicles, and internal combustion engine vehicles, in combination with power-to-gas and power-to-liquid processes. To reach climate policy targets, our findings imply that energy stakeholders must (1) plan for the significant additional demand for renewable electricity for heat and road transport, (2) pave the way for system-friendly direct heat electrification, (3) be aware of technological uncertainties in the transport sector, (4) clarify the vision for decarbonisation, particularly for road transport, and (5) use holistic and more comparable scenario frameworks. Y1 - 2018 UR - https://nbn-resolving.org/urn:nbn:de:kobv:b1570-opus4-30602 U6 - https://doi.org/10.1016/j.energy.2018.10.114 SN - 0360-5442 VL - 166 IS - 1 SP - 989 EP - 999 ER - TY - JOUR A1 - Ruhnau, Oliver A1 - Hirth, Lion A1 - Praktiknjo, Aaron T1 - Time series of heat demand and heat pump efficiency for energy system modeling JF - Nature Scientific Data N2 - With electric heat pumps substituting for fossil-fueled alternatives, the temporal variability of their power consumption becomes increasingly important to the electricity system. To easily include this variability in energy system analyses, this paper introduces the “When2Heat” dataset comprising synthetic national time series of both the heat demand and the coefficient of performance (COP) of heat pumps. It covers 16 European countries, includes the years 2008 to 2018, and features an hourly resolution. Demand profiles for space and water heating are computed by combining gas standard load profiles with spatial temperature and wind speed reanalysis data as well as population geodata. COP time series for different heat sources – air, ground, and groundwater – and different heat sinks – floor heating, radiators, and water heating – are calculated based on COP and heating curves using reanalysis temperature data. The dataset, as well as the scripts and input parameters, are publicly available under an open source license on the Open Power System Data platform. Y1 - 2019 U6 - https://doi.org/10.1038/s41597-019-0199-y N1 - Open Access publication VL - 6 IS - 189 ER - TY - JOUR A1 - Ruhnau, Oliver A1 - Hirth, Lion A1 - Praktiknjo, Aaron T1 - Heating with Wind: Economics of heat pumps and variable renewables JF - Energy Economics N2 - With the growth of wind and solar energy in electricity supply, the electrification of space and water heating is becoming a promising decarbonization option. In turn, such electrification may help the power system integration of variable renewables, for two reasons: thermal storage could provide low-cost flexibility, and heat demand is seasonally correlated with wind power. However, temporal fluctuations in heat demand may also imply new challenges for the power system. This study assesses the economic characteristics of electric heat pumps and wind energy and studies their interaction on wholesale electricity markets. Using a numerical electricity market model, we estimate the economic value of wind energy and the economic cost of powering heat pumps. We find that, just as expanding wind energy depresses its €/MWhel value, adopting heat pumps increases their €/MWhel cost. This rise can be mitigated by synergistic effects with wind power, “system-friendly” heat pump technology, and thermal storage. Furthermore, heat pumps raise the wind market value, but this effect vanishes if accounting for the additional wind energy needed to serve the heat pump load. Thermal storage facilitates the system integration of wind power but competes with other flexibility options. For an efficient adoption of heat pumps and thermal storage, we argue that retail tariffs for heat pump customers should reflect their underlying economic cost. Y1 - 2020 U6 - https://doi.org/10.1016/j.eneco.2020.104967 VL - 92 ER - TY - JOUR A1 - Ruhnau, Oliver A1 - Bannik, Sergej A1 - Otten, Sydney A1 - Praktiknjo, Aaron A1 - Robinius, Martin T1 - Direct or indirect electrification? A review of heat generation and road transport decarbonisation scenarios for Germany 2050 JF - Energy N2 - Energy scenarios provide guidance to energy policy, not least by presenting decarbonisation pathways for climate change mitigation. We review such scenarios for the example of Germany 2050, with a focus on the decarbonisation of heat generation and road transport. In this context, we characterize the role of renewable electricity and contrast two rivalling narratives: direct and indirect electrification. On the one hand, electricity directly provides heat and transport, using electric heat pumps, electric heaters, and battery electric vehicles. On the other