Determinants of Total Factor Productivity in the Italian Regions

This paper investigates the determinants of TFP for Italian regions. We find strong evidence in favour of the factors commonly suggested by the theoretical literature. In particular, R&D expenditures and the number of researchers are positively related to regional TFP. Moreover, human capital is an important determinant of TFP. Finally, we find a strong difference between Northern and Southern regions, particularly regarding the effect of research activity and social capital. Our results are robust across different estimation methods.Total factor productivity, Italian regions, panel data, human capital, social capital

Forward price, renewables and the electricity price: The case of Italy

This paper investigates the determinants of the Italian electricity price (PUN) in order to determine the major challenges this market is currently facing. The results suggest that the policy maker should be aware that the importance of market expectations is increasing (captured in the model by the forward electricity price) and this may be used to understand and forecast the dynamics of spot prices. Second, the positive link between fuel prices and the Italian electricity price may lead to a greater exposure of the Italian electricity price to fluctuations in the international fuel markets. However the results show that the risks associated with higher fuel prices are partially mitigated by the presence of wind generation installed in the system

Decomposing patterns of emission intensity in the EU and China: how much does trade matter?. ESRI WP462. July 2013

This paper uses data from the World Input Output Database (WIOD) to examine channels through which CO2 emissions are embodied within and imported into the European production process. We apply a metric to calculate sectoral emission intensity and thus rank countries and sectors in the EU in terms of their emission intensity, and look at the evolution of patterns of emission intensity in 2005 and in 2009. We use an input-output price model to simulate the effect that a rise in the price of EU-ETS allowances, from $17 to$25 /tonne, would have on the final price of goods in each EU country and sector. We find that all countries in the EU reduced the emission-intensity of their production processes from 2005 to 2009, and we find that the reduction was greatest in those sectors regulated under the ETS. Comparisons of emission intensity between countries show that industries in Central and Eastern Europe are more emission intensive than those of Northern Europe, where industries import emission-intensive goods rather than producing them domestically. Finally we examine the trade in intermediate goods from China into the EU to examine possible increases in carbon leakage from 2005 to 2009. Results show that while emissions embodied in imported intermediate goods have increased from 2005 to 2009, this increase is not limited to, nor particularly notable in, the sectors regulated by the ETS

Carbon tax scenarios and their effects on the Irish energy sector

In this paper we use annual time series data from 1960 to 2008 to estimate the long run price and income elasticities underlying energy demand in Ireland. The Irish economy is divided into five sectors: residential, industrial, commercial, agricultural and transport, and separate energy demand equations are estimated for all sectors. Energy demand is broken down by fuel type, and price and income elasticitieis are estimated for the primary fuels in the Irish fuel mix. Using the estimated price and income elasticities we forecast Irish sectoral energy demand out to 2025. The share of electricity in the Irish fuel mix is predicted to grow over time, as the share of carbon intensive fuels such as coal, oil and peat, falls. The share of electricity in total energy demand grows most in the industrial and commercial sectors, while oil remains an important fuel in the residential and transport sectors. Having estimated the baseline forecasts, two different carbon tax scenarios are imposed and the impact of these scenarios on energy demand, carbon dioxide emissions, and government revenue is assessed. If it is assumed that the level of the carbon tax will track the futures price of carbon under the EU-ETS, the carbon tax will rise from €21.50 per tonne CO2 in 2012 (the first year forecasted) to €41 in 2025. Results show that under this scenario total emissions would be reduced by approximately 861,000 tonnes of CO2 in 2025 relative to a zero carbon tax scenario, and that such a tax would generate €1.1 billion in revenue in the same year. We also examine a high tax scenario under which emissions reductions and revenue generated will be greater. Finally, in order to assess the macroeconomic effects of a carbon tax, the carbon tax scenarios were run in HERMES, the ESRI's medium-term macroeconomic model. The results from HERMES show that, a carbon tax of €41 per tonne CO2 would lead to a 0.21 per cent contraction in GDP, and a 0.08 per cent reduction in employment. A higher carbon tax would lead to greater contractions in output

