Economic perspective of PV electricity in Oman

Solar and wind energies are likely to play an important role in the future energy generation in Oman. This paper utilizes average daily global solar radiation and sunshine duration data of 25 locations in Oman to study the economic prospects of solar energy. The study considers a solar PV power plant of 5-MW at each of the 25 locations. The global solar radiation varies between slightly greater than 4 kWh/m²/day at Sur to about 6 kWh/m²/day at Marmul while the average value in the 25 locations is more than 5 kWh/m²/day. The results show that the renewable energy produced each year from the PV power plant varies between 9000 MWh at Marmul and 6200 MWh at Sur while the mean value is 7700 MWh of all the 25 locations. The capacity factor of PV plant varies between 20% and 14% and the cost of electricity varies between 210 US$/MWh and 304 US$/MWh for the best location to the least attractive location, respectively. The study has also found that the PV energy at the best location is competitive with diesel generation without including the externality costs of diesel. Renewable energy support policies that can be implemented in Oman are also discussed.     

The impact of Production Tax Credits on the profitable production of electricity from wind in the U.S.

A spatial financial model using wind data derived from assimilated meteorological condition was developed to investigate the profitability and competitiveness of onshore wind power in the contiguous U.S. It considers not only the resulting estimated capacity factors for hypothetical wind farms but also the geographically differentiated costs of local grid connection. The levelized cost of wind-generated electricity for the contiguous U.S. is evaluated assuming subsidy levels from the Production Tax Credit (PTC) varying from 0 to 4 ¢/kWh under three cost scenarios: a reference case, a high cost case, and a low cost case. The analysis indicates that in the reference scenario, current PTC subsidies of 2.1 ¢/kWh are at a critical level in determining the competitiveness of wind-generated electricity compared to conventional power generation in local power market. Results from this study suggest that the potential for profitable wind power with the current PTC subsidy amounts to more than seven times existing demand for electricity in the entire U.S. Understanding the challenges involved in scaling up wind energy requires further study of the external costs associated with improvement of the backbone transmission network and integration into the power grid of the variable electricity generated from wind.     

Internalizing externalities into capacity expansion planning: The case of electricity in Vietnam

This paper examines the impacts of including external costs such as environmental and health damages from power production on power generation expansion planning in Vietnam. Using the MARKAL model and covering a 20-year period to 2025, the study shows that there are substantial changes in the generation structure in favor of renewable energy technologies and other low emitting technologies. These changes lead to a reduction in fossil fuel requirements, and consequently, a reduction of CO₂, NO_x, SO₂, and PM emissions which could be expected to also reduce the associated environmental and human health impacts. The avoided external costs would be equivalent to 4.4 US cent/kWh. However, these gains are not free as the additional electricity production cost would be around 2.6 US cent/kWh higher if the switch to more expensive, but lower emitting technologies were made. The net benefit of internalizing these externalities is thus around 1.8 US cent/kWh.     

Economic feasibility of electricity production from energy plantations present on community-managed forestlands in Madhya Pradesh,India

This paper assesses economic feasibility of utilizing community-managed degraded forest areas for raising energy crops and using the produced biomass for electricity production in the state of Madhya Pradesh, India through gasification technology. Three fast-growing species, three gasifiers of different capacities, three capital costs, and two scenarios of carbon payments were considered for analysis. Sensitivity and risk analyses were undertaken for determining the effects of variations in inputs on selected outputs. Results suggest that 5 million megawatt hour electricity can be generated annually which will prevent 4 million tons of carbon dioxide emissions per year. The production cost of a unit of electricity was found inversely related to the scale of production. The average cost of electricity at the consumer level produced using 100 kW gasifier was $0.15/kWh, which was greater than the price of electricity supplied from grid i.e. $0.08/kWh. The unit cost of producing electricity using Acacia nilotica was lowest among all the selected species. Technological advancements suitable government incentives are needed to promote electricity generation from forest biomass through gasification technology. This will help in spurring economic development and reducing overall ecological footprint of the state.     

