Despite increasing fuel cost volatility, regulatory uncertainty, and imminent shifts to industry dynamics, utility managers are forced to make tough decisions in regards to installing long-life generation assets. This study seeks to identify and quantify determinants of fuel choice in new electric power plants given vast uncertainties in the electricity generation sector. Using a probit functional form to estimate marginal effects on the likelihood of choosing wind versus natural gas powered generation, I find positive effects of natural gas prices in the period three years prior to initial operation of the new facility, positive effects of static-level standard score of mix, and positive effects of wind-power density. Additional feedstock choice sets and parameters are considered. All models suggest that (a) feedstock costs are significant predictors of fuel choice, (b) state-level regulatory learning enhances likelihood of choosing relatively young technologies, (c) Renewable Portfolio Standards result in artificial substitution between wind and solar technologies, and (d) population density, more so than political influence, predicts choices to install wind-powered capacity. Public policy and managerial implications are discussed.

MBL 3 Research Report / This study investigated the economic significance of using bagasse as a source of raw material for pulp and paper manufacturing. The study also compared this issue with the currently undergoing practices of cogeneration, where bagasse is burnt in the sugar mill boilers to produce steam and generate electricity.

The document reviews the current and projected electricity demand until the year 2030 along with the fuel mix. Several projections based on different agencies were studied in order to understand the trend of fuel mix projected to be used. Clearly, the fuel mix being used or projected is unsustainable. Depletion of fossil fuels, increasing demand and environmental impacts are some of the factors that emphasize the use of Alternative Sources of Electricity. Three of the upcoming Alternative Sources - Solar, Wind and Landfill Gases - are discussed and compared in the document. Based on the comparison, Landfill Gas projects seem to be very favorable, despite the higher costs related with such projects, several advantages over the other two Alternative Sources are discussed in the document. The several advantages of Landfill Gas projects, such as emissions reduction, better power quality, reduction in transmission losses, and several others are discussed in the document

MSc, Faculty of Science, University of the Witwatersrand, 2011 / A growing interest is on the biological remediation of pollutants with the added benefit of generating electricity in microbial fuel cells (MFCs). Therefore, the analyses of suitability and potential of full-strength paper mill effluent and cheese whey were separately investigated in such devices. The most promising effluent was selected for biofilm optimization studies. In the biofilm buildup studies, anodes were enriched with microorganisms inherent to whey for a period between one and three months before their application in reactors. Independently, pre-incubated electrodes which were two-month-old were used serially in four MFCs of seven days each. In the preliminary study, the maximum power densities were 24 ± 3 mW/m2 (0.02 % coulombic efficiency − εcb) and 16.7 ± 1.8 W/m2 (εcb = 3.7 %) in paper mill effluent and whey, respectively. Following a three-month acclimation of whey anodophilic microbes, the power increased to 1 800 W/m2 (εcb = 80.9 %) and 92.8 % total chemical oxygen demand (tCOD) removal after a single batch cycle in MFCs. In anode recycling experiments, the operation was characterised by power of 390 ± 21 W/m2 (εcb = 0.25 %) in the third anode reuse; whilst the second reactor cycle had the highest tCOD removal (44.6 %). The anodophilic microbial species identified in cheese whey were from the Lactobacillus genus. This study concluded that wastes can supply fuel for power generation with simultaneous remediation; whey had greater potential than paper mill effluent; and both continual acclimation of inherent waste microbes and anode recycling improved the performance of MFCs.

[pt] O presente trabalho realiza uma comparação entre o ciclo Rankine tradicional e uma nova proposta de ciclo Rankine para uma planta de cogeração na indústria siderúrgica. O ciclo inovador é caracterizado por um sistema de regeneração por injeção direta de vapor seguida de bombeamento bifásico substituindo o uso de pré-aquecedores como no ciclo tradicional. Para a simulação dos ciclos de potência é empregado o Software Gate Cycle. São simuladas e estudadas diversas alternativas de configuração para a aplicação da nova tecnologia. A melhor alternativa de configuração do ciclo inovador é então comparada com o ciclo tradicional por meio da aplicação das análises de Primeira e Segunda Leis da Termodinâmica. Observou-se, entretanto, pouca diferença no desempenho do ciclo tradicional e do ciclo modificado. / [en] In the present work, a comparison between a traditional Rankine cycle and a proposed innovative Rankine cycle, for a cogeneration plant in the steel industry, is carried out. The innovative cycle is characterized by a regeneration system with direct steam injection followed by two-phase pumping, instead of the water pre-heaters used in the traditional cycle. Different configuration alternatives for the technology application were simulated and studied. The best alternative was then selected and compared with the traditional cycle using First and Second Laws of Thermodynamics analyses. Little difference was observed, however, between the traditional and the modified cycle performances.

