@article{RuhnauBucksteegRitteretal., author = {Ruhnau, Oliver and Bucksteeg, Michael and Ritter, David and Schmitz, Richard and B{\"o}ttger, Diana and Koch, Matthias and P{\"o}stges, Arne and Wiedmann, Michael and Hirth, Lion}, title = {Why electricity market models yield different results: Carbon pricing in a model-comparison experiment}, doi = {10.1016/j.rser.2021.111701}, abstract = {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.}, language = {en} } @article{CloeteRuhnauCloeteetal., author = {Cloete, Schalk and Ruhnau, Oliver and Cloete, Jan Hendrik and Hirth, Lion}, title = {Blue hydrogen and industrial base products: The future of fossil fuel exporters in a net-zero world}, publisher = {Journal of Cleaner Production Vo. 363}, doi = {10.1016/j.jclepro.2022.132347}, abstract = {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.}, language = {en} } @techreport{HirthKhannaRuhnau, type = {Working Paper}, author = {Hirth, Lion and Khanna, Tarun and Ruhnau, Oliver}, title = {The (very) short-term price elasticity of German electricity demand}, abstract = {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.}, language = {en} } @techreport{RuhnauStieweMuesseletal., type = {Working Paper}, author = {Ruhnau, Oliver and Stiewe, Clemens and Muessel, Jarusch and Hirth, Lion}, title = {Gas demand in times of crisis. The response of German households and industry to the 2021/22 energy crisis}, pages = {8}, abstract = {Europe is in the midst of the most severe energy crisis in a generation, at the core of which is the continuously plummeting supply of Russian natural gas. With alternative supply options being limited, natural gas prices have surged. This paper empirically estimates the response of natural gas demand to the price increase, using data from Germany—the so far largest consumer of Russian natural gas. We identify the crisis response of small and large consumers separately, controlling for temperature, gas-fired power generation, and economic activity. For small consumers, including mostly households, we find a substantial demand reduction of 6\% from March onwards—most likely due to political and ethical considerations after the start of Russia's invasion of Ukraine. For industrial consumers, demand reductions started much earlier in August 2021, when wholesale prices for natural gas started to surge, with an average reduction of 11\%. We conclude that voluntary industrial demand response has played a significant role in coping with the energy crisis so far.}, language = {en} } @article{RuhnauEickeSgarlatoetal., author = {Ruhnau, Oliver and Eicke, Anselm and Sgarlato, Raffaele and Tr{\"o}ndle, Tim and Hirth, Lion}, title = {Cost-Potential Curves of Onshore Wind Energy: the Role of Disamenity Costs}, series = {Environmental and Resource Economics}, journal = {Environmental and Resource Economics}, doi = {10.1007/s10640-022-00746-2}, abstract = {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.}, language = {en} } @techreport{StieweRuhnauHirth, type = {Working Paper}, author = {Stiewe, Clemens and Ruhnau, Oliver and Hirth, Lion}, title = {European industry responds to high energy prices: The case of German ammonia production.}, pages = {6}, abstract = {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.}, language = {en} }