Supply amount and marginal price of renewable electricity under the renewables portfolio standard in Japan

The Renewables Portfolio Standard (RPS) in Japan requires that approximately 1.35% of each retail supplier's electricity sales in FY2010 come from renewable energy sources (RES), for example, photovoltaics, wind, biomass, geothermal, and small hydropower. To help retail suppliers and renewable generators develop effective strategies, this study provides a quantitative analysis of the impact of this measure. We assume the supply conditions for electricity generation from renewable energy sources (RES-E) based on regional resource endowments, and we derive the cost-effective compositions of renewable portfolios, RES-E certificate prices, and additional costs to retail suppliers. The future prospects of RES-E are assessed based on technology, region, and year up to FY2010. The analysis reveals that wind power and biomass power generated from municipal waste will provide the majority of the total supply of RES-E under the RPS. It also indicates that the marginal price of RES-E certificates will be approximately 5.8 JPY/kWh (5.2 USc/kWh) in FY2010, in the case wherein the marginal price of electricity is assumed to be 4 JPY/kWh (3.6 USc/kWh). In order to elaborate on this further, sensitivity analyses for some parameters of RES and the price of electricity are provided. The dynamic supply curves of RES-E certificates are also indicated.     

Internalizing externalities of electricity generation: An analysis with MESSAGE-MACRO

This paper examines the global impacts of a policy that internalizes the external costs (related to air pollution damage, excluding climate costs) of electricity generation using a combined energy systems and macroeconomic model. Starting point are estimates of the monetary damage costs for SO₂, NO_X, and PM per kWh electricity generated, taking into account the fuel type, sulfur content, removal technology, generation efficiency, and population density. Internalizing these externalities implies that clean and advanced technologies increase their share in global electricity production. Particularly, advanced coal power plants, natural gas combined cycles, natural gas fuel cells, wind and biomass technologies gain significant market shares at the expense of traditional coal- and gas-fired plants. Global carbon dioxide emissions are lowered by 3% to 5%. Sulfur dioxide emissions drop significantly below the already low level. The policy increases the costs of electricity production by 0.2 (in 2050) to 1.2 € cent/kWh (in 2010). Gross domestic product losses are between 0.6% and 1.1%. They are comparatively high during the initial phase of the policy, pointing to the need for a gradual phasing of the policy.     

State-scale evaluation of renewable electricity policy: The role of renewable electricity credits and carbon taxes

We have developed a state-scale version of the MARKAL energy optimization model, commonly used to model energy policy at the US national scale and internationally. We apply the model to address state-scale impacts of a renewable electricity standard (RES) and a carbon tax in one southeastern state, Georgia. Biomass is the lowest cost option for large-scale renewable generation in Georgia; we find that electricity can be generated from biomass co-firing at existing coal plants for a marginal cost above baseline of 0.2–2.2 cents/kWh and from dedicated biomass facilities for 3.0–5.5 cents/kWh above baseline. We evaluate the cost and amount of renewable electricity that would be produced in-state and the amount of out-of-state renewable electricity credits (RECs) that would be purchased as a function of the REC price. We find that in Georgia, a constant carbon tax to 2030 primarily promotes a shift from coal to natural gas and does not result in substantial renewable electricity generation. We also find that the option to offset a RES with renewable electricity credits would push renewable investment out-of-state. The tradeoff for keeping renewable investment in-state by not offering RECs is an approximately 1% additional increase in the levelized cost of electricity.     

