@article{LehmannCreutzigEhlersetal., author = {Lehmann, Paul and Creutzig, Felix and Ehlers, Melf-Hinrich and Friedrichsen, Nele and Heuson, Clemens and Hirth, Lion and Pietzcker, Robert}, title = {Carbon lock-out: Advancing renewable energy policy in Europe}, series = {Energies}, volume = {5}, journal = {Energies}, number = {2}, issn = {1996-1073}, doi = {10.3390/en5020323}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-22972}, pages = {323 -- 354}, abstract = {As part of its climate strategy, the EU aims at increasing the share of electricity from renewable energy sources (RES-E) in overall electricity generation. Attaining this target poses a considerable challenge as the electricity sector is "locked" into a carbon-intensive system, which hampers the adoption of RES-E technologies. Electricity generation, transmission and distribution grids as well as storage and demand response are subject to important path dependences, which put existing, non-renewable energy sources at an advantage. This paper examines how an EU framework for RES-E support policies should be designed to facilitate a carbon lock-out. For this purpose, we specify the major technological, economic and institutional barriers to RES-E. For each of the barriers, a policy review is carried out which assesses the performance of existing policy instruments and identifies needs for reform. The review reveals several shortcomings: while policies targeting generation are widely in place, measures to address barriers associated with electricity grids, storage and demand are still in their infancy and have to be extended. Moreover, the implementation of policies has been fragmented across EU Member States. In this respect, national policies should be embedded into an integrated EU-wide planning of the RES-E system with overarching energy scenarios and partially harmonized policy rules.}, language = {en} } @article{UeckerdtHirthLudereretal., author = {Ueckerdt, Falko and Hirth, Lion and Luderer, Gunnar and Edenhofer, Ottmar}, title = {System LCOE: What are the costs of variable renewables?}, series = {Energy}, volume = {63}, journal = {Energy}, publisher = {Elsevier Ltd}, issn = {0360-5442}, doi = {10.1016/j.energy.2013.10.072}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-22942}, pages = {61 -- 75}, abstract = {Levelized costs of electricity (LCOE) are a common metric for comparing power generating technologies. However, there is criticism particularly towards evaluating variable renewables like wind and solar PV power based on LCOE because it ignores variability and integration costs. We propose a new metric System LCOE that accounts for integration and generation costs. For this purpose we develop a new mathematical definition of integration costs that directly relates to economic theory. As a result System LCOE allow the economic comparison of generating technologies and deriving optimal quantities in particular for VRE. To demonstrate the new concept we quantify System LCOE from a simple power system model and literature values. We find that at high wind shares integration costs can be in the same range as generation costs of wind power and conventional plants in particular due to a cost component "profile costs" captured by the new definition. Integration costs increase with growing wind shares and might become an economic barrier to deploying VRE at high shares. System LCOE help understanding and resolving the challenge of integrating VRE and can guide research and policy makers in realizing a cost-efficient transformation towards an energy system with potentially high shares of variable renewables.}, language = {en} } @article{EdenhoferHirthKnopfetal., author = {Edenhofer, Ottmar and Hirth, Lion and Knopf, Brigitte and Pahle, Michael and Schl{\"o}mer, Steffen and Schmid, Eva and Ueckerdt, Falko}, title = {On the Economics of Renewable Energy Sources}, series = {Energy Economics}, volume = {40}, journal = {Energy Economics}, number = {S1}, issn = {0140-9883}, doi = {10.1016/j.eneco.2013.09.015}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-22965}, pages = {S12 -- S23}, abstract = {With the global expansion of renewable energy (RE) technologies, the provision of optimal RE policy packages becomes an important task. We review pivotal aspects regarding the economics of renewables that are relevant to the design of an optimal RE policy, many of which are to date unresolved. We do so from three interrelated perspectives that a meaningful public policy framework for inquiry must take into account. First, we explore different social objectives justifying the deployment of RE technologies, including potential co-benefits of RE deployment, and review modelbased estimates of the economic potential of RE technologies, i.e. their socially optimal deployment level. Second, we address pivotal market failures that arise in the course of implementing the economic potential of RE sources in decentralized markets. Third, we discuss multiple policy instruments curing these market failures. Our framework reveals the requirements for an assessment of the relevant options for real-world decision makers in the field of RE policies. This review makes it clear that there are remaining white areas on the knowledge map concerning consistent and socially optimal RE policies.}, language = {en} } @article{HirthUeckerdt, author = {Hirth, Lion and Ueckerdt, Falko}, title = {Redistribution Effects of Energy and Climate Policy: The Electricity Market}, series = {Energy Policy}, volume = {62}, journal = {Energy Policy}, publisher = {Elsevier Ltd}, issn = {0301-4215}, doi = {10.1016/j.enpol.2013.07.055}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-22886}, pages = {934 -- 947}, abstract = {Energy and climate policies are usually seen as measures to internalize externalities. However, as a side effect, the introduction of these policies redistributes wealth between consumers and producers, and within these groups. While redistribution is seldom the focus of the academic literature in energy economics, it plays a central role in public debates and policy decisions. This paper compares the distributional effects of two major electricity policies: support schemes for renewable energy sources, and CO2 pricing. We find that the redistribution effects of both policies are large, and they work in opposed directions. While renewables support transfers wealth from producers to consumers, carbon pricing does the opposite. More specifically, we show that moderate amounts of wind subsidies can increase consumer surplus, even if consumers bear the subsidy costs. CO2 pricing, in contrast, increases aggregated producer surplus, even without free allocation of emission allowances; however, not all types of producers benefit. These findings are derived from an analytical model of electricity markets, and a calibrated numerical model of Northwestern Europe. Our findings imply that if policy makers want to avoid large redistribution they might prefer a mix of policies, even if CO2 pricing alone is the first-best climate policy in terms of allocative efficiency.