hand, electricity, heat, and transport are indirectly linked, using gas heat pumps, gas heaters, fuel cell electric vehicles, and internal combustion engine vehicles, in combination with power-to-gas and power-to-liquid processes. To reach climate policy targets, our findings imply that energy stakeholders must (1) plan for the significant additional demand for renewable electricity for heat and road transport, (2) pave the way for system-friendly direct heat electrification, (3) be aware of technological uncertainties in the transport sector, (4) clarify the vision for decarbonisation, particularly for road transport, and (5) use holistic and more comparable scenario frameworks. Y1 - 2018 UR - https://nbn-resolving.org/urn:nbn:de:kobv:b1570-opus4-31063 U6 - https://doi.org/10.1016/j.energy.2018.10.114 SN - 0360-5442 N1 - This is a post-peer-review, pre-copyedit version of an article published in Energy. The final authenticated version is available online at: https://doi.org/10.1016/j.energy.2018.10.114 VL - 166 IS - 1 SP - 989 EP - 999 ER - TY - CHAP A1 - Madlener, Reinhard A1 - Ruhnau, Oliver ED - Sioshansi, Fereidoon T1 - Variable renewables and demand flexibility: Day-ahead versus intraday valuation T2 - Variable Generation, Flexible Demand N2 - This chapter discusses trading in the day-ahead and intraday electricity markets, first in general and then from the perspectives of renewable power generators and demand response, respectively. This includes an overview of the relevant literature, a theoretical framework, and illustrative quantitative examples. The uncertainty of renewable electricity supply drives price volatility, especially in the intraday market, and leads to balancing cost for renewables, which can be optimized through forecasting and trading. The increased intraday price volatility can be exploited and moderated by demand response, which thereby helps to balance the uncertainty of renewables. KW - Centre for Sustainability Y1 - 2020 SN - 9780128238103 U6 - https://doi.org/10.1016/B978-0-12-823810-3.00005-4 SP - 309 EP - 327 PB - Academic Press ER - TY - RPRT A1 - Ruhnau, Oliver T1 - Market-based renewables: How flexible hydrogen electrolyzers stabilize wind and solar market values N2 - Wind and solar energy are often expected to fall victim to their own success: the higher their share in electricity production, the more their revenue on electricity markets (their “market value”) declines. While in conventional power systems, the market value may converge to zero, this study demonstrates that “green” hydrogen production, through adding electricity demand in low-price hours, can effectively and permanently halt the decline. With an analytical derivation, a Monte Carlo simulation, and a numerical electricity market model, I find that – due to flexible hydrogen production – market values in 2050 likely converge above €19 ± 9 per MWh for solar energy and above €27 ± 8 per MWh for wind energy. This is in the range of the projected levelized costs of renewables and has profound implications. Market-based renewables may hence be within reach. KW - Renewable energy KW - Hydrogen electrolysis KW - Electricity market KW - Electricity economics KW - Integrated energy system Y1 - 2020 UR - https://www.econstor.eu/handle/10419/227075 ER - TY - JOUR A1 - Pöstges, Arne A1 - Bucksteeg, Michael A1 - Ruhnau, Oliver A1 - Böttger, Diana A1 - Haller, Markus A1 - Künle, Eglantine A1 - Ritter, David A1 - Schmitz, Richard A1 - Wiedmann, Michael T1 - Phasing out coal - An impact analysis comparing five large-scale electricity market models N2 - Climate target achievement has a crucial influence on the modelling and the decision processes in the energy sector. It induced the development of several policy instruments to mitigate greenhouse gas emissions, including administrative and market-based mechanisms for phasing out coal-fired generation technologies. In order to analyse such instruments, electricity market and energy system models are widely used. However, results and corresponding recommendations largely depend on the formulation of the respective model. This motivates a systematic comparison of five large-scale electricity market models which are applied to European scenarios considering the period until 2030. An evolved diff-in-diff approach is proposed to analyse the effects of two coal phase-out strategies. This contribution expands on that of earlier studies and provides some more general takeaways for both modellers and decision-makers. For instance, the evolved diff-in-diff analysis shows the influence of the reference scenario when evaluating a policy