By extending carbon pricing to buildings and road transport through ETS2, the European Union is undertaking a major policy experiment in market creation. ETS2 overlaps national emissions budgets and technology requirements, raising a general question: when does a legal market govern allocation? We distinguish three functions of market effectiveness: scarcity, exchange, and allocation authority. Completing exchange and allocation authority lowers present-value EU policy costs over 2028–2048 by 25.5%, or EUR 1.33 trillion relative to legal market creation only. Allocation authority accounts for 76% of savings; 88% of member states benefit. Compensating remaining losses requires EUR 6 billion, only 0.2% of ETS2 revenues. Restoring allocation authority raises the allowance price but lowers policy cost, implying that the endogenous carbon price in an ETS is not a sufficient statistic for welfare across institutional designs.

The European Union (EU) has pledged to reduce greenhouse gas (GHG) emissions until the year 2030 by 55% compared to 1990. Recently, the EU institutions decided to introduce a new Emission Trading System for road transport, buildings and fuels for additional sectors (ETS2) in addition to the current EU ETS. Contested design features were the split of the carbon budget between the EU ETS and the remaining sectors regulated under the Effort Sharing Regulation (ESR), and the carbon price level of the ETS2. Conducting a multi-model assessment, we find that the agreed allocation of the carbon budget between EU ETS and ESR sectors seems almost optimal from an economic efficiency point of view. We also find that if carbon prices are the only instruments used, the prices necessary to reach the emission targets range from 130 to 286 euro/tCO2 in the EU ETS and from 175 to 360 euro/tCO2 for the energy-related ESR (ESR-E) emissions - depending on technology development and baseline assumptions of the different models. Our results imply that when the ETS2 price does not go above the "indicative cap" of 45 euro/tCO2, the abatement target will not be reached with a carbon price alone. The remaining abatement needs to come from complementary policies like technology standards or subsidies. As abatement costs from these policies are above 45 euro/tCO2, effective costs for consumers could well exceed the costs of carbon pricing alone due to inefficiencies that arise from the lack of flexibility to mitigate emissions where it is cheapest.

This paper provides an empirical assessment of the impact of rising gas and carbon prices on European electricity prices. Using a comprehensive data set of hourly power market data of 14 European countries, we estimate the impact of gas and carbon prices on electricity prices for the years 2018 to 2021. Depending on the country, we find that a gas price increase of 1€/MWh leads to an electricity price increase of 0.2-1.4€/MWh. Correspondingly, a carbon price increase of 1€/tCO2 leads to an electricity price increase of 0.5-1.0€/MWh. The magnitude of these impacts depends on a power market’s production portfolio: Countries with a high gas share are more heavily affected by increasing gas prices; whereas the carbon price impact is higher for countries with a high coal share. Finally, we find that the rising gas price was mostly responsible for the electricity price increase in 2021. We show that the gas price lead to an average increase in electricity prices of 110€/MWh; whereas the increase attributed to the carbon price only amounted to an average of 20€/MWh. Thus, our analysis contributes to the current policy debate on reasons and distributional consequences of rising energy and carbon prices across Europe.

Electricity generation based on renewable energy (RE) sources such as wind and solar replace the most expensive generators that often rely on fossil fuels. In response to RE promotion, wholesale electricity prices and carbon emissions are therefore expected to decrease. In interconnected electricity systems, this so-called merit- order effect stimulates a change in electricity trade ows. Therefore, conventional generation and prices in neighboring countries are also likely to decrease. The impact of these trade reactions on carbon offsets is ambiguous and depends on installed generation and interconnector capacities. Moreover, the cross-border merit-order effect causes opposing effects on consumers and producers: Generators' profits decline, while consumers benefit from lower electricity costs and an increase in the consumer surplus. Using a rich data set of hourly technology-specific generation and wholesale market price data for ten central European countries, we estimate the domestic and cross-border impacts of German RE for the years 2015 to 2020. We find that German RE generation offset 79 to 113 MtCO2 per year. The major emission effect took place in Germany (64 - 99 MtCO2). The average cost of emission offset of 212 to 321e/t were almost entirely borne by German market participants. Neighboring countries do not bear costs, but a significant shift from producer to consumer rents is observed.

We examine how optimal renewable energy (RE) support policies need to be adjusted to account for carbon prices. We show theoretically and empirically that changing carbon prices requires adjusting RE subsidies due to two motives. First, RE premiums need to be reduced to reflect the carbon value embedded in the market price. Second, once a coal to gas switch occurs, RE premiums and feed-in tariffs need to be adjusted to account for changes in the marginal external benefit of RE. We use empirical estimations and numerical simulation models to quantify these effects for the United Kingdom. We show that the second effect is empirically small, whereas the first effect requires to completely phase-out RE premiums with increasing carbon prices. Finally, a fuel switch increases solar-induced abatement, whereas wind-induced abatement is rather invariant to a fuel switch. Yet, the differentiation of optimal subsidies between wind and solar power is modest.