}, language = {en} } @article{Hirth, author = {Hirth, Lion}, title = {The market value of variable renewables: The effect of solar wind power variability on their relative price}, series = {Energy Economics}, volume = {38}, journal = {Energy Economics}, publisher = {Elsevier B.V.}, issn = {0140-9883}, doi = {10.1016/j.eneco.2013.02.004}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-22900}, pages = {218 -- 236}, abstract = {This paper provides a comprehensive discussion of the market value of variable renewable energy (VRE). The inherent variability of wind speeds and solar radiation affects the price that VRE generators receive on the market (market value). During windy and sunny times the additional electricity supply reduces the prices. Because the drop is larger with more installed capacity, the market value of VRE falls with higher penetration rate. This study aims to develop a better understanding on how the market value with penetration, and how policies and prices affect the market value. Quantitative evidence is derived from a review of published studies, regression analysis of market data, and the calibrated model of the European electricity market EMMA. We find the value of wind power to fall from 110\% of the average power price to 50-80\% as wind penetration increases from zero to 30\% of total electricity consumption. For solar power, similarly low value levels are reached already at 15\% penetration. Hence, competitive large-scale renewable deployment will be more difficult to accomplish than as many anticipate.}, language = {en} } @article{HirthZiegenhagen, author = {Hirth, Lion and Ziegenhagen, Inka}, title = {Wind, Sonne, und Regelleistung}, series = {Energiewirtschaftliche Tagesfragen : et}, journal = {Energiewirtschaftliche Tagesfragen : et}, number = {10}, edition = {13}, publisher = {EW Medien und Kongresse GmbH}, address = {Frankfurt am Main}, issn = {0013-743X - 0720-6240}, pages = {59}, language = {de} } @article{Hirth, author = {Hirth, Lion}, title = {The Optimal Share of Variable Renewables: How the Variability of Wind and Solar Power affects their Welfare-optimal Deployment}, series = {The Energy Journal}, volume = {36}, journal = {The Energy Journal}, number = {1}, issn = {1944-9089}, doi = {10.5547/01956574.36.1.6}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-22832}, pages = {127 -- 162}, abstract = {This paper estimates the welfare-optimal market share of wind and solar power, explicitly taking into account their output variability. We present a theoretical valuation framework that consistently accounts for the impact of fluctuations over time, forecast errors, and the location of generators in the power grid on the marginal value of electricity from renewables. Then the optimal share of wind and solar power in Northwestern Europe's generation mix is estimated from a calibrated numerical model. We find the optimal long-term wind share to be 20\%, three times more than today; however, we also find significant parameter uncertainty. Variability significantly impacts results: if winds were constant, the optimal share would be 60\%. In addition, the effect of technological change, price shocks, and policies on the optimal share is assessed. We present and explain several surprising findings, including a negative impact of CO2 prices on optimal wind deployment.}, language = {en} } @article{Hirth, author = {Hirth, Lion}, title = {The Market Value of Solar Power: Is Photovoltaics Cost-Competitive?}, series = {IET Renewable Power Generation}, volume = {9}, journal = {IET Renewable Power Generation}, number = {1}, issn = {1752-1416}, doi = {10.1049/iet-rpg.2014.0101}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-22844}, pages = {37 -- 45}, abstract = {This paper reviews the economics of solar power as a source of grid-connected electricity generation. It is widely acknowledged that costs of solar power have declined, but there is disagreement how its economic value should be calculated. 'Grid parity', comparing generation costs to the retail price, is an often used yet flawed metric for economic assessment, as it ignores grid fees, levies, and taxes. It also fails to account for the fact that electricity is more valuable at some points in time and at some locations than that at others. A better yardstick than the retail price is solar power's 'market value'. This paper explains why, and provides empirical estimates of the solar market value from a literature review, German spot market analysis, and the numerical electricity market model EMMA. At low penetration rates (<2-5\%) solar power's market value turns out to be higher than the average wholesale electricity price - mainly, because the sun tends to shine when electricity demand is high. With increasing penetration, the market value declines - the solar premium turns into a solar penalty. In Germany, the value of solar power has fallen from 133\% of the average electricity price to 98\% as solar penetration increased from zero to 4.7\%. This value drop is steeper than wind power's value drop, because solar generation is more concentrated in time. As a consequence, large-scale solar deployment without subsidies will be more difficult to accomplish than many observers have anticipated.