instrument. Furthermore, the importance of technical aspects such as constraints for combined heat and power plants are discussed and implications regarding three dimensions (economic, environmental, and security of supply) are presented. KW - model comparison, coal phase-out, electricity market model, energy policy KW - Centre for Sustainability Y1 - 2022 U6 - https://doi.org/https://www.econstor.eu/handle/10419/234102 PB - Applied Energy Vol. 319 ER - TY - JOUR A1 - Ruhnau, Oliver A1 - Bucksteeg, Michael A1 - Ritter, David A1 - Schmitz, Richard A1 - Böttger, Diana A1 - Koch, Matthias A1 - Pöstges, Arne A1 - Wiedmann, Michael A1 - Hirth, Lion T1 - Why electricity market models yield different results: Carbon pricing in a model-comparison experiment N2 - The European electricity industry, the dominant sector of the world’s largest cap-and-trade scheme, is one of the most-studied examples of carbon pricing. In particular, numerical models are often used to study the uncertain future development of carbon prices and emissions. While parameter uncertainty is often addressed through sensitivity analyses, the potential uncertainty of the models themselves remains unclear from existing single-model studies. Here, we investigate such model-related uncertainty by running a structured model comparison experiment, in which we exposed five numerical power sector models to aligned input parameters—finding stark model differences. At a carbon price of 27 EUR/t in 2030, the models estimate that European power sector emissions will decrease by 36–57% when compared to 2016. Most of this variation can be explained by the extent to which models consider the market-driven decommissioning of coal- and lignite-fired power plants. Higher carbon prices of 57 and 87 EUR/t yield a stronger decrease in carbon emissions, by 45–75% and 52–80%, respectively. The lower end of these ranges can be attributed to the short-term fuel switch captured by dispatch-only models. The higher reductions correspond to models that additionally consider market-based investment in renewables. By further studying cross-model variation in the remaining emissions at high carbon prices, we identify the representation of combined heat and power as another crucial driver of differences across model results. KW - Carbon pricing, EU Emission Trading System (EU ETS), electricity decarbonization, power sector, renewable energy, fuel switch, combined heat and power, electricity market modeling, model comparison, model-related uncertainty KW - Centre for Sustainability Y1 - 2022 U6 - https://doi.org/10.1016/j.rser.2021.111701 N1 - Preprint version available here: https://www.econstor.eu/handle/10419/234468 ER - TY - JOUR A1 - Cloete, Schalk A1 - Ruhnau, Oliver A1 - Cloete, Jan Hendrik A1 - Hirth, Lion T1 - Blue hydrogen and industrial base products: The future of fossil fuel exporters in a net-zero world N2 - Is there a place for today’s fossil fuel exporters in a low-carbon future? This study explores trade channels between energy exporters and importers using a novel electricity-hydrogen-steel energy systems model calibrated to Norway, a major natural gas producer, and Germany, a major energy consumer. Under tight emission constraints, Norway can supply Germany with electricity, (blue) hydrogen, or natural gas with re-import of captured CO2. Alternatively, it can use hydrogen to produce steel through direct reduction and supply it to the world market, an export route not available to other energy carriers due to high transport costs. Although results show that natural gas imports with CO2 capture in Germany is the least-cost solution, avoiding local CO2 handling via imports of blue hydrogen (direct or embodied in steel) involves only moderately higher costs. A robust hydrogen demand would allow Norway to profitably export all its natural gas production as blue hydrogen. However, diversification into local steel production, as one example of easy-to-export industrial base products, offers an effective hedge against the possibility of lower European blue hydrogen demand. Thus, it is recommended that hydrocarbon exporters like Norway consider a strategic energy export transition to a diversified mix of blue hydrogen and climate-neutral industrial base products. KW - Hydrogen economy, Energy-intensive industry, Decarbonization, CO2 capture and storage, Variable renewable energy KW - Centre for Sustainability Y1 - 2022 U6 - https://doi.org/10.1016/j.jclepro.2022.132347 PB - Journal of Cleaner Production Vo. 363 ER - TY - JOUR A1 - Eicke, Anselm A1 - Ruhnau, Oliver A1 - Hirth, Lion T1 - Electricity balancing as a market