Explore the vast range of titles available.

Tajikistan's electricity system is in a state of crisis. Approximately 70 percent of the Tajik people suffer from extensive shortages of electricity during the winter. These shortages, estimated at about 2,700 GWh, about a quarter of winter electricity demand, impose economic losses estimated at over United States (US) 200 million dollars per annum or 3 percent of Gross Domestic Product (GDP). The electricity shortages have not been addressed because investments have not been made in new electricity supply capacity and maintenance of existing assets has not improved. The financial incentive for electricity consumers to reduce their consumption is inadequate as electricity prices are among the lowest in the world. Without prompt action to remedy the causes of Tajikistan's electricity crisis and with growing demand, the shortages could increase to about 4,500 GWh by 2016 (over a third of winter electricity demand) or worse. The World Bank undertook this study to assist the Government of Tajikistan (GoT) in finding ways to overcome the current electricity shortages and establish a sound basis for meeting the growing electricity demand in Tajikistan. The study focuses on the investments and policy reforms needed between now and 2020 to strengthen the financial, technical and institutional capacity of the Tajik power sector and prepare the GoT for undertaking a major expansion of power supply capacity. The study excludes large hydropower plants with storage, given their complexity and global experience that such projects are subject to delays. The winter electricity shortages are caused by a combination of low hydropower output during winter when river flows are low and high demand driven by heating needs. The GoT should focus its immediate attention on three ways to eliminate the current winter power shortages: 1) ambitious energy efficiency plans to reduce uneconomic power usage; 2) new dual-fired thermal power supply to complement the existing hydropower supply during winter; and 3) increased energy imports to leverage surplus electricity supply in neighboring countries.

This paper presents a methodology to estimate the Levelized Avoided Cost of Electricity (LACE) of new generation projects based on the assessment of economic and operational benefits perceived by an existing power system. The marginal economic benefit caused by the integration of a new generation project is captured using the Differential Revenue Requirement method (DRR); whereas the operational benefits are observed by analyzing the performance of the new project through a preventive DC Security-Constrained Optimal Power Flow (SCOPF) tool. The SCOPF also allows quantifying economic benefits due to replacement of expensive generation, transmission congestion, and N-1 security improvement. Additionally, another metric, called Net Benefit (NB) of a generation project, expressed as the difference between LACE and LCOE (Levelized Cost of Electricity) is also employed in this work. It provides a realistic, easy-to-compute, and intuitive index that helps identifying the most promising generation projects during system expansion planning procedures. Finally, the proposed methodology is applied for computing LACE and NB of different generation projects in Colombia. According to the results, geothermal projects display the most significant LACE and NB. These metrics (LACE and NB) can become useful tools for decision-making in planning process.

Conventional sources of electricity are limited and they pollute the Earth, so it is necessary to think about an additional source of electricity in the future. Nuclear power is one of the options. Two scenarios using different shares of nuclear power in the future are described in this paper. Scenario 1 describes a moderate increase in nuclear energy use in the future, but with a tendency for a larger increase over 2050. Scenario 2 describes a significant increase in nuclear energy until 2100. Both scenarios are divided into three sub-scenarios (total six) in which the use of different nuclear technologies is analyzed (conventional liquid water reactors, fast breeder reactors and molten salt reactors using thorium as nuclear fuel). In all scenarios, the phase-out of fossil fuel power plants is assumed. One part of the power system is covered by nuclear power plants, and the remaining part is covered by renewable energy power plants. After 2050, an increasing share of the electricity system will be taken over by RES power plants. Nuclear fuel stocks are also analyzed. It is calculated that currently known nuclear fuel stocks are sufficient to meet the needs in all six scenarios. The carbon dioxide emissions saved due to nuclear energy use instead of conventional energy power plants are calculated. The CO2eq emission savings for Scenario 1 is 87.4% of the recommended emission savings under the IPCC. The CO2eq emission savings for Scenario 2 is more than sufficient. A calculation of the economic profitability of nuclear energy use is made in relation to fossil power plants and renewable energy power plants. According to calculations, nuclear energy is profitable compared to other energy sources. Nuclear energy use is positive from all the mentioned aspects.

The mass introduction of variable renewable energies, including wind and solar photovoltaic, leads to additional costs caused by the intermittency. Many recent studies have addressed these “integration costs,” and proposed novel metrics that replace the traditional metric known as the levelized cost of electricity (LCOE). However, the policy relevance of those metrics remains unclear. In this study, the author investigates and re-defines the concept of system LCOE, referring to prior studies, and proposes concrete methods to estimate them. Average system LCOE allocates the integration cost to each power source, dividing that by the adjusted power output. Marginal system LCOE revises the concept of system LCOE and value-adjusted LCOE proposed by prior studies, to be clearer and more policy-relevant. These metrics are also applied to Japan’s power sector in 2050, suggesting the necessity of aiming for a “well-balanced energy mix” in future power systems with decarbonised power sources.

Background In an attempt to realize the most beneficial and optimal mix of electricity generation in Niger, a society’s cost of electricity (SCOE) as the levelized cost of electricity (LCOE) plus the cost of climate change and air pollution is formulated. The SCOE is used as a basis for setting the performance criteria for supply optimization to balance future electricity demand in Niger. The demand projection is derived from a system dynamics model that anticipates future changes based on its influencing factors of population growth, urbanization progress, and industrial development. Results Reference case and what-if scenarios are simulated to see the projected electricity demand and possible renewable energy transition pathways. As a result, for example, the annual electricity of 3214 GWh estimated for 2030 might be balanced with about 200 MW, 104 MW, 85 MW, and 63 MW power from hydropower, grid-tied PV, coal, and diesel for SCOE optimized grid. For the same case, a greenhouse gas (GHG) emission reduction of 11.26–15.66% could be achieved when compared to the LCOE-based optimized grid. In addition, the most preferred energy option hydropower will be almost exhausted when the projected electricity demand in 2035 reaches slightly more than double its value in 2025. Thus, Niger should start exploiting its solar as well as conventional sources intensively to balance its future energy demand. Conclusions In this work, a mixed energy grid is optimized primarily on affordability while considering its sustainability. The implemented holistic approach lessens the need for energy import in the country and provides relief to energy security issues such as electricity price volatility and supply reliability. Additionally, the proposed strategy helps to guide the renewable energy transition pathway in Niger.

