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The Role of Weather Predictions in Electricity Price Forecasting Beyond the Day-Ahead Horizon
(2022)
Forecasts of meteorology-driven factors, such as intermittent renewable generation, are commonly included in electricity price forecasting models. We show that meteorological forecasts can be used directly to improve price forecasts multiple days in advance. We introduce an autoregressive multivariate linear model with exogenous variables and LASSO for variable selection and regularization. We used variants of this model to forecast German wholesale prices up to ten days in advance and evaluate the benefit of adding meteorological forecasts, namely wind speed and direction, solar irradiation, cloud cover, and temperature forecasts of selected locations across Europe. The resulting regression coefficients are analyzed with regard to their spatial as well as temporal distribution and are put in context with underlying power market fundamentals. Wind speed in northern Germany emerges as a particularly strong explanatory variable. The benefit of adding meteorological forecasts strongest when autoregressive effects are weak, yet the accuracy of the meteorological forecasts is sufficient for the model to identify patterns. Forecasts produced 2-4 days in advance exhibit an improvement in RMSE by 10-20%. Furthermore, the forecasting horizon is shown to impact the choice of the regularization penalty that tends to increase at longer forecasting horizons.
Assessing Climate Policy Instrument Pathways: An Application to the German Light Duty Vehicle Sector
(2022)
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.
The European Commission has proposed a carbon border adjustment mechanism (CBAM) that would apply the carbon price prevailing in the EU emissions trading system to import-related emissions. We conducted a survey to study perceptions of an EU CBAM among German key stakeholders from industry, civil society, and research in July 2021. We find that substantial support for CBAM exists as well as the expectation that the mechanism will eventually be introduced. We identified divergent views on key design options among stakeholder groups. Stakeholders from industry generally favour the continuation of free allocation of emissions allowances, rebates for exporters from the EU, coverage of only scope 1 emissions, and use of revenues for domestic spending. Stakeholders from civil society prefer phasing out free allocation, coverage only of imports, an emissions scope including all indirect emissions, exempting low-income countries and countries that do implement non-price-based climate policies, and the use of revenues to finance green transformation in low-income countries. Respondents from research would generally rather see free allocation being phased out, emissions coverage of scope 1 and 2, exemptions for low-income countries and countries that do implement non-price-based policies with comparable effects in relevant sectors and a transfer of revenues to support clean technologies in low-income countries and green technologies in the EU. Our survey design allows us to identify three cross-stakeholder group clusters, one containing stakeholders who are comparably more hesitant towards CBAM, a second one with respondents most in favour of introducing CBAM, as well as a 'middle ground' cluster which contains views that are often in between the other two. We also compare the survey responses to the design of the Commission's CBAM proposal to identify the most likely points of political disagreement.
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.
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.
Electrolytic hydrogen complements renewable energy in many net-zero energy scenarios. In these long-term scenarios with full decarbonization, the “greenness” of hydrogen is without question. In current energy systems, however, the ramp-up of hydrogen production may cause additional emissions. To avoid this potential adverse effect, recently proposed EU regulation defines strict requirements for electrolytic hydrogen to qualify as green: electrolyzers must run on additional renewable generation, which is produced in a temporally and geographically congruent manner. Focusing on the temporal dimension, this paper argues in favor of a more flexible definition of green hydrogen, which keeps the additionality criterion on a yearly basis but allows for dispatch optimization on a market basis within that period. We develop a model that optimizes dispatch and investment of a wind-hydrogen system—including wind turbines, hydrogen electrolysis, and hydrogen storage—and apply the model to a German case study based on data from 2017-2021. Contrasting different regulatory conditions, we show that a flexible definition of green hydrogen can reduce costs without additional power sector emissions. By contrast, requiring simultaneity implies that a rational investor would build a much larger wind turbine, hydrogen electrolyzer, and hydrogen storage than needed. This leads to additional costs, underutilized resources, and a potential slow-down of green hydrogen deployment. We discuss that current trends in the energy transition are likely to amplify the economic and environmental benefits of a flexible definition of green hydrogen and recommend this as the way forward for a sustainable hydrogen policy.
In electricity systems, supply traditionally follows demand. Consequently, economists have focused on analyzing supply while assuming perfectly inelastic demand. Demand flexibility, if at all, occurred in deterministic patterns, such as during peak and off-peak periods, incentivized by static time-of-use tariffs. Nowadays, the role of electricity demand is changing fundamentally: growing shares of fluctuating wind and solar energy require flexibility in a larger quantity and on a stochastic basis; increasing loads of electric vehicles, heat pumps, and hydrogen electrolyzers could provide flexibility through battery, thermal, and gas storage; and the introduction of smart meters enables dynamic real-time tariffs and an automated response of distributed loads.