While carbon taxes are generally seen as a rational policy response to climate change, knowledge about their performance from an expost perspective is still limited. This paper analyzes the emissions and cost impacts of the UK CPS, a carbon tax levied on all fossil-fired power plants. To overcome the problem of a missing control group, we propose a policy evaluation approach which leverages economic theory and machine learning for counterfactual prediction. Our results indicate that in the period 2013-2016 the CPS lowered emissions by 6.2 percent at an average cost of €18 per ton. We find substantial temporal heterogeneity in tax-induced impacts which stems from variation in relative fuel prices. An important implication for climate policy is that in the short run a higher carbon tax does not necessarily lead to higher emissions reductions or higher costs.

Carbon pricing is a key instrument for achieving Europe's ambitious climate targets. It is therefore not surprising that reform of the EU carbon market is at the heart of the measures proposed by the European Commission (EC). One important policy innovation would be the introduction of a second emissions trading system in Europe that integrates other sectors like buildings and road transport. This addresses some of the inefficiencies of the existing, fragmented EU carbon markets, but at the same time requires a policy decision with potentially large implications in terms of economic costs to achieve European climate goals: How should the EU carbon budget be divided between two separate carbon markets? Achieving the EU climate target of 55 per cent causes a decrease in the aggregate consumption level of the EU-27 countries of 2.8 per cent or 248.9 billion euros in 2030 under current EU climate policy (without considering possible benefits from avoided climate change damages). A new emissions trading system reduces these costs by 21.5 per cent under the current allocation of the EU climate budget and by 33.0 per cent under the allocation proposed by the European Commission. Larger cost reductions of up to 61.6 per cent are possible if an even larger emissions budget is allocated to the buildings and transport sectors. Given the difficulties to politically determine the allocation of the EU climate budget, market-based flexibility mechanisms are desirable in order to achieve climate targets at the lowest economic cost.

This study analyses factors related to allowance-trading behaviour for the first ten years of the existence of the European Union Emissions Trading System (EU ETS). Our empirical analysis employs a dataset that combines information on trading activities for more than 6000 companies with company characteristics. Indicators of trading activity include the volume and the number of transactions as well as the usage of intermediaries and of derivatives markets. For 2005–2014 and for the individual trading periods, we find that trading behaviour is related to the size of a company, its net position (the difference between free allocations and verified emissions), its sector affiliation, productivity, and location. We also find evidence that trading-related transaction costs affect trading activity in the EU ETS in all trading periods. Our results further suggest that net buyers (companies whose verified emissions exceed free allocations in a given year) are more likely to participate in emissions trading and to trade at higher volumes than net sellers are. We explain this asymmetry in behaviour—which might lead to a violation of Coase’s independence property—by potential asymmetries in the actual or perceived opportunity costs of holding allowances between net sellers and net buyers.

This paper examines how enhanced flexibility across space, time, and a regulatory dimension affects the economic costs and CO2 emissions of integrating large shares of intermittent renewable energy from wind and solar. We develop a numerical model which resolves hourly dispatch and investment choices among heterogeneous energy technologies and natural resources in interconnected wholesale electricity markets, cross-country trade (spatial flexibility), energy storage (temporal flexibility), and tradable green quotas (regulatory flexibility). Taking the model to the data for the case of Europe’s system of interconnected electricity markets, we find that the appropriate combination of flexibility can bring about substantial gains in economic efficiency, reduce costs (up to 13.8%) and lower CO2 emissions (up to 51.2%). Regulatory flexibility is necessary to realize most of the maximum possible benefits. We also find that gains from increased flexibility are unevenly distributed and that some countries incur welfare losses.

Natural gas plays an important role in many European energy systems especially with regard to the envisioned transition towards a less carbon intensive energy supply. Being dependent on imports - especially from Russia - this raises questions about the future development and security of Europe's gas supply. Using a numerical network model of the European gas system we assess 1) the potential impact of infrastructure extensions for Europe's gas supply and 2) the role of supply security policies in coping with a disruption of Russian imports via the Ukraine. Our results indicate that overall the European gas infrastructure is sufficient for average market conditions. Due to the strong dependency on Russian imports, however, disruptions during the winter months could lead to load curtailment. Projected network extension (Southern Gas Corridor, Nord Stream 2, and new LNG terminals) or a strategic storage policy coordinated across Europe has the potential to reduce this shortage. The positive impact of an extended network, however, also depends on the capability of the global gas market to provide flexible gas that can be reallocated towards Europe. The majority of demand curtailment can already by countered by a relatively modest amount of strategic storage (20% to 30%) if their use during crisis situations is coordination across European countries.