The objective of this thesis is to provide a foundation for evaluating the water costs associated with electricity production to calculate the avoided water cost of energy for solar PV and wind technologies relative to coal, natural gas, nuclear, geothermal, concentrated solar thermal, and biomass. Water consumption is estimated for energy production (fuel extraction and preparation) and electricity generation (power plant operation) using the best available information from published articles. The quantity of water consumed for electricity production is monetized for a Southern California case study based on the water rates of Metropolitan Water District of Southern California (MET), which is the largest wholesale supplier of surface water in the United States. Water withdrawals are addressed but not included in the monetization of water consumption. Case studies of specific power plant’s water costs are used for comparison and demonstrate variation in water costs due to variations in water consumption. Water costs are estimated in terms of water cost ($) per unit energy generated (MWh). Since solar PV and wind energy are shown to have negligible water consumption relative to the other technologies, the water costs for each of the other electrical generation methods are equivalent to the water savings potential of solar PV and wind generated electricity. Compared to other evaluated electricity sources that could provide electricity to Southern California, solar PV and wind energy can save water worth $0.76/MWh for natural gas combined-cycle plants, $0.94/MWh for geothermal power plants, $1.01/MWh for biomass power plants, between $1.14 and $1.82 per MWh for concentrated solar thermal plants, $1.43/MWh for nuclear power plants, and $1.49/MWh for coal power plants. Results indicate that there are three processes that use substantial amounts of water: fuel extraction (for coal, natural gas, and nuclear), thermoelectric cooling of power plants and emissions controls such as carbon capture and sequestration. Carbon capture and sequestration are estimated to almost double the water consumption costs of coal and natural gas power plants. Of the evaluated technologies, only solar PV and wind do not require any of those three steps. Solar PV and wind energy can thus save the greatest value of water when displacing power plants that utilize (or may someday be required to utilize) all three of the major culprits of water consumption. Even the use of one of these processes (particularly thermoelectric cooling) results in substantial water consumption. Total water costs for each technology were normalized to the total expected electrical output of a typical capacity natural gas combined-cycle power plant to demonstrate the economies of scale of power production. Over a forty year lifespan of a typical natural gas power plant, total water consumption would result in $67 million worth of water (southern CA wholesale prices). To generate the same amount of electricity the total value of water consumption is estimated to be $83 million for geothermal plants, $89 million for biomass plants, $100 million to $160 million for concentrated solar thermal plants, $126 million for nuclear plants, and $131 million for coal power plants. The use of carbon capture and sequestration is expected to nearly double these total water costs. Compliance with environmental regulations can cause expenses much greater than water consumption. For example, mitigation costs for impingement and entrainment (a consequence of cooling water withdrawals) as well as the cost to convert to closed-loop cooling for environmental compliance can be considered costs associated with water usage. This is demonstrated by a case study about the Los Angeles Department of Water and Power regarding the elimination of once through cooling. The conversion to closed-loop cooling for the Haynes natural gas power plant is expected to cost $782 million, resulting in an estimated unit cost of $10.66/MWh. Finally, the economic benefits of the California Renewables Portfolio Standard are calculated with respect to water consumption. By holding hydroelectricity, geothermal, biomass and CST production constant and utilizing solar PV and wind to meet the 33% renewables target by 2020, a water value of $28.5 million/year can be conserved relative to meeting rising electricity demand with only natural gas combined-cycle generation. MET water rates increased 70% from 2008 to 2014. If water rates increase at the same rate over the next six years, the water savings of the Renewable Portfolio Standard would be 70% higher in 2020 dollars, equating to water savings of $48.4 million per year.

No description available.