This cumulative dissertation contributes to the economic understanding of flexible electricity demand with five scientific articles. Article 1 starts with reviewing the role of electrification in decarbonization scenarios for heating and road transport in Germany. The article finds that decarbonization drives electrification, leading to an increase in electricity demand by a factor of roughly two. Direct and indirect electrification options are contrasted with respect to their distinct flexibility potential.
Articles 2 and 3 explore the implications of decentralized electric heat pumps and centralized electrolytic hydrogen, respectively, for the market value of renewables. Both use the same numerical electricity market model. Article 2 finds that the volatility of the heat pump’s electricity demand challenges the electricity system, which becomes apparent in increasing load cost. A flexible operation of heat pumps may reduce this challenge, but potential benefits for the market value of wind energy are minor. By contrast, Article 3 shows that hydrogen electrolyzers have the potential to stabilize renewable market values at high renewable market shares effectively and permanently, because additional renewable supply can trigger investment in additional hydrogen electrolyzers with additional demand.
Articles 4 and 5 investigate the flexibility of the current electricity demand using econometric models with instrumental variables. Article 4 reveals that, at an hourly temporal resolution, the aggregated electricity demand in Germany is indeed price-elastic; it decreases by 70 MW for every € 1 per MWh increase in the day-ahead wholesale price. Article 5 finds that demand is also price-responsive in the very short term: the demand for imbalance energy responds to the imbalance price—despite the legal obligation in Germany to minimize imbalances independent of prices.
Um die Klimaziele bis 2045 zu erreichen, muss der Stromsektor fundamental verändert werden. Insbesondere die Erneuerbaren Energien (EE) müssen massiv ausgebaut werden. Dabei stellt sich auch die Frage, an welchen Standorten neue Anlagen errichtet werden. Fand der Zubau historisch eher in den Regionen mit guten natürlichen Ressourcen an Wind und Sonne, hohen Volllaststunden und damit niedrigen Kosten pro erzeugter Stromeinheit statt, kann in Zukunft eine Standortsteuerung notwendig werden, um Kosten und Nutzen des EE-Ausbaus gleichmäßiger über das Bundesgebiet zu verteilen, die Stromnetze zu entlasten und die Potentiale in allen Regionen zu heben.
Im Rahmen des Kopernikus-Projekts Ariadne wurden Szenarien entwickelt, anhand derer Bürgerinnen und Bürger die Vor- und Nachteile verschiedener regionaler Verteilungen der Standorte aus Akzeptanzgesichtspunkten diskutierten. Dabei wurde erkennbar, dass mögliche regionale Verteilungen, die aus Sicht der Bürgerinnen und Bürger eher wünschenswert wären, deutlich vom Status Quo abweichen.
In der vorliegenden Analyse geben wir daher einen Überblick über die Regulierungs- und Politikinstrumente, mit denen eine ex ante bestimmte regionale Verteilung erreicht werden kann, die nicht allein einer ökonomischen Optimierung folgt. Zur Bestimmung der Verteilung können übergeordnete Anforderungen, beispielsweise an eine ausgewogene Flächenverteilung, eine Rolle spielen, aber auch gesellschaftliche Indikatoren, wie eine als gerecht empfundene Lasten- und Nutzenteilung. Wir analysieren Vor- und Nachteile der verschiedenen Instrumente und geben Hinweise zu ihrer juristischen Umsetzbarkeit. Außerdem quantifizieren wir anhand eines stilisierten Beispiels, wie preisbasierte Steuerungselemente ausgestaltet werden müssten, um zu einer regionalen Verteilung der Windanlagen in Deutschland zu führen, die in dem „Fokus PV“-Szenario des Ariadne-Reports zur Klimaneutralität 20451 modelliert wurde.
Die Analyse zeigt auf, dass eine Vielzahl von Instrumenten die regionale Verteilung so beeinflussen können, dass sie zu einer gleichmäßigeren und mitunter als gerechter empfundenen Verteilung des Zubaus an Erneuerbaren Energien führt.
Das Aufzeigen der verschiedenen Instrumentenoptionen zur regionalen Steuerung ist relevant für die künftige Gestaltung der Energiewende, da die bisherige regionale Steuerung vor allem innerhalb der Erneuerbaren-Förderung stattfindet, die in Zukunft jedoch zunehmend an Bedeutung verlieren dürfte und zudem nicht alle Technologien berücksichtigt. Die transparente Darstellung der Vor- und Nachteile hilft außerdem beim Abwägen im Falle von – bei der Auswahl von Standorten häufig auftretenden – Interessenskonflikten.
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.