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Interconnections for cross-border electricity trade improve price convergence and welfare. Increased production from variable renewables however implies higher levels of optimal interconnection capacity than in the past. Rather than using scenario building to determine new optimal levels of interconnection capacity, this paper presents a new methodology for Cost-Benefit Analysis (CBA) based on empirical market data, using the French-German electricity trade as an example. Employing a very fine dataset of hourly supply and demand curves (aggregated auction curves) from the EPEX Spot market, it constructs net export (NEC) and net import demand curves (NIDC) for both countries. This allows assessing hourly welfare impacts for incremental capacity and, summed over the year, the annual welfare benefits for each discrete increase in interconnection capacity. Confronting benefits with the annualised costs of increasing interconnection capacity determines the socially optimal increase in interconnection capacity between France and Germany on the basis of empirical market micro-data. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

This paper evaluates the energy efficiency of EU countries over the period 2000-2010. At the first stage, data envelopment analysis (DEA) is used, combining multiple energy consumption data and economic outputs. The efficiency estimates obtained from the analysis are evaluated in a second stage through a multiple criteria decision aiding methodology (MCDA). The proposed non-parametric approach combining DEA with MCDA enables modeling of the problem in an integrated manner, not only providing energy efficiency estimates but also supporting the analysis of the main contributing factors, as well as the development of a benchmarking model for energy efficiency evaluation at the country level. [ABSTRACT FROM AUTHOR]

This study analyzes the relationship between the energy efficiency and the stringency of environmental and market regulation in the electricity sectors has been analyzed. Using 19 European Union countries (2006-2014), we decomposed the environmental policy stringency index, the OECD regulatory indicators and the total factor productivity growth to highlight the complexity of the relations between electricity sector and regulatory policies. In the first stage we compute the three main components of total factor productivity. These three efficiency measures are used in the second stage to assess the impact of the regulatory policies on the total factor productivity also controlling for spatial effect. Results suggest that market and environmental regulations have not unidirectional impacts on the three components of total factor productivity. Pure and scale efficiency index are negatively affected by sectorial regulation that positively affect the shift of technological frontier. Environmental policy negatively affects the shift of the efficient frontier, but has a positive effect on the scale efficiency. [ABSTRACT FROM AUTHOR]

One of the major questions related to renewable energy systems is whether we are approaching solar grid parity or not. Solar based power generation will play an important role in future sustainable energy mixes due to its high reliability, yield predictability and capacity for electricity production during peak demand when the electricity price is usually high. But nowadays the economic viability of these technologies depends on the subsidies usually granted, mainly by public authorities, and in a minor way by electricity producers. The article evaluates the potential of solar energy based technologies for viable electricity generation, focusing on Photovoltaics (PV) and Concentrated Solar Power (CSP) systems. The evaluation was not only focused on EU but also covered global markets, assessing the necessary barriers and thresholds preventing or boosting these technologies to reach grid parity. The observed rapid growth in deployment of the studied technologies (especially PV) in recent years is largely policy-driven and whether this trend will be sustainable depends on whether governments will continue to expand financial incentives and policy mandates, as well as address regulatory and market barriers. [ABSTRACT FROM AUTHOR]

We analyze incentives to invest in renewable energy technologies induced by the overlap of two types of policies: feed-in schemes and carbon mitigation instruments. We find that results differ markedly depending on the specific types of policies in place, reflecting different impacts of uncertainty. As a result, the recent reform to the EU-ETS system that has established the Market Stability Reserve (MSR), effective in 2019, requires to appropriately fine-tune the direct RES-E support schemes. We show that this may involve moving away from feed-in tariffs towards feed-in premia. Our results suggest that the schemes currently adopted in Germany and in Italy, broadly based on feed-in premia for large generators and on feed-in tariffs for the small ones, could well fit also the post-MSR EU carbon mitigation policy. To the contrary, other countries (e.g. France and the U.K.) may have to modify their support schemes as the MSR will become operational. [ABSTRACT FROM AUTHOR]

While the 2009 EU Renewables Directive allows countries to purchase some of their obligation from another member state, no country has yet done so, preferring to invest locally even where load factors are very low. If countries specialised in renewables most suited to their own endowments and expanded international trade, we estimate that system costs in 2030 could be reduced by 5%, or €15 billion a year, after allowing for the costs of extra transmission capacity, peaking generation and balancing operations needed to maintain electrical feasibility. Significant barriers must be overcome to unlock these savings. Countries that produce more renewable power should be compensated for the extra cost through tradable certificates, while those that buy from abroad will want to know that the power can be imported when needed. Financial Transmission Rights could offer companies investing abroad confidence that the power can be delivered to their consumers. They would hedge short-term fluctuations in prices and operate much more flexibly than the existing system of physical point-to-point rights on interconnectors. Using FTRs to generate revenue for transmission expansion could produce perverse incentives to under-invest and raise their prices, so revenues from FTRs should instead be offset against payments under the existing ENTSO-E compensation scheme for transit flows. FTRs could also facilitate cross-border participation in capacity markets, which are likely to be needed to reduce risks for the extra peaking plants required. [ABSTRACT FROM AUTHOR]

We estimate the relationship between electricity, fuel and carbon prices in Germany, France, the Netherlands, the Nord Pool market and Spain, using one-year futures for base and peakload prices for the years 2008-2011, corresponding to physical settlement during the second market phase of the EU ETS. We employ a series of estimation methods that allow for an increasing interaction between electricity and input prices on the one hand, and between electricity markets on the other. The results vary by country due to different generation portfolios. Overall, we find that (a) carbon costs are passed through fully in most countries; (b) under some model specifications, cost pass-through is higher during peakload than during baseload for France, Germany and the Netherlands; and (c) the results are sensitive to the degree of cross-commodity and cross-market interaction allowed. [ABSTRACT FROM AUTHOR]