The electricity system is particularly susceptible to climate change due to the close interconnectedness between not only electricity production and consumption to climate, but also the interdependence of many European countries in terms of electricity imports and exports. This study provides a country based relative analysis of a number of selected European countries’ electricity system vulnerability to climate change. Taking into account a number of quantitative influencing factors, the vulnerability of each country is examined both for the current system and using some projected data. Ultimately the result of the analysis is a relative ranked vulnerability index based on a number of qualitative indicators. Overall, countries that either cannot currently meet their own electricity consumption demand with inland production (Luxembourg), or countries that experience and will experience the warmest national mean temperatures, and are expected to see increases in their summer electricity consumption are found to be the most vulnerable for example Greece and Italy. Countries such as the Czech Republic, France and Norway that consistently export surplus electricity and will experience decreases in winter electricity consumption peaks were found to be the least vulnerable to climate change. The inclusion of some qualitative factors however may subject their future vulnerability to increase. The findings of this study enable countries to identify the main factors that increase their electricity system vulnerability and proceed with adaptation measures that are the most eective in decreasing vulnerability.

This thesis examines the private and external costs of electricity generated in Ontario by natural gas, wind, refurbished nuclear and new nuclear power. The purpose of the assessment is to determine a capacity expansion plan that meets the forecasted electricity supply gap in Ontario at the lowest social costs (i. e. the lowest aggregated private and external costs). A levelized unit electricity cost (LUEC) analysis is employed to evaluate private costs under both public and merchant perspectives. Computable external costs are monetized by adapting estimates from the literature that were previously developed using a primarily bottom-up damage cost method. <br /><br /> The findings reveal that social cost estimates for nuclear refurbishment are the lowest of the generation alternatives studied regardless of the evaluation perspective. Therefore, if the capacity expansion decision were based solely on these estimates, nuclear refurbishment should be utilized until its capacity constraints are reached. The generation alternative with the second lowest social costs depends on the perspective from which private costs are evaluated: from a public perspective, the remainder of the supply gap should be filled by new nuclear generation and from a merchant perspective, which is assumed to be more reflective of the current Ontario electricity market, natural gas-fired generation should be used. <br /><br /> Due to inherent uncertainty and limitations associated with the estimation of social costs, the estimates obtained in this thesis are considered to be context and data specific. A sensitivity analysis, which is employed to attempt to mitigate some of the uncertainty, shows that changes to key variables alter the capacity expansion plan. This reinforces the observation that methods and assumptions significantly affect social cost estimates. <br /><br /> Despite the limitations of this kind of evaluation, it is argued that a social cost assessment that is consistent, transparent and comprehensive can be a useful tool to assess the trade-offs of electricity generation alternatives if used along with existing evaluation criteria. Such an assessment can increase the likelihood that actual social costs are minimized, which can steer electricity generation in Ontario towards a system that is more efficient and sustainable.

The focus of this thesis is to explore a new mechanism to give added incentive to invest in new capacities in deregulated electricity markets. There is a lot of concern in energy markets, regarding lack of sufficient private sector investment in new capacities to generate electricity. Although some markets are using mechanisms to reward these investments directly, e.g., by governmental subsidies for renewable sources such as wind or solar, there is not much theory to guide the process of setting the reward levels. The proposed mechanism involves a long term planning model, maximizing the social welfare measured as consumers’ plus producers’ surplus, by choosing new generation capacities which, along with still existing capacities, can meet demand. Much previous research in electricity capacity planning has also solved optimization models, usually with continuous variables only, in linear or non-linear programs. However, these approaches can be misleading when capacity additions must either be zero or a large size, e.g., the building of a nuclear reactor or a large wind farm. Therefore, this research includes binary variables for the building of large new facilities in the optimization problem, i.e. the model becomes a mixed integer linear or nonlinear program. It is well known that, when binary variables are included in such a model, the resulting commodity prices may give insufficient incentive for private investment in the optimal new capacities. The new mechanism is intended to overcome this difficulty with a capacity price in addition to the commodity price: an auxiliary mathematical program calculates the minimum capacity price that is necessary to ensure that all firms investing in new capacities are satisfied with their profit levels. In order to test the applicability of this approach, the result of the suggested model is compared with the Ontario Integrated Power System Plan (IPSP), which recommends new generation capacities, based on historical data and costs of different sources of electricity generation for the next 20 years given a fixed forecast of demand.