Exergoeconomic assessment of a geothermal assisted high temperature steam electrolysis system

Exergoeconomic formulations and procedure including exergy flows and cost formation and allocation within a high temperature steam electrolysis (HTSE) system are developed, and applied at three environmental temperatures. The cost accounting procedure is based on the specific exergy costing (SPECO) methodology. Exergy based cost-balance equations are obtained by fuel and product approach. Cost allocations in the system are obtained and effect of the second-law efficiency on exergetic cost parameters is investigated. The capital investment cost, the operating and maintenance costs and the total cost of the system are determined to be 422.2, 2.04, and 424.3 €/kWh, respectively. The specific unit exergetic costs of the power input to the system are 0.0895, 0.0702, and 0.0645 €/kWh at the environmental temperatures of 25 °C, 11 °C, and −1 °C, respectively. The exergetic costs of steam are 0.000509, 0.000544, and 0.000574 €/kWh at the same environmental temperatures, respectively. The amount of energy consumption for the production of one kg hydrogen is obtained as 133 kWh (112.5 kWh power + 20.5 kWh steam), and this corresponds to a hydrogen cost of 1.6 €/kg H₂.     

Estimating the manufacturing cost of purely organic solar cells

In this paper we estimate the manufacturing cost of purely organic solar cells. We find a very large range since the technology is still very young. We estimate that the manufacturing cost for purely organic solar cells will range between $50 and $140/m². Under the assumption of 5% efficiency, this leads to a module cost of between $1.00 and $2.83/W_p. Under the assumption of a 5-year lifetime, this leads to a levelized cost of electricity (LEC) of between 49¢ and 85¢/kWh. In order to achieve a more competitive COE of about 7¢/kWh, we would need to increase efficiency to 15% and lifetime to between 15-20 years.     

Projected costs of a grid-connected domestic PV system under different scenarios in Ireland,using measured data from a trial installation

This paper presents results of a study of projected costs for a grid-connected PV system for domestic application in Ireland. The study is based on results from a 1.72 kWp PV system installed on a flat rooftop in Dublin, Ireland. During its first year of operation a total of 885.1 kWh/kWp of electricity was generated with a performance ratio of 81.5%. The scenarios employed in this study consider: a range of capital costs; cost dynamics based on a PV module learning rate of 20±5%; projections for global annual installed PV capacity under an advanced and moderate market growth conditions; domestic electricity cost growth of 4.5% based on historic data; and a reduction of 25% or 50% in the CO₂ intensity of national electricity production by 2055. These scenarios are used to predict when system life cycle production costs fall to grid prices (grid parity).     

Ontario feed-in-tariff programs

Recent feed-in-tariff (FIT) programs in Ontario, Canada have elicited a very strong supply response. Within the first year of their inception, the Ontario Power Authority received applications totaling over 15,000 MW, equivalent to about 43% of current Ontario electricity generating capacity. The overwhelming share of applications is for wind-power (69%) and solar photovoltaic (28%) generating facilities. Wind generation is being remunerated at 14–19 ¢/kWh. Solar facilities receive from 40 to 80 ¢/kWh. The initiative, which responds to Provincial legislation is administratively divided into applications for facilities exceeding 10 kW (the FIT program) and those less than or equal to 10 kW (the microFIT program). This paper describes the programs and their features, compares them to their predecessors in Ontario as well as to programs elsewhere, analyses the reasons for the very strong response, and assesses their efficacy and sustainability.     

Analysis of CSP plants for the definition of energy policies: The influence on electricity cost of solar multiples,capacity factors and energy storage

The effect on the cost of electricity from concentrating solar power (CSP) plants of the solar multiple, the capacity factor and the storage capacity is studied. The interplay among these factors can be used to search for a minimal-cost objective that can serve as a technical criterion to guide in the design of economic incentives for CSP plants. The probability-density function of irradiation is used in conjunction with screening models to evaluate the performance characteristics and costs of concentrating solar power plants. Two technologies have been analyzed in this study: parabolic-trough and tower plants. The results provide information to define the optimal operational range as a function of the desired objective. Thus, it is possible to derive a technical criterion for the design of CSP plants which optimizes the solar electricity produced and its generation cost. The methodology is applied to Spain, and the analysis of the results shows that a solar energy production of 37 kWh/m²/year for tower plants and 66 kWh/m²/year for parabolic-trough ones define the approximate optimal working conditions for the mean DNI in Spain.     

