@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{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{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} }