}, language = {en} } @article{HirthZiegenhagen, author = {Hirth, Lion and Ziegenhagen, Inka}, title = {Balancing power and variable renewables: Three links}, series = {Renewable and Sustainable Energy Reviews}, volume = {50}, journal = {Renewable and Sustainable Energy Reviews}, publisher = {Elsevier Ltd}, issn = {1364-0321}, doi = {10.1016/j.rser.2015.04.180}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-22856}, pages = {1035 -- 1051}, abstract = {Balancing power is used to quickly restore the supply-demand balance in power systems. The need for this tends to be increased by the use of variable renewable energy sources (VRE) such as wind and solar power. This paper reviews three channels through which VRE and balancing systems interact: the impact of VRE forecast errors on balancing reserve requirements; the supply of balancing services by VRE generators; and the incentives to improve forecasting provided by imbalance charges. The paper reviews the literature, provides stylized facts from German market data, and suggests policy options. Surprisingly, while German wind and solar capacity has tripled since 2008, balancing reserves have been reduced by 15\%, and costs by 50\%.}, language = {en} } @article{HirthUeckerdtEdenhofer, author = {Hirth, Lion and Ueckerdt, Falko and Edenhofer, Ottmar}, title = {Integration Costs Revisited - An economic framework for wind and solar variability}, series = {Renewable Energy}, volume = {74}, journal = {Renewable Energy}, publisher = {Elsevier Ltd}, issn = {0960-1481}, doi = {10.1016/j.renene.2014.08.065}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-22878}, pages = {925 -- 939}, abstract = {The integration of wind and solar generators into power systems causes "integration costs" - for grids, balancing services, more flexible operation of thermal plants, and reduced utilization of the capital stock embodied in infrastructure, among other things. This paper proposes a framework to analyze and quantify these costs. We propose a definition of integration costs based on the marginal economic value of electricity, or market value - as such a definition can be more easily used in economic cost-benefit assessment than previous approaches. We suggest decomposing integration costs intro three components, according to the principal characteristics of wind and solar power: temporal variability, uncertainty, and location-constraints. Quantitative estimates of these components are extracted from a review of 100 + published studies. At high penetration rates, say a wind market share of 30-40\%, integration costs are found to be 25-35 €/MWh, i.e. up to 50\% of generation costs. While these estimates are system-specific and subject to significant uncertainty, integration costs are certainly too large to be ignored in high-penetration assessments (but might be ignored at low penetration). The largest single factor is reduced utilization of capital embodied in thermal plants, a cost component that has not been accounted for in most previous integration studies.}, language = {en} } @article{Hirth, author = {Hirth, Lion}, title = {Die {\"O}konomie der Energiewende}, series = {Phasenpr{\"u}fer}, journal = {Phasenpr{\"u}fer}, language = {de} } @article{Hirth, author = {Hirth, Lion}, title = {Das Ende der Grundlast}, series = {Phasenpr{\"u}fer}, journal = {Phasenpr{\"u}fer}, language = {de} } @article{WeberHirth, author = {Weber, Christoph and Hirth, Lion}, title = {Jenseits des S{\"u}ndenbocks Erneuerbare: Was hat den Verfall des B{\"o}rsenstrompreises wirklich verursacht?}, series = {Phasenpr{\"u}fer}, journal = {Phasenpr{\"u}fer}, language = {de} } @article{PfenningerDeCarolisHirthetal., author = {Pfenninger, Stefan and DeCarolis, Joseph and Hirth, Lion and Quoilin, Sylvain and Staffell, Iain}, title = {The importance of open data and software: Is energy research lagging behind?}, series = {Energy Policy}, volume = {101}, journal = {Energy Policy}, publisher = {Elsevier Ltd}, issn = {0301-4215}, doi = {10.1016/j.enpol.2016.11.046}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-22791}, pages = {211 -- 215}, abstract = {Energy policy often builds on insights gained from quantitative energy models and their underlying data. As climate change mitigation and economic concerns drive a sustained transformation of the energy sector, transparent and well-founded analyses are more important than ever. We assert that models and their associated data must be openly available to facilitate higher quality science, greater productivity through less duplicated effort, and a more effective science-policy boundary. There are also valid reasons why data and code are not open: ethical and security concerns, unwanted exposure, additional workload, and institutional or personal inertia. Overall, energy policy research ostensibly lags behind other fields in promoting more open and reproducible science. We take stock of the status quo and propose actionable steps forward for the energy research community to ensure that it can better engage with decision-makers and continues to deliver robust policy advice in a transparent and reproducible way.}, language = {en} } @article{HirthSteckel, author = {Hirth, Lion and Steckel, Jan}, title = {The role of capital costs for decarbonizing the electricity sector}, series = {Environmental Research Letters}, volume = {11}, journal = {Environmental Research Letters}, number = {11}, issn = {1748-9326}, doi = {10.1088/1748-9326/11/11/114010}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-22804}, pages = {8}, abstract = {Low-carbon electricity generation, i.e. renewable energy, nuclear power and carbon capture and storage, is more capital intensive than electricity generation through carbon emitting fossil fuel power stations. High capital costs, expressed as high weighted average cost of capital (WACC), thus tend to encourage the use of fossil fuels. To achieve the same degree of decarbonization, countries with high capital costs therefore need to impose a higher price on carbon emissions than countries with low capital costs. This is particularly relevant for developing and emerging economies, where capital costs tend to be higher than in rich countries. In this paper we quantitatively evaluate how high capital costs impact the transformation of the energy system under climate policy, applying a numerical techno-economic model of the power system. We find that high capital costs can significantly reduce the effectiveness of carbon prices: if carbon emissions are priced at USD 50 per ton and the WACC is 3\%, the cost-optimal electricity mix comprises 40\% renewable energy. At the same carbon price and a WACC of 15\%, the cost-optimal mix comprises almost no renewable energy. At 15\% WACC, there is no significant emission mitigation with carbon pricing up to USD 50 per ton, but at 3\% WACC and the same carbon price, emissions are reduced by almost half. These results have implications for climate policy; carbon pricing might need to be combined with policies to reduce capital costs of low-carbon options in order to decarbonize power systems.