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Many governments who preside over liberalised energy markets are developing policies aimed at promoting investment in renewable generation whilst maintaining the level of security of supply customers have come to expect. Of particular interest is the mix and amount of generation investment over time in response to policies promoting high penetrations of variable output renewable power such as wind. Modelling the dynamics of merchant generation investment in market environments can inform the debate. Such models need improved methods to calculate expected output, costs and revenue of thermal generation subject to varying load and random independent thermal outages in a power system with high penetrations of wind. This paper presents a dynamic simulation model of the aggregated Great Britain (GB) generation investment market. The short-term energy market is simulated using probabilistic production costing based on the Mix of Normals distribution technique with a residual load calculation (load net of wind output). Price mark-ups due to market power are accounted for. These models are embedded in a dynamic model in which generation companies use a Value at Risk (VaR) criterion for investment decisions. An `energy-only' market setting is used to estimate the economic profitability of investments and forecast the evolution of security of supply. Simulated results for the GB market case study show a pattern of increased relative security of supply risk during the 2020s. In addition, fixed cost recovery for many new investments can only occur during years in which more frequent supply shortages push energy prices higher. A sensitivity analyses on a number of key model assumptions provides insight into factors affecting the simulated timing and level of generation investment. This is achieved by considering the relative change in simulated levels of security of supply risk metric such as de-rated capacity margins and expected energy unserved. The model can be used as a decision support tool in policy design, in particular how to address the increased `energy-only market revenue risk facing thermal generation, particularly peaking units, that rely on a small number of high price periods to recover fixed costs and make adequate returns on investment.

As power systems evolve to incorporate greater penetrations of variable renewables, the demand for flexibility within the system is increased. Combined-cycle gas turbines are traditionally considered as relatively inflexible units, but those which incorporate a steam bypass stack are capable of opencycle operation. Facilitating these units to also operate in opencycle mode can benefit the power system via improved system reliability, while reducing the production needed from dedicated peaking units. The utilization of the multi-mode functionality is shown to be dependent on the flexibility inherent in the system and the manner in which the system is operated. Science Foundation Ireland Other funder Charles Parsons Energy Research Awards Wrong bibliographical details: see doi 10.1109/TPWRS.2011.2163649 and http://ieeexplore.ieee.org/xpls/abs_all.jsp?arnumber=6006567 - AV 27/9/2011

Large-scale deployment of renewable energy technologies, such as wind power and solar energy, has been taking place in industrialized and developing economics mainly because of various fiscal and regulatory policies. An understanding of the economy-wide impacts of those policies is an important part of an overall analysis of them. Using a perfect foresight computable general equilibrium model, this study analyzes the economy-wide costs of achieving a 10 percent share of wind power in Brazil’s electricity supply mix by 2030. Brazil is in the midst of an active program of wind capacity expansion. The welfare loss would be small, 0.1 percent of total baseline welfare in the absence of the 10 percent wind power expansion. The study also finds that, in the case of Brazil, production subsidies financed through increased value-added tax would have superior impacts on welfare and greenhouse gas mitigation, compared with a consumption mandate where electricity utilities are allowed to pass the increased electricity supply costs directly to consumers. These two policies would impact various production sectors differently to achieve the wind power expansion targets: the burden of the mandate falls mostly on electricity-intensive production and consumption, whereas the burden of the subsidy is distributed toward goods and services with higher value added.

Many governments who preside over liberalised energy markets are developing policies aimed at promoting investment in renewable generation whilst maintaining the level of security of supply customers have come to expect. Of particular interest is the mix and amount of generation investment over time in response to policies promoting high penetrations of variable output renewable power such as wind. Modelling the dynamics of merchant generation investment in market environments can inform the debate. Such models need improved methods to calculate expected output, costs and revenue of thermal generation subject to varying load and random independent thermal outages in a power system with high penetrations of wind. This paper presents a dynamic simulation model of the aggregated Great Britain (GB) generation investment market. The short-term energy market is simulated using probabilistic production costing based on the Mix of Normals distribution technique with a residual load calculation (load net of wind output). Price mark-ups due to market power are accounted for. These models are embedded in a dynamic model in which generation companies use a Value at Risk (VaR) criterion for investment decisions. An `energy-only' market setting is used to estimate the economic profitability of investments and forecast the evolution of security of supply. Simulated results for the GB market case study show a pattern of increased relative security of supply risk during the 2020s. In addition, fixed cost recovery for many new investments can only occur during years in which more frequent supply shortages push energy prices higher. A sensitivity analyses on a number of key model assumptions provides insight into factors affecting the simulated timing and level of generation investment. This is achieved by considering the relative change in simulated levels of security of supply risk metric such as de-rated capacity margins and expected energy unserved. The model can be used as a decision support tool in policy design, in particular how to address the increased `energy-only market revenue risk facing thermal generation, particularly peaking units, that rely on a small number of high price periods to recover fixed costs and make adequate returns on investment.

Certain developments in the electricity sector may result in suboptimal operation of base-load generating units in countries worldwide. Despite the fact they were not designed to operate in a flexible manner, increasing penetration of variable power sources coupled with the deregulation of the electricity sector could lead to these base-load units being shut down or operated at part-load levels more often. This cycling operation would have onerous effects on the components of these units and potentially lead to increased outages and significant costs. This paper shows the serious impact increasing levels of wind power will have on the operation of base-load units. Those base-load units which are not large contributors of primary reserve to the system and have relatively shorter start-up times were found to be the most impacted as wind penetration increases. A sensitivity analysis shows the presence of storage or interconnection on a power system actually exacerbates base-load cycling until very high levels of wind power are reached. Finally, it is shown that if the total cycling costs of the individual base-load units are taken into consideration in the scheduling model, subsequent cycling operation can be reduced. Science Foundation Ireland Electricity Research Centre (ERC) Industry Members Publisher version at http://dx.doi.org/10.1109/TPWRS.2009.2037326. DG 07/07/10 ke - AL 23/07/2010

The rapid growth of Vietnam's economy, industry, and consumption has resulted in unprecedented growth in energy demand, and its infrastructure for extracting, generating, and distributing energy is expanding to try to meet those needs. Between 2000 and 2005, total primary energy consumption in Vietnam grew 10.6 percent per year. Growth in fossil-fuel consumption was correspondingly high, with coal use growing at 14.9 percent per year, oil use at 8.2 percent per year, and natural gas use at 37 percent per year. From 2002 to 2030, Vietnam's primary energy demand is expected to grow at a rate of 4.4 percent, increasing from 42 megatons oil equivalent (MTOE) in 2002 to 142 MTOE in 2030. This note will focus on Vietnam's potential Greenhouse gas (GHG) emission reductions and possible interventions associated with resource extraction and power generation for grid electricity. Emissions from power generation in industry and transport are covered under the respective sector notes, and reduction of greenhouse gases through management of end-use demand is covered in the context of industry (as the largest energy user) in the industry sector note.