This paper examines the efficiency and distributional impacts of introducing a price floor in an emissions trading system (ETS) when environmental regulation is partitioned. We theoretically characterize the conditions under which a price floor enhances welfare. Using a multi-country multi-sector numerical general equilibrium model of the European carbon market, we find that moderate minimum price levels in the EU ETS can reduce the costs of EU climate policy by up to thirty percent and yield outcomes close to uniform carbon pricing. Moreover, most of the EU Member States would gain. Our results are robust with respect to parametric uncertainty in production and consumption technologies.

This paper uses theoretical and numerical economic equilibrium models to examine optimal renewable energy (RE) support policies for wind and solar resources in the presence of a carbon externality associated with the use of fossil fuels. We emphasize three main issues for policy design: the heterogeneity of intermittent natural resources, budget-neutral financing rules, and incentives for carbon mitigation. We find that differentiated subsidies for wind and solar, while being optimal, only yield negligible efficiency gains. Policies with smart financing of RE subsidies which either relax budget neutrality or use “polluter-pays-the-price” financing in the context of budget-neutral schemes can, however, approximate socially optimal outcomes. Our analysis suggests that optimally designed RE support policies do not necessarily have to be viewed as a costly second-best option when carbon pricing is unavailable.

Mitigating climate change will require integrating large amounts of highly intermittent renewable energy (RE) sources in future electricity markets. Considerable uncertainties exist about the cost and availability of future large-scale storage to alleviate the potential mismatch between demand and supply. This paper examines the suitability of regulatory (public policy) mechanisms for coping with the volatility induced by intermittent RE sources, using a numerical equilibrium model of a future wholesale electricity market. We find that the optimal RE subsidies are technology-specific reflecting the heterogeneous value for system integration. Differentiated RE subsidies reduce the curtailment of excess production, thereby preventing costly investments in energy storage. Using a simple cost-benefit framework, we show that a smart design of RE support policies significantly reduces the level of optimal storage. We further find that the marginal benefits of storage rapidly decrease for short-term (intra-day) storage and are small for long-term (seasonal) storage independent of the storage level. This suggests that storage is not likely to be the limiting factor for decarbonizing the electricity sector.

Carbon taxes are commonly seen as a rational policy response to climate change, but little is known about their performance from an ex-post perspective. This paper analyzes the emissions and cost impacts of the UK CPS, a carbon tax levied on all fossil-fired power plants. To overcome the problem of a missing control group, we propose a novel approach for policy evaluation which leverages economic theory and machine learning techniques for counterfactual prediction. Our results indicate that in the period 2013-2016 the CPS lowered emissions by 6.2 percent at an average cost of € 18 per ton. We find substantial temporal heterogeneity in tax-induced impacts which stems from variation in relative fuel prices. An important implication for climate policy is that a higher carbon tax does not necessarily lead to higher emissions reductions or higher costs.

Supply security is a prominent and crucial notion which nds application in various economic sectors (energy security, food security, supply chain risks). Yet, it remains particularly dicult to dene and measure. Currently used indicators of supply security focus on narrow approaches and oer limited guidance to policy makers. Considering this, we propose a novel indicator assessing the supply security of industries, conceptually or physically, based on a network structure. The indicator is based on a simulation methodology and evaluates the reaction of the market to disruptions of its network services, thereby capturing the various dimensions of supply security. Subsequently, we perform an exemplary application onto the European natural gas market, and evaluate the impact of currently debated network extensions projects and policy measures.

The addition of stochastic renewable resources within modern electricity markets creates a need for more flexible generation assets and for appropriate mechanisms to ensure capacity adequacy. To assess both of these issues, more cross-platform analysis is needed that can evaluate short-term reliability concerns, medium-term dispatch and price concerns, and long-term capacity expansion and market design concerns. We present an integrated modeling framework that combines a long-term investment model, a robust dispatch model of the energy market, a detailed AC network model, a novel quantification for reserves, and a rigorous evaluation of renewable energy resource potentials. We apply the framework to a business-as-usual reference case simulating the phase-out of nuclear capacity in Switzerland and a case with renewable generation targets for Switzerland. We find that the nuclear phase-out leads to a strong increase in Swiss imports. In contrast, additional renewable targets lead to a decrease of these imports. In both cases, the Swiss cross-border lines are found to be the most critical network bottlenecks and in both future cases the increased reliance on imports worsens the severity of these bottlenecks. However, the network and security assessments show no significant challenges associated with a faster and stronger renewable increase in Switzerland.