Carbon Tax Scenarios and their Effects on the Irish Energy Sector. ESRI WP407. September 2011

In this paper we use annual time series data from 1960 to 2008 to estimate the long run price and income elasticities underlying energy demand in Ireland. The Irish economy is divided into five sectors: residential, industrial, commercial, agricultural and transport, and separate energy demand equations are estimated for all sectors. Energy demand is broken down by fuel type, and price and income elasticitieis are estimated for the primary fuels in the Irish fuel mix. Using the estimated price and income elasticities we forecast Irish sectoral energy demand out to 2025. The share of electricity in the Irish fuel mix is predicted to grow over time, as the share of carbon intensive fuels such as coal, oil and peat, falls. The share of electricity in total energy demand grows most in the industrial and commercial sectors, while oil remains an important fuel in the residential and transport sectors

Are Renewables Profitable in 2030? A Comparison between Wind and Solar across Europe

The European Union has set ambitious targets for emission reduction and the penetration of renewable energy, including the electricity generation sector as one of the major emitters of CO2. After a period of subsidy-driven investments, the costs of renewables decreased strongly making investments more attractive. Since European countries differ strongly in terms of natural resources, we analyse the profitability of wind onshore and offshore and solar PV across Europe to determine where it is optimal to invest in the future and to understand which factors drive the profitability of the investments. We use a power systems model to simulate the whole European electricity market in 2030. Using the renewable revenues determined by the model, we calculate the internal rate of return to analyse how profitable each technology is in each country. We find that investments in the considered technologies are not homogeneously profitable across Europe. This suggests that cooperation between European countries can be expected to achieve the overall targets at lower costs than nationally-driven approaches. We also find that in many countries, wind onshore and solar PV are profitable by 2030 in absence of any financial support. Wind offshore does not seem to be profitable without financial support

Competition and the Single Electricity Market: Which Lessons for Ireland?. ESRI WP497. March 2015

This paper examines the redesign of the Irish Single Electricity Market in order to comply with the European Target Model for electricity. In particular, this work focuses on the challenges raised by the high concentration in the generation sector which exists in the Irish electricity market. We examine the theoretical and empirical conditions under which forward markets promote competition in the spot and retail markets; in addition, we investigate the impact of concentration in the market on the new capacity payment mechanism. In order to ensure a competitive outcome for consumers, the regulatory authorities should continue to regulate the directed forward contracts made by the dominant firm; moreover, our analysis suggests that the regulator should extend regulation to the price and quantity which the dominant firm bids for holding new reliability options

Wind, storage, interconnection and the cost of electricity

We evaluate how increasing wind generation affects whole sale electricity prices, balancing payments and the cost of subsidies using the Irish Single Electricity Market (SEM) as a test system, with hourly data from 1 January 2008 to 28 August 2012. We measure the effect of wind on the marginal cost of generating electricity using a system of seemingly unrelated regressions (SUR) where the regressions are the 24 hours of the day. Wind has a negative impact on the system marginal price. In particular, every MWh increase in wind generation (equal to about 0.2% of the average wind generation in our sample) leads to a decrease of the system marginal price of €0.018/MWh, or about 0.3% of its average value in our sample. Using time series models we show that wind generation increases balancing payments, as do the forecast errors of demand and wind. Lack of storage significantly increases the impact of wind on balancing payments whereas the lack of interconnection has no effect. Overall, wind decreases costs through its effect on the electricity price more than it increases constraint payments, even when storage is on outage. The effect of wind remains positive after including the subsidies given to wind generation

The Irish Electricity Market: New Regulation to Preserve Competition. ESRI Research Notes 2015/1/1

In the electricity sector there are two different markets: the wholesale (or spot) market, in which electricity generators generate and sell electricity at a new price every half hour, and the retail market, in which electricity supply companies sell electricity to the final consumers. Supply companies tend not to change the price they charge their consumers very frequently, and so these companies typically enter into longer-term contracts for electricity with generators to avoid the risks they would face if they bought at a new price every half hour. Internationally, many electricity markets also include a specific capacity payment mechanism, which ensures generators receive sufficient revenue to cover their fixed costs, thereby incentivising investment