}, language = {en} } @article{HirthMueller, author = {Hirth, Lion and M{\"u}ller, Simon}, title = {System-friendly wind power: How advanced wind turbine design can increase the economic value of electricity generated through wind power}, series = {Energy Economics}, volume = {56}, journal = {Energy Economics}, publisher = {Elsevier B.V.}, issn = {0140-9883}, doi = {10.1016/j.eneco.2016.02.016}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-22819}, pages = {51 -- 63}, abstract = {Previous studies find that the economic value of electricity (USD/MWh) generated by wind power drops with increasing market share. Different measures can help mitigate the value drop, including electricity storage, flexible conventional plants, expansion of transmission, and demand response. This study assesses another option: a change in design of wind power plants. "Advanced" wind turbines that are higher and have a larger rotor compared to rated capacity (lower specific rating) generate electricity more constantly than "classical" turbines. Recent years have witnessed a significant shift towards such advanced technology. Our model-based analysis for Northwestern Europe shows that such design can substantially increase the spot market value of generated electricity. At a 30\% penetration rate, the value of 1 MWh of electricity generated from a fleet of advanced turbines is estimated to be 15\% higher than the value of 1 MWh from classical turbines. The additional value is large, whether compared to wind generation costs, to the value drop, or to the effect of alternative measures such as electricity storage. Extensive sensitivity tests indicate that this finding is remarkably robust. The increase in bulk power value is not the only advantage of advanced turbines: additional benefits might accrue from reduced costs for power grids and balancing services. To fully realize this potential, power markets and support policies need to be appropriately designed and signal scarcity investors.}, language = {en} } @article{HirthUeckerdtEdenhofer, author = {Hirth, Lion and Ueckerdt, Falko and Edenhofer, Ottmar}, title = {Why Wind is not Coal: On the Economics of Electricity Generation}, series = {The Energy Journal}, volume = {37}, journal = {The Energy Journal}, number = {3}, issn = {1944-9089}, doi = {10.5547/01956574.37.3.lhir}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-22828}, pages = {1 -- 27}, abstract = {Electricity is a paradoxical economic good: it is highly homogeneous and heterogeneous at the same time. Electricity prices vary dramatically between moments in time, between location, and according to lead-time between contract and delivery. This three-dimensional heterogeneity has implication for the economic assessment of power generation technologies: different technologies, such as coal-fired plants and wind turbines, produce electricity that has, on average, a different economic value. Several tools that are used to evaluate generators in practice ignore these value differences, including "levelized electricity costs", "grid parity", and simple macroeconomic models. This paper provides a rigorous and general discussion of heterogeneity and its implications for the economic assessment of electricity generating technologies. It shows that these tools are biased, specifically, they tend to favor wind and solar power over dispatchable generators where these renewable generators have a high market share. A literature review shows that, at a wind market share of 30-40\%, the value of a megawatt-hour of electricity from a wind turbine can be 20-50\% lower than the value of one megawatt-hour as demanded by consumers. We introduce "System LCOE" as one way of comparing generation technologies economically.}, language = {en} } @article{HirthSchlandt, author = {Hirth, Lion and Schlandt, Jakob}, title = {{\"U}bertragungsnetzbetreiber erwarten massiven Wertverlust f{\"u}r Solarstrom}, series = {Phasenpr{\"u}fer}, journal = {Phasenpr{\"u}fer}, language = {de} } @article{NahmmacherSchmidHirthetal., author = {Nahmmacher, Paul and Schmid, Eva and Hirth, Lion and Knopf, Brigitte}, title = {Carpe diem: A novel approach to select representative days for long-term power system modeling}, series = {Energy}, volume = {112}, journal = {Energy}, issn = {0360-5442}, doi = {10.1016/j.energy.2016.06.081}, pages = {430 -- 442}, abstract = {In order to explore scenarios on the future of power systems, a variety of numerical models have been developed. As the share of variable renewable energy sources, particularly wind and solar, is projected to significantly increase, accounting for their temporal and spatial variability becomes ever more important in developing sound long-term scenarios. Computational restrictions prevent many long-term power system models being developed with an hourly resolution; instead they use time slices that aggregate periods with similar load and renewable electricity generation levels. There is to date no reproducible and validated method to derive and select time slices for power system models with multiple fluctuating time series. In this paper, we present a novel and effective method that is easily applied to input data for all kinds of power system models. We utilize this procedure in the long-term power system model LIMES-EU and show that a small number of representative days developed in this way are sufficient to reflect the characteristic fluctuations of the input data. Alongside a validation of the method, we discuss the conditions under which seasonal differentiation, and the use of representative weeks instead of days, is necessary.