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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. While seemingly modest, our results imply that even with limited exposure to real time prices, short-term demand response facilitates decarbonization of the electricity grid by reducing the need for battery storage or backup fossil power by approximately 8%.

Contracts for differences are widely discussed as a cornerstone of Europe’s future electricity market design. This is a paper on CfD contract design. We summarize the dispatch and investment distortions that conventional CfDs cause, the patches that are used to overcome these shortcomings, and the problems these fixes introduce. We then propose an alternative contract that we dub “financial” CfD. It is a hybrid between conventional CfDs and forward contracts that mitigates revenue risk to a very large degree while providing undistorted incentives and avoiding margin calls. Like traditional CfDs, these contracts are long-term and tailored to technology-specific (wind, solar, nuclear) generation patterns but, like forwards, decouple payments from actual generation. We also propose to mitigate volume risk and to accept physical assets as collateral to avoid margin calls.

This report discusses the improvements made in the three economic impacts models that are the modeling ensemble of SENTINEL Work Package 5, namely, the European Electricity Market Model (EMMA), the WEGDYN computable general equilibrium (CGE) model and the Business Strategy Assessment Model (BSAM). EMMA is a techno-economic model, developed to simulate the integrated north-western European power system. It models both dispatch of and investment in power plants, minimizing total costs with respect to investment, production, and trade decisions under a large set of technical constraints. WEGDYN belongs to the class of macroeconomic models, which depict the whole economy, separated into different production sectors and demand agents. At the global level, it can be configured at flexible country/regional levels. At the country/regional level, it can be configured at flexible sectoral levels. The model also differentiates private and public households across European countries/regions. The Business Strategy Assessment Model (BSAM) is an agent-based simulation model which simulates the Day-Ahead Scheduling (DAS) of wholesale electricity markets. It outputs the system marginal price (SMP), the electricity mix, the generation schedule of all resources, the profit/loss of each generator, and the level of curtailment applied to renewable energy sources. It is currently developed and calibrated to model the specificities of the Greek wholesale electricity market. Together these three models aim to capture micro- and macroeconomic impacts of the energy transition. Improvements were made to the structure and functioning of these three models to match user needs. Based on the literature review on modelling trends and paradigms, the expertise of the involved project partners, and considering user needs, we identified the following key areas for enhancing the capabilities of economic impact models covered in this project: Exploration of distributional effects at the level of economic sectors (incl. energy) and private and public households by improving the WEGDYN model. Exploration of the effects of (de)commissioning and (in) flexible energy production at a higher resolved technological level by adding these features to the EMMA model. Evaluation of the evolution of the electricity mix as RES technologies’ capacity increases in the generation portfolio by using the improved BSAM model Provision of a comprehensive, consistent and tractable assessment of the trade-offs and synergies related to the energy transition (distributional effects, emission reduction targets, competitiveness, etc.) by soft linking of EMMA, BSAM and WEGDYN., The authors would like to acknowledge the support from the EC. The authors would like to thank the stakeholders that participated in the interview meetings, the online survey and the stakeholders workshop. The content of this report is the sole responsibility of its authors and does not necessary reflect the views of the EC.

Contracts for differences are widely discussed as a cornerstone of Europe’s future electricity market design. In this paper, we make three contributions to the debate. First, we summarize the dispatch and investment distortions that traditional CfDs cause. Second, we propose an alternative CfD specification that we dub "financial wind CfDs". It is a hybrid between CfDs and forward contracts that aims at being superior to conventional CfDs both in terms of risk mitigation and incentives. Third, we point out that "the other side of the contract", the government’s financial position resulting from any long-term contract with generators, must be carefully handled to avoid muting consumers' flexibility incentives or depleting forward markets.

This paper proposes a game-theoretic model to analyze the strategic behavior of inc-dec gaming in market-based congestion management (redispatch). We extend existing models by considering incomplete information about competitors' costs and a finite set of providers. We find that these extensions do not dissolve inc-dec gaming, which already occurs in our setup of two regions. We also benchmark market-based redispatch against grid investment, cost-based redispatch, and the Vickrey-Clarke-Groves mechanism. The comparison highlights a significant inefficiency of market-based redispatch and inflated redispatch payments. Finally, we study seven variations of our basic model to assess whether different market fundamentals or market design changes mitigate inc-dec gaming. None of these variations eliminate inc-dec gaming entirely.

When Russia curbed natural gas supply to Europe in 2021 and 2022, it created 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, trends, and economic activity. For industrial consumers, we find a strong and sustained response, with reductions steadily increasing from 4% in September 2021 to 19% in September 2022, roughly following wholesale price levels. For small consumers, including households and small enterprises, we find a response between 10% and 36% from March to September 2022. However, large relative reductions during the summer translate to small absolute values, because small consumers use little gas during this season anyway. The amount of gas burned in power stations is primarily driven by electricity sector events that are not directly linked to reduced Russian gas supply. These findings suggest that voluntary reductions in gas consumption have played a significant role in coping with the crisis. Updated version from October 2022

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.

This paper proposes a game-theoretic model to analyze the strategic behavior of incdec gaming in market-based congestion management (redispatch). We extend existing models by considering incomplete information about competitors’ costs and a finite set of providers. We find that these extensions do not dissolve inc-dec gaming, which already occurs in our setup of two regions. We also benchmark market-based redispatch against grid investment, cost-based redispatch, and the Vickrey-Clarke-Groves mechanism. The comparison highlights a significant inefficiency of market-based redispatch and inflated redispatch payments. Finally, we study seven variations of our basic model to assess whether different market fundamentals or market design changes mitigate inc-dec gaming. None of these variations eliminate inc-dec gaming entirely

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.

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.

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 system imbalance 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. Please cite as: Eicke, Anselm, Oliver Ruhnau & Lion Hirth (2021): “Electricity balancing as a market equilibrium: An instrument-based estimation of supply and demand for imbalance energy”, Energy Economics, https://doi.org/10.1016/j.eneco.2021.105455