In this study, a novel system which integrates solar thermal energy with membrane gas absorption technology is proposed to capture CO2 from a 580 MWe pulverized coal power plant. Technical feasibility and economic evaluation are carried out on the proposed system in three cities with different solar resources in China. Research results show that the output capacity and net efficiency of the SOL-HFMC power plant are significantly higher than those of the reference power plant regardless of whether a TES system is applied or not. In addition, the CEI of the SOL-HFMC power plant with the TES system is 4.36 kg CO2/MWh, 4.45 kg CO2/MWh and 4.66 kg CO2/MWh lower than that of the reference power plant. The prices of the membrane, vacuum tube collector and phase change material should be reduced to achieve lower LCOE and COR values. Specifically for the SOL-HFMC power plant with the TES system, the corresponding vacuum tube collector price shall be lower than 25.70$/m2 for Jinan, 95.20 $ /m2 for Xining, and 128.70$/m2 for Lhasa, respectively. To be more competitive than a solar-assisted ammonia-based post-combustion CO2 capture power plant, the membrane price in Jinan, Xining and Lhasa shall be reduced to 0.012 $ /m, 0.015$/m and 0.016 $ /m for the sake of LCOE, and 0.03$/m, 0.033 $ /m and 0.034 $/m for the sake of COR, respectively.

Moving to 100% renewables scenario in EU requires huge support to renewable energy technologies, however this support needs to integrate positive externalities of renewables, therefore it is important to analyse dynamics of external costs of electricity generation in Visegrad countries and to compare them with support allocated to renewable energy sources in these countries. Therefore, the paper aims to compare the Visegrad countries in terms of reduction of external electricity generation costs due to increased share of renewables in electricity generation and the government support provided for renewables. ExternE methodology and CASES database is applied in this research. The results of study provide guidance for policy makers with regards to promotion of RES for achieving low-carbon energy transition by 2050.

To satisfy Jordan’s growing demand for electricity and to diversify its energy mix, the Jordanian government is considering a number of electricity-generation technologies that would allow for locally available resources to be used alongside imported energy. Energy policy in Jordan aims to address both climate change mitigation and energy security by increasing the share of low-carbon technologies and domestically available resources in the Jordanian electricity mix. Existing technological alternatives include the scaling up of renewable energy sources, such as solar and wind; the deployment of nuclear energy; and shale oil exploration. However, the views, perceptions, and opinions regarding these technologies—their benefits, risks, and costs—vary significantly among different social groups both inside and outside the country. Considering the large-scale policy intervention that would be needed to deploy these technologies, a compromise solution must be reached. This paper is based on the results of a four-year research project that included extensive stakeholder processes in Jordan, involving several social groups and the application of various methods of participatory governance research, such as multi-criteria decision-making. The results show the variety of opinions expressed and provide insights into each type of electricity-generation technology and its relevance for each stakeholder group. There is a strong prevalence of economic rationality in the results, given that electricity-system costs are prioritized by almost all stakeholder groups.

Economic feasibility studies of concentrated solar power (CSP) plants with thermal energy storage (TES) systems have been mainly based on the levelized cost of electricity (LCOE), disregarding the economic benefits to the electricity system resulting from the dispatchability of the CSP plants. The analysis of these benefits is essential since the existence of storage can provide greater operating flexibility to the system. Although there are few studies on the benefits of CSP plants in thermoelectric systems, this analysis has not yet been done in a predominantly hydroelectric system. In this paper, CSP plants with TES systems were inserted in a hydrothermal system in order to estimate the economic benefits and the net cost of electricity generated by those plants. The System Advisor Model (SAM) and the hydrothermal scheduling model DESSEM were used in a real case study of inclusion of CSP plants in the Brazilian system. The results indicate that the cost of a CSP plant, previously estimated by the LCOE, can be reduced by at least 37% when considering its benefits to a hydrothermal system, increasing its competitiveness with other technologies. Therefore, we propose the use of the net cost for an appropriate comparison among energy sources.

A solar thermal wind tower (STWT) is a low-temperature power generation plant that mimics the wind cycle in nature, comprising a flat plate solar air collector and central updraft tower to produce thermal wind that drives turbines to generate electricity. The development of power generation systems toward a sustainable future needs to be made taking into account the balance between environmental impact and economic feasibility. We examine the sustainability of STWT power generation technology using the inclusive impact index light (Triple I-light), which estimates whether it is good to do the project, including both the negative environmental impact and the economic aspect. Environmental disadvantages are discussed by performing a CO2 inventory analysis for the life-cycle of the STWT power plant. Evaluation of the economic feasibility is done by calculating the levelized electricity cost (LEC), which is the cost per unit of electricity generated. From the calculations, it is found that overall system efficiency is increased by enlarging the capacity, the negative environmental impact by the STWT plant comes mainly from manufacturing stage (more than 60%), and the levelized electricity cost is dramatically decreased by enlarging the capacity of the system (about 50% reduction). A negative value of Triple I (meaning it is sustainable) can be achieved for high power generation capacity (above 100 MW). Moreover, this paper discusses the implementation and the potential of constructing offshore STWTs.