equilibrium: An instrument-based estimation of supply and demand for imbalance energy N2 - Frequency stability requires equalizing supply and demand for electricity at short time scales. Such electricity balancing is often understood as a sequential process in which random shocks, such as weather events, cause imbalances that system operators close by activating balancing reserves. By contrast, we study electricity balancing as a market where the equilibrium price (imbalance price) and quantity (system imbalance) are determined by supply and demand. System operators supply imbalance energy by activating reserves; market parties that, deliberately or not, deviate from schedules create a demand for imbalance energy. The incentives for deliberate strategic deviations emerge from wholesale market prices and the imbalance price. We empirically estimate the demand curve of imbalance energy, which describes how sensitive market parties are to imbalance prices. To overcome the classical endogeneity problem of price and quantity, we deploy instruments derived from a novel theoretical framework. Using data from Germany, we find a decline in the demand for imbalance energy by 2.2 MW for each increase in the imbalance price by EUR 1 per MWh. This significant price response is remarkable because the German regulator prohibits strategic deviations. We also estimate cross-market equilibriums between intraday and imbalance markets, finding that a shock to the imbalance price triggers a subsequent adjustment of the intraday price. KW - Electricity balancing, Intraday electricity market, Imbalance energy KW - Centre for Sustainability Y1 - 2021 U6 - https://doi.org/10.1016/j.eneco.2021.105455 ER - TY - JOUR A1 - Cloete, Schalk A1 - Ruhnau, Oliver A1 - Hirth, Lion T1 - On capital utilization in the hydrogen economy: The quest to minimize idle capacity in renewables-rich energy systems JF - International Journal of Hydrogen Energy N2 - The hydrogen economy is currently experiencing a surge in attention, partly due to the possibility of absorbing wind and solar energy production peaks through electrolysis. A fundamental challenge with this approach is low utilization rates of various parts of the integrated electricity-hydrogen system. To assess the importance of capacity utilization, this paper introduces a novel stylized numerical energy system model incorporating the major elements of electricity and hydrogen generation, transmission and storage, including both "green" hydrogen from electrolysis and "blue" hydrogen from natural gas reforming with CO2 capture and storage (CCS). Balancing renewables with electrolysis results in low utilization of electrolyzers, hydrogen pipelines and storage infrastructure, or electricity transmission networks, depending on whether electrolyzers are co-located with wind farms or demand centers. Blue hydrogen scenarios face similar constraints. High renewable shares impose low utilization rates of CO2 capture, transport and storage infrastructure for conventional CCS, and of hydrogen transmission and storage infrastructure for a novel process (gas switching reforming) that enables flexible power and hydrogen production. In conclusion, both green and blue hydrogen can facilitate the integration of wind and solar energy, but the cost related to low capacity utilization erodes much of the expected economic benefit. KW - Hydrogen economy KW - Energy system model KW - Decarbonization KW - CO2 capture and storage KW - Variable renewable energy KW - Centre for Sustainability Y1 - 2021 U6 - https://doi.org/10.1016/j.ijhydene.2020.09.197 VL - 46 IS - 1 SP - 169 EP - 188 ER - TY - JOUR A1 - Ruhnau, Oliver A1 - Hennig, Patrick A1 - Madlener, Reinhard T1 - Economic implications of forecasting electricity generation from variable renewable energy sources JF - Renewable Energy N2 - Short-term forecasting of electricity generation from variable renewable energy sources is not an end in itself but should provide some net benefit to its user. In the case of electricity trading, which is in the focus of this paper, the benefit can be quantified in terms of an improved economic outcome. Although some effort has been made to evaluate and to improve the profitability of electricity forecasts, the understanding of the underlying effects has remained incomplete so far. In this paper, we develop a more comprehensive theoretical framework of the connection between the statistical and the economic properties of day-ahead electricity forecasts. We find that, apart from the accuracy and the bias, which have already been extensively researched, the correlation between the