}, language = {en} } @article{Hirth, author = {Hirth, Lion}, title = {The benefits of flexibility: The value of wind energy with hydropower}, series = {Applied Energy}, volume = {181}, journal = {Applied Energy}, doi = {10.1016/j.apenergy.2016.07.039}, pages = {210 -- 223}, abstract = {Several studies have shown that the revenue of wind power generators on spot markets ("market value") diminishes with increasing deployment. This "value drop" is mostly observed in power markets that are dominated by thermal power plants, such as in Germany. This paper assesses the wind market value in power systems where hydroelectric stations with large reservoirs prevail, such as in Sweden. Due to their dispatch flexibility, such hydropower compensates for wind power output variability and thereby mitigates the wind power value drop. The market value of electricity from wind declines with penetration in both types of power systems, but it tends to decline at a slower rate if hydropower is present. This paper presents empirical evidence on the relevance of this effect derived from market data and numerical model results. Our results indicate that when moving from 0\% to 30\% wind penetration, hydropower mitigates the value drop by a third. As a result, 1 MWh of wind energy is worth 18\% more in Sweden than in Germany. Sensitivity analyses indicate high robustness despite large parameter uncertainty: in 80\% of all sensitivities, wind energy is valuable 12-29\% more in Sweden than in Germany. The benefits of hydropower seem to level off at around 20\% wind penetration. This suggests that the hydro flexibility is "exhausted" at this level. Low wind speed wind turbines, carbon pricing, and upgrades of hydropower generation capacity can lever the added value of hydro flexibility further. Not only is wind energy more valuable in the presence of hydropower, hydroelectricity also becomes more valuable if paired with wind power.}, language = {en} } @article{Hirth, author = {Hirth, Lion}, title = {What caused the drop of European electricity prices? A factor decomposition analysis}, series = {The Energy Journal}, volume = {39}, journal = {The Energy Journal}, number = {1}, issn = {0195-6574}, doi = {10.5547/01956574.39.1.lhir}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-23227}, pages = {143 -- 157}, abstract = {European wholesale electricity prices have dropped by early two thirds since their all-time high around 2008. Different factors have been blamed, or praised, for having caused the price slump: the expansion of renewable energy; the near-collapse of the European emissions trading scheme; over-optimistic power plant investments; a decline in final electricity consumption; and cheap coal and natural gas. This ex-post study of European electricity markets from 2008 to 2015 uses a fundamental power market model to quantify their individual contributions on day-ahead prices. The two countries we study in detail, Germany and Sweden,differ significantly: fuel and CO2 prices were important price drivers in Germany, but in Sweden it was electricity demand. This difference is explained by the nature of the hydro-dominate Nordic electricity system. In both countries, however, the single largest factor depressing prices was the expansion of renewable energy. At the same time, Germany's nuclear phase-out had an upward effect on prices. If one defines the Energiewende as the combination of these two policies, its net effect on power prices was negligible.}, language = {en} } @article{HirthMuehlenpfordtBulkeley, author = {Hirth, Lion and M{\"u}hlenpfordt, Jonathan and Bulkeley, Marisa}, title = {The ENTSO-E Transparency Platform. An assessment of Europe's most ambitious electricity data platform}, series = {Applied Energy}, volume = {225}, journal = {Applied Energy}, issn = {0306-2619}, doi = {10.1016/j.apenergy.2018.04.048}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-28171}, pages = {1054 -- 1067}, abstract = {Applied power system research is data intensive, often requiring hour-by-hour data on electricity consumption and generation as well as detailed information about technical and cost parameters of power stations. The European Union obliges firms to publish much of this information on a common website, the "ENTSO-E Transparency Platform" operated by the association of transmission system operators. It is possibly the most ambitious platform for power system data globally. However, anecdotal evidence from users indicates significant shortcomings regarding data quality and usability. This paper provides an introduction to and an assessment of the Transparency Platform, helping researchers to use it more efficiently and to judge data quality more rigorously.}, language = {en} } @article{StefanHirthSchlechtetal, author = {Stefan, Pfenninger and Hirth, Lion and Schlecht, et. al., Ingmar}, title = {Opening the black box of energy modelling: Strategies and lessons learned}, series = {Energy Strategy Reviews}, volume = {19}, journal = {Energy Strategy Reviews}, doi = {10.1016/j.esr.2017.12.002}, pages = {63 -- 71}, abstract = {The global energy system is undergoing a major transition, and in energy planning and decision-making across governments, industry and academia, models play a crucial role. Because of their policy relevance and contested nature, the transparency and open availability of energy models and data are of particular importance. Here we provide a practical how-to guide based on the collective experience of members of the Open Energy Modelling Initiative (Openmod). We discuss key steps to consider when opening code and data, including determining intellectual property ownership, choosing a licence and appropriate modelling languages, distributing code and data, and providing support and building communities. After illustrating these decisions with examples and lessons learned from the community, we conclude that even though individual researchers' choices are important, institutional changes are still also necessary for more openness and transparency in energy research.}, language = {en} } @article{Hirth, author = {Hirth, Lion}, title = {Open data for electricity modeling: Legal aspects}, series = {Energy Strategy Reviews}, journal = {Energy Strategy Reviews}, edition = {27}, doi = {10.1016/j.esr.2019.100433}, abstract = {Power system modeling is data intensive. In Europe, electricity system data is often available from sources such as statistical offices or system operators. However, it is often unclear if these data can be legally used for modeling, and in particular if such use infringes intellectual property rights. This article reviews the legal status of power system data, both as a guide for data users and for data publishers. It is based on interpretation of the law, a review of the secondary literature, an analysis of the licenses used by major data distributors, expert interviews, and a series of workshops. A core finding is that in many cases the legality of current practices is doubtful: in fact, it seems likely that modelers infringe intellectual property rights quite regularly. This is true for industry analysis but also academic researchers. A straightforward solution is open data - the idea that data can be freely used, modified, and shared by anyone for any purpose. To be open, it is not sufficient for data to be accessible free of cost, it must also come with an open data license, the most common types of which are also reviewed in this paper.