forecast errors and the market price spread determines the economic implications - a phenomenon which we refer to as ‘correlation effect’. Our analysis is completed by a case study on solar electricity forecasting in Germany which illustrates the relevance and the limits of both our theoretical framework and the correlation effect. KW - Forecasting evaluation KW - Renewable energy KW - Electricity markets KW - Balancing costs KW - Artificial neural network Y1 - 2020 U6 - https://doi.org/10.1016/j.renene.2020.06.110 SN - 0960-1481 IS - 161 SP - 1318 EP - 1327 ER - TY - JOUR A1 - Bucksteeg, Michael A1 - Wiedmann, Michael A1 - Pöstges, Arne A1 - Haller, Markus A1 - Böttger, Diana A1 - Ruhnau, Oliver A1 - Schmitz, Richard T1 - The transformation of integrated electricity and heat systems—Assessing mid-term policies using a model comparison approach JF - Renewable and Sustainable Energy Reviews N2 - The development of European power markets is highly influenced by integrated electricity and heat systems. Therefore, decarbonization policies for the electricity and heat sectors, as well as numerical models that are used to guide such policies, should consider cross-sectoral interdependencies and need evaluation. Many model-based policy assessments evaluate potential benefits of combined heat and power. However, the extent of benefits, such as emissions reductions, found in existing studies is subject to considerable variations. While scenarios and model inputs may partly explain such variations, differences in results may also be related to the model formulation itself. Against this background, this study is the first to compare electricity market models in the context of potential benefits of integrated electricity and heat systems in decarbonization. Five large-scale market models covering electricity and heat supply were utilized to study the interactions between a rather simple coal replacement scenario and a more ambitious policy that supports decarbonization through power-to-heat. With a focus on flexibility provision, emissions reduction, and economic efficiency, although the models agree on the qualitative effects, there are considerable quantitative differences. For example, the estimated reductions in overall CO2 emissions range between 0.2 and 9.0 MtCO2/a for a coal replacement scenario and between 0.2 and 25.0 MtCO2/a for a power-to-heat scenario. Model differences can be attributed mainly to the level of detail of combined heat and power modeling and the endogeneity of generation investments. Based on a detailed comparison of the modeling results, implications for modeling choices and political decisions are discussed. KW - Combined heat and power KW - power-to-heat KW - coal phase-out KW - renewable energy KW - renewable energyenergy system transformation Y1 - 2022 UR - https://www.sciencedirect.com/science/article/pii/S1364032122001915?via%3Dihub U6 - https://doi.org/10.1016/j.rser.2022.112270 VL - 160 ER - TY - RPRT A1 - Tiedemann, Silvana A1 - Sanchez Canales, Jorge A1 - Schur, Felix A1 - Sgarlato, Raffaele A1 - Hirth, Lion A1 - Ruhnau, Oliver A1 - Peters, Jonas T1 - Identifying Elasticities in Autocorrelated Time Series Using Causal Graphs N2 - The price elasticity of demand can be estimated from observational data using instrumental variables (IV). However, naive IV estimators may be inconsistent in settings with autocorrelated time series. We argue that causal time graphs can simplify IV identification and help select consistent estimators. To do so, we propose to first model the equilibrium condition by an unobserved confounder, deriving a directed acyclic graph (DAG) while maintaining the assumption of a simultaneous determination of prices and quantities. We then exploit recent advances in graphical inference to derive valid IV estimators, including estimators that achieve consistency by simultaneously estimating nuisance effects. We further argue that observing significant differences between the estimates of presumably valid estimators can help to reject false model assumptions, thereby improving our understanding of underlying economic dynamics. We apply this approach to the German electricity market, estimating the price elasticity of demand on simulated and real-world data. The findings underscore the importance of accounting for structural autocorrelation in IV-based analysis. Y1 - 2024 U6 - https://doi.org/10.48550/arXiv.2409.15530 PB - arXiv ER - TY - RPRT A1 - Bucksteeg, Michael A1 - Wiedmann, Michael A1 - Pöstges, Arne A1 - Haller, Markus A1 - Böttger, Diana A1 - Ruhnau, Oliver A1 - Schmitz, Richard T1 - The transformation of