}, language = {en} } @article{JerrentrupLotzTiedemannetal., author = {Jerrentrup, Lars and Lotz, Bastian and Tiedemann, Silvana and Hirth, Lion}, title = {Technology-Neutral Auctions for Renewable Energy: EU Law vs. Member State Reality}, series = {Journal for European Environmental \& Planning Law}, volume = {16}, journal = {Journal for European Environmental \& Planning Law}, edition = {4}, issn = {1876-0104}, doi = {10.1163/18760104-01604005}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-30906}, pages = {386 -- 406}, abstract = {European Union competition law, intended to thwart subsidies paid out by national governments, plays an important role in shaping EU Member States' support schemes for renewable energy. The Environmental and Energy State Aid Guidelines 2014-2020, which formalize the European Commission's take on subsidies in the electricity sector, prescribe technology-neutral auctions as the standard mechanism to determine support levels. In this study, we have assessed the formal decisions of the Commission with respect to technology-neutrality between July 2014 and May 2018. It turns out that 16 out of 18 schemes are not technology-neutral and figure high degrees of technology-differentiation. We have also studied the exemption clauses invoked to justify technology-discrimination, finding that the most ambiguous clause is used most frequently, and that the application and level of scrutiny varies strongly from case to case. The State Aid Guidelines are meant to increase transparency and legal certainty. We find that with respect to technology-neutral auctions for renewable energy, the Guidelines fail to deliver on their purpose.}, language = {en} } @article{RuhnauHirthPraktiknjo, author = {Ruhnau, Oliver and Hirth, Lion and Praktiknjo, Aaron}, title = {Time series of heat demand and heat pump efficiency for energy system modeling}, series = {Nature Scientific Data}, volume = {6}, journal = {Nature Scientific Data}, number = {189}, doi = {10.1038/s41597-019-0199-y}, abstract = {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.}, language = {en} } @article{KochHirth, author = {Koch, Christopher and Hirth, Lion}, title = {Short-term electricity trading for system balancing: An empirical analysis of the role of intraday trading in balancing Germany's electricity system}, series = {Renewable \& Sustainable Energy Reviews}, volume = {113}, journal = {Renewable \& Sustainable Energy Reviews}, doi = {10.1016/j.rser.2019.109275}, abstract = {Previous studies have noted that, surprisingly, Germany's dramatic expansion of wind and solar energy coincided with a reduction of short-term balancing reserves. This paper provides further and updated evidence, supporting this "German Balancing Paradox": since 2011 wind and solar energy nearly doubled while reserve requirements and reserve activation declined by around 50\%. We quantitatively explore one reason for reduced balancing needs: increased and improved short-term wholesale electricity trading. Electricity trading is now commonly done around the clock and based on quarter hours, rather than hours. The shift to quarter-hourly products alone explains a decrease in balancing energy by 17\%. We also find strong evidence for market parties to respond efficiently to imbalance charges, suggesting that market-based approaches to balancing work.}, language = {en} } @article{WieseSchlechtBunkeetal., author = {Wiese, Frauke and Schlecht, Ingmar and Bunke, Wolf-Dieter and Gerbaulet, Clemens and Hirth, Lion and Jahn, Martin and Kunz, Friedrich and Lorenz, Casimir and M{\"u}hlenpfordt, Jonathan and Reimann, Juliane and Schill, Wolf-Peter}, title = {Open Power System Data - Frictionless data for electricity system modelling}, series = {Applied Energy}, volume = {236}, journal = {Applied Energy}, doi = {10.1016/j.apenergy.2018.11.097}, pages = {409}, abstract = {The quality of electricity system modelling heavily depends on the input data used. Although a lot of data is publicly available, it is often dispersed, tedious to process and partly contains errors. We argue that a central provision of input data for modelling has the character of a public good: it reduces overall societal costs for quantitative energy research as redundant work is avoided, and it improves transparency and reproducibility in electricity system modelling. This paper describes the Open Power System Data platform that aims at realising the efficiency and quality gains of centralised data provision by collecting, checking, processing, aggregating, documenting and publishing data required by most modellers. We conclude that the platform can provide substantial benefits to energy system analysis by raising efficiency of data pre-processing, providing a method for making data pre-processing for energy system modelling traceable, flexible and reproducible and improving the quality of original data published by data providers.