integrated electricity and heat systems—Assessing mid-term policies using a model comparison approach N2 - The development of European power markets is highly influenced by integrated electricity and heat systems. Therefore, decarbonization policies for the electricity and heat sectors, as well as numerical models that are used to guide such policies, should consider cross-sectoral interdependencies. However, although many model-based policy assessments for the highly interconnected European electricity system exist, international studies that consider interactions with the heat sector are rare. In this contribution, we systematically study the potential benefits of integrated heat and power systems by conducting a model comparison experiment. Five large-scale market models covering electricity and heat supply were utilized to study the interactions between a rather simple coal replacement scenario and a more ambitious policy that supports decarbonization through power-to-heat. With a focus on flexibility provision, emissions reduction, and economic efficiency, although the models agree on the qualitative effects, there are considerable quantitative differences. For example, the estimated reductions in overall CO2 emissions range between 0.2 and 9.0 MtCO2/a for a coal replacement scenario and between 0.2 and 25.0 MtCO2/a for a power-to-heat scenario. Model differences can be attributed mainly to the level of detail of CHP modeling and the endogeneity of generation investments. Based on a detailed comparison of the modeling results, implications for modeling choices and political decisions are discussed. KW - Combined heat and power power-to-heat coal phase-out renewable energy energy system transformation electricity market modeling model comparison KW - Centre for Sustainability Y1 - 2021 UR - https://www.econstor.eu/handle/10419/242981 ER - TY - JOUR A1 - Hirth, Lion A1 - Khanna, Tarun M. A1 - Ruhnau, Oliver T1 - How aggregate electricity demand responds to hourly wholesale price fluctuations JF - Energy Economics N2 - Electricity needs to be consumed at the very moment of production, leading wholesale prices to fluctuate widely at (sub-)hourly time scales. This article investigates the response of aggregate electricity demand to such price variations. Using wind energy as an instrument, we estimate a significant and robust short-term price elasticity of about −0.05 in Germany and attribute this to industrial consumers. As the share of consumption that is exposed to real-time prices (currently less than 25%) expands, we expect the aggregated price elasticity to grow. Y1 - 2024 U6 - https://doi.org/10.1016/j.eneco.2024.107652 SN - 0140-9883 VL - 135 PB - Elsevier BV ER - TY - JOUR A1 - Ruhnau, Oliver A1 - Stiewe, Clemens A1 - Muessel, Jarusch A1 - Hirth, Lion T1 - Natural gas savings in Germany during the 2022 energy crisis JF - Nature Energy N2 - Russia curbed its natural gas supply to Europe in 2021 and 2022, creating a grave energy crisis. This paper empirically estimates the crisis response of natural gas consumers in Germany—for decades the largest export market for Russian gas. Using a multiple regression model, we estimate the response of small consumers, industry, and power stations separately, controlling for the non-linear temperature-heating relationship, seasonality, and trends. We find significant and substantial gas savings for all consumer groups, but with differences in timing and size. For instance, industry started reducing consumption as early as September 2021, while small consumers saved substantially only since March 2022. Across all sectors, gas consumption during the second half of 2022 was 23% below the temperature-adjusted baseline. We discuss the drivers behind these savings and draw conclusions on their role in coping with the crisis. Y1 - 2023 UR - https://nbn-resolving.org/urn:nbn:de:kobv:b1570-opus4-49445 U6 - https://doi.org/10.48462/opus4-4944 N1 - This is a post-peer-review, pre-copyedit version of an article published in Nature Energy. The final authenticated version is available online at: https://doi.org/10.1038/s41560-023-01260-5 ER - TY - RPRT A1 - Hirth, Lion A1 - Khanna, Tarun A1 - Ruhnau, Oliver T1 - The (very) short-term price elasticity of German electricity demand N2 - Electricity is a peculiar economic good, the most important reason being that it needs to be supplied at the very moment of consumption. As a result, wholesale electricity prices fluctuate widely at hourly or sub-hourly time scales, regularly reaching multiples of their average, and even turn negative. This paper examines whether the demand for