}, language = {en} } @article{DertingerHirth, author = {Dertinger, Andrea and Hirth, Lion}, title = {Reforming the electric power industry in developing economies: Evidence on efficiency and electricity access outcomes}, series = {Energy Policy}, journal = {Energy Policy}, number = {139}, doi = {10.1016/j.enpol.2020.111348}, abstract = {Since the 1990s, many developing countries have restructured their electric power industry. Policies such as breaking up, commercializing and privatizing utilities, allowing for independent power producers, installing independent regulators, and introducing competitive wholesale markets were meant to improve the industry's efficiency and service quality. We exploit more than 30 years of data from over 100 countries to investigate the impact of power sector reforms on efficiency (represented by network losses) and access to electricity (represented by connection rates and residential power consumption). Crucially, reforms are likely to be endogenous with respect to sector performance: a crisis in electricity supply might well trigger reform efforts. We deal with endogeneity using reform activity in neighboring countries as an instrument. Our results suggest that reforms strongly and positively impact electricity access. According to our preferred specification, a full reform program would increase connection rates by 20 percentage points and per capita consumption by 62 percent: these are large effects that are stable across a range of robustness checks. Moreover, the effect of improving access is largest in South Asian countries. In contrast to previous studies, we do not find robust evidence to support the theory that reforms reduce network losses.}, language = {en} } @article{Hirth, author = {Hirth, Lion}, title = {Open Data for Electricity Modeling: Legal Aspects}, series = {Energy Strategy Reviews}, journal = {Energy Strategy Reviews}, number = {27}, doi = {10.1016/j.esr.2019.100433}, abstract = {Power system modeling is data intensive. In Europe, electricity system data is often available from sources such as statistical offices or system operators. However, it is often unclear if these data can be legally used for modeling, and in particular if such use infringes intellectual property rights. This article reviews the legal status of power system data, both as a guide for data users and for data publishers. It is based on interpretation of the law, a review of the secondary literature, an analysis of the licenses used by major data distributors, expert interviews, and a series of workshops. A core finding is that in many cases the legality of current practices is doubtful: in fact, it seems likely that modelers infringe intellectual property rights quite regularly. This is true for industry analysis but also academic researchers. A straightforward solution is open data - the idea that data can be freely used, modified, and shared by anyone for any purpose. To be open, it is not sufficient for data to be accessible free of cost, it must also come with an open data license, the most common types of which are also reviewed in this paper.}, language = {en} } @article{CloeteHirth, author = {Cloete, Schalk and Hirth, Lion}, title = {Flexible power and hydrogen production: Finding synergy between CCS and variable renewables}, series = {Energy}, volume = {192}, journal = {Energy}, doi = {10.1016/j.energy.2019.116671}, abstract = {The expansion of wind and solar power is creating a growing need for power system flexibility. Dispatchable power plants with CO2 capture and storage (CCS) offer flexibility with low CO2 emissions, but these plants become uneconomical at the low running hours implied by renewables-based power systems. To address this challenge, the novel gas switching reforming (GSR) plant was recently proposed. GSR can alternate between electricity and hydrogen production from natural gas, offering flexibility to the power system without reducing the utilization rate of the capital stock embodied in CCS infrastructure. This study assesses the interplay between GSR and variable renewables using a power system model, which optimizes investment and hourly dispatch of 13 different technologies. Results show that GSR brings substantial benefits relative to conventional CCS. At a CO2 price of €100/ton, inclusion of GSR increases the optimal wind and solar share by 50\%, lowers total system costs by 8\%, and reduces system emissions from 45 to 4 kgCO2/MWh. In addition, GSR produces clean hydrogen equivalent to about 90\% of total electricity demand, which can be used to decarbonize transport and industry. GSR could therefore become a key enabling technology for a decarbonization effort led by wind and solar power.}, language = {en} } @article{RuhnauHirthPraktiknjo, author = {Ruhnau, Oliver and Hirth, Lion and Praktiknjo, Aaron}, title = {Heating with Wind: Economics of heat pumps and variable renewables}, series = {Energy Economics}, volume = {92}, journal = {Energy Economics}, doi = {10.1016/j.eneco.2020.104967}, abstract = {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.}, language = {en} } @article{EickeKhannaHirth, author = {Eicke, Anselm and Khanna, Tarun and Hirth, Lion}, title = {Locational Investment Signals: How to Steer the Siting of New Generation Capacity in Power Systems?}, series = {The Energy Journal}, volume = {41}, journal = {The Energy Journal}, number = {6}, doi = {10.5547/01956574.41.6.aeic}, pages = {281 -- 304}, abstract = {New generators located far from consumption centers require transmission infrastructure and increase network losses. The primary objective of this paper is to study signals that affect the location of generation investment. Such signals result from the electricity market itself and from additional regulatory instruments. We cluster them into five groups: locational electricity markets, deep grid connection charges, grid usage charges, capacity mechanisms, and renewable energy support schemes. We review the use of instruments in twelve major power systems and discuss relevant properties, including a quantitative estimate of their strength. We find that most systems use multiple instruments in parallel, and none of the identified instruments prevails. The signals vary between locations by up to 20 EUR per MWh. Such a difference is significant when compared to the levelized costs of combined cycle plants of 64-72 EUR per MWh in Europe.}, language = {en} } @article{BlumeWerryFaberHirthetal., author = {Blume-Werry, Eike and Faber, Thomas and Hirth, Lion and Huber, Claus and Everts, Martin}, title = {Eyes on the Price: Which Power Generation Technologies Set the Market Price?}, series = {Economics of Energy \& Environmental Policy}, volume = {10}, journal = {Economics of Energy \& Environmental Policy}, number = {1}, doi = {10.5547/2160-5890.10.1.eblu}, abstract = {Upon discussion of price setting on electricity wholesale markets, many refer to the so-called merit order model. Conventional wisdom holds that during most hours of the year, coal- or natural gas-fired power plants set the price on European markets. In this context, this paper analyses price setting on European power markets. We use a fundamental electricity market model of interconnected bidding zones to determine hourly price-setting technologies for the year 2020. We find a price-setting pattern that is more complex and nuanced than the conventional wisdom suggests: across all researched countries, coal- and natural gas-fired power plants set the price for only 40 per cent of all hours. Other power generation technologies such as wind, biomass, hydro and nuclear power plants as well as lignite-fired plants set the price during the rest of the year. On some markets, the price setting is characterised by a high level of interconnectivity and thus foreign influence - as illustrated by the example of the Netherlands. During some 75 per cent of hours, foreign power plants set the price on the Dutch market, whilst price setting in other more isolated markets is barely affected by foreign markets. Hence, applying the price setting analysis to the proposed Dutch carbon price floor, we show that different carbon prices have little effect on the technological structure of the price-setting units. In this respect, the impacts of the unilateral initiative are limited. There are, however, considerable changes to be observed in wholesale power prices, import/export balances as well as production volumes and subsequent CO2 outputs of lignite-, coal- and gas-fired power plants.}, language = {en} } @article{KhannaBaiocchiCallaghanetal., author = {Khanna, Tarun and Baiocchi, Giovanni and Callaghan, Max and Creutzig, Felix and Guias, Horia and Haddaway, Neal R. and Hirth, Lion and Javaid, Aneeque and Koch, Nicolas and Laukemper, Sonja and L{\"o}schel, Andreas and del Mar Zamora Dominguez, Maria and Minx, Jan C.}, title = {A multi-country meta-analysis on the role of behavioural change in reducing energy consumption and CO2 emissions in residential buildings}, series = {Nature Energy}, volume = {6}, journal = {Nature Energy}, doi = {10.1038/s41560-021-00866-x}, pages = {925 -- 932}, abstract = {Despite the importance of evaluating all mitigation options to inform policy decisions addressing climate change, a comprehensive analysis of household-scale interventions and their emissions reduction potential is missing. Here, we address this gap for interventions aimed at changing individual households' use of existing equipment, such as monetary incentives or feedback. We have performed a machine learning-assisted systematic review and meta-analysis to comparatively assess the effectiveness of these interventions in reducing energy demand in residential buildings. We extracted 360 individual effect sizes from 122 studies representing trials in 25 countries. Our meta-regression confirms that both monetary and non-monetary interventions reduce the energy consumption of households, but monetary incentives, of the sizes reported in the literature, tend to show on average a more pronounced effect. Deploying the right combinations of interventions increases the overall effectiveness. We have estimated a global carbon emissions reduction potential of 0.35 GtCO2 yr-1, although deploying the most effective packages of interventions could result in greater reduction. While modest, this potential should be viewed in conjunction with the need for de-risking mitigation pathways with energy-demand reductions.}, language = {en} } @article{CloeteRuhnauHirth, author = {Cloete, Schalk and Ruhnau, Oliver and Hirth, Lion}, title = {On capital utilization in the hydrogen economy: The quest to minimize idle capacity in renewables-rich energy systems}, series = {International Journal of Hydrogen Energy}, volume = {46}, journal = {International Journal of Hydrogen Energy}, number = {1}, doi = {10.1016/j.ijhydene.2020.09.197}, pages = {169 -- 188}, abstract = {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.}, language = {en} } @article{EickeRuhnauHirth, author = {Eicke, Anselm and Ruhnau, Oliver and Hirth, Lion}, title = {Electricity balancing as a market equilibrium: An instrument-based estimation of supply and demand for imbalance energy}, doi = {10.1016/j.eneco.2021.105455}, abstract = {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.}, language = {en} } @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} } @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} } @article{RuhnauStieweMuesseletal., author = {Ruhnau, Oliver and Stiewe, Clemens and Muessel, Jarusch and Hirth, Lion}, title = {Natural gas savings in Germany during the 2022 energy crisis}, series = {Nature Energy}, journal = {Nature Energy}, doi = {10.48462/opus4-4944}, url = {http://nbn-resolving.de/urn:nbn:de:kobv:b1570-opus4-49445}, abstract = {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.}, language = {en} } @article{SchlechtMaurerHirth, author = {Schlecht, Ingmar and Maurer, Christoph and Hirth, Lion}, title = {Financial contracts for differences: The problems with conventional CfDs in electricity markets and how forward contracts can help solve them}, series = {Energy Policy}, volume = {186}, journal = {Energy Policy}, doi = {10.1016/j.enpol.2024.113981}, abstract = {Contracts for differences are widely seen as a cornerstone of Europe's future electricity market design. This paper is about designing such contracts. We identify the dispatch and investment distortions that conventional CfDs cause, the patches used to overcome these shortcomings, and the problems these fixes introduce. We then propose an alternative contract we call "financial" CfD. This hybrid between conventional CfDs and forward contracts mitigates revenue risk to a substantial degree while providing undistorted incentives. Like conventional CfDs, it is long-term and tailored to technology-specific (wind, solar, nuclear) generation patterns but, like forwards, decouples payments from actual generation. The proposed contract mitigates volume risk and avoids margin calls by accepting physical assets as collateral.}, language = {en} } @article{HirthKhannaRuhnau, author = {Hirth, Lion and Khanna, Tarun M. and Ruhnau, Oliver}, title = {How aggregate electricity demand responds to hourly wholesale price fluctuations}, series = {Energy Economics}, volume = {135}, journal = {Energy Economics}, publisher = {Elsevier BV}, issn = {0140-9883}, doi = {10.1016/j.eneco.2024.107652}, abstract = {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.}, language = {en} }