electricity responds to such price variations in the very short term. To solve the classical identification problem when estimating a demand curve, we use weather-driven wind energy generation as an instrument. Our robustness checks confirm that wind energy is indeed a strong and valid instrument. Using data from Germany, we estimate that a 1 €/MWh increase in the wholesale electricity price causes the aggregate electricity demand to decline by 67–80 MW or 0.12–0.14%, contradicting the conventional wisdom that electricity demand is highly price-inelastic. These estimates are statistically significant and robust across model specifications, estimators, and sensitivity analyses. At average price and demand, our estimates correspond to a price elasticity of demand of about –0.05. Comparing situations with high and low wind energy (5–95th percentile), we estimate that prices vary by 26 €/MWh, and the corresponding demand response to wholesale electricity prices is about 2 GW, or 2.6% of peak load. Our analysis suggests that the demand response in Germany can be attributed primarily to industrial consumers. KW - Electricity markets KW - Price elasticity KW - Demand response KW - Instrumental variables KW - Centre for Sustainability Y1 - 2022 UR - https://www.econstor.eu/handle/10419/249570 ER - TY - JOUR A1 - Ruhnau, Oliver A1 - Eicke, Anselm A1 - Sgarlato, Raffaele A1 - Tröndle, Tim A1 - Hirth, Lion T1 - Cost-Potential Curves of Onshore Wind Energy: the Role of Disamenity Costs JF - Environmental and Resource Economics N2 - Numerical optimization models are used to develop scenarios of the future energy system. Usually, they optimize the energy mix subject to engineering costs such as equipment and fuel. For onshore wind energy, some of these models use cost-potential curves that indicate how much electricity can be generated at what cost. These curves are upward sloping mainly because windy sites are occupied first and further expanding wind energy means deploying less favorable resources. Meanwhile, real-world wind energy expansion is curbed by local resistance, regulatory constraints, and legal challenges. This presumably reflects the perceived adverse effect that onshore wind energy has on the local human population, as well as other negative external effects. These disamenity costs are at the core of this paper. We provide a comprehensive and consistent set of cost-potential curves of wind energy for all European countries that include disamenity costs, and which can be used in energy system modeling. We combine existing valuation of disamenity costs from the literature that describe the costs as a function of the distance between turbine and households with gridded population data, granular geospatial data of wind speeds, and additional land-use constraints to calculate such curves. We find that disamenity costs are not a game changer: for most countries and assumptions, the marginal levelized cost of onshore wind energy increase by 0.2–12.5 €/MWh. KW - Centre for Sustainability Y1 - 2022 U6 - https://doi.org/10.1007/s10640-022-00746-2 ER - TY - RPRT A1 - Stiewe, Clemens A1 - Ruhnau, Oliver A1 - Hirth, Lion T1 - European industry responds to high energy prices: The case of German ammonia production. N2 - Since September 2021, European natural gas prices are at record-high levels. On average, they have been six to seven times higher than pre-pandemic price levels. While the post-pandemic recovery of global natural gas demand has driven up prices around the world, the most important drivers for European gas prices were Russia's less-than-usual supply since mid-2021 and its invasion of Ukraine in February 2022. Western efforts to abandon Russian gas imports altogether mean that high natural gas prices are likely to stay for longer. While high gas prices may be the new normal, there is uncertainty about the economic reaction to this shock. How do energy-intensive industries react? Do global value chains collapse if intermediate goods produced in Europe become uneconomic because of high energy prices? Our preliminary analysis shows that industry response to has in fact been visible from the very onset of the energy crisis. A closer look at German fertilizer production, which heavily relies on natural gas as fuel and feedstock to produce ammonia as an intermediate product, reveals that increased ammonia imports have allowed domestic fertilizer production to remain remarkably stable. KW - Energy Demand KW - Demand response KW - European energy crisis KW - Natural gas KW - Centre for Sustainability Y1 - 2022 UR - https://www.econstor.eu/handle/10419/253251 ER -