Electricity generation from the first wind farm situated at Ras Ghareb, Egypt

Egypt is one of the Red Sea and Mediterranean countries having windy enough areas, in particular along the coasts. The coastal location Ras Ghareb on the Red Sea has been investigated in order to know the wind power density available for electricity generation. To account for the wind potential variations with height, a new simple estimating procedure was introduced. This study has explicitly demonstrated the presence of high wind power density nearly 900 kW/m² per year at 100 m of altitude for this region. Indeed, the seasonal wind powers available are comparable to and sometimes higher than the power density in many European cities for wind electricity applications like Vindeby (Denmark) and also America.New technical analysis for wind turbine characteristics have been made using three types of commercial wind turbines possessing the same rotor diameter and rated power to choice the best wind machine suitable for Ras Ghareb station. As per the decreasing the cut-in wind speed for the wind turbine used, the availability factor increases for a given generator. That it could produce more energy output throughout the year for the location.The aim of this research, was to predict the electrical energy production with the cost analysis of a wind farm 150 MW total power installed at Ras Ghareb area using 100 wind turbines model (Repower MD 77) with 1.5 MW rated power. Additionally, this paper developed the methodology for estimating the price of each kWh electricity from the wind farms. Results show that this wind park will produce maximum energy of 716 GWh/year. The expected specific cost equal to 1.5 € cent/kWh is still less than and very competitive price with that produced from the wind farms in Great Britain and Germany and at the international markets of wind power. The important result derived from this study encourages several wind parks with hundreds of megawatts can be constructed at Ras Ghareb region.     

The use of cost-generation curves for the analysis of wind electricity costs in Spain

The cost of the electricity generated from onshore wind is assessed through a method based on an estimation of the geographical distribution of the technical potential and a cost structure for the estimation of the local unit cost. Generation-cost curves are then employed to portray the evolution of the specific generating cost with the increase of the generated energy, until the limit of the technical potential is reached. The study also relates the energy cost to the land occupancy, the installed power and the capacity factor, and includes an assessment of the interplay between land usage and the cost of wind electricity. An analysis is presented to determine the uncertainty in the costs of the several model parameters. The method is applied to Spain, and allows to establish that, for an electricity-generation level of 300 TW h/y (roughly equal to the overall demand in Spain in 2008), the specific marginal cost is around 8.5 c€/kW h.     

The air quality and human health effects of integrating utility-scale batteries into the New York State electricity grid

In a restructured electricity market, utility-scale energy storage technologies such as advanced batteries can generate revenue by charging at low electricity prices and discharging at high prices. This strategy changes the magnitude and distribution of air quality emissions and the total carbon dioxide (CO₂) emissions. We evaluate the social costs associated with these changes using a case study of 500 MW sodium-sulfur battery installations with 80% round-trip efficiency. The batteries displace peaking generators in New York City and charge using off-peak generation in the New York Independent System Operator (NYISO) electricity grid during the summer. We identify and map charging and displaced plant types to generators in the NYISO. We then convert the emissions into ambient concentrations with a chemical transport model, the Particulate Matter Comprehensive Air Quality Model with extensions (PMCAM_x). Finally, we transform the concentrations into their equivalent human health effects and social benefits and costs. Reductions in premature mortality from fine particulate matter (PM_2.5) result in a benefit of 4.5 ¢ kWh⁻¹ and 17 ¢ kWh⁻¹ from displacing a natural gas and distillate fuel oil fueled peaking plant, respectively, in New York City. Ozone (O₃) concentrations increase due to decreases in nitrogen oxide (NO_x) emissions, although the magnitude of the social cost is less certain. Adding the costs from charging, displacing a distillate fuel oil plant yields a net social benefit, while displacing the natural gas plant has a net social cost. With the existing base-load capacity, the upstate population experiences an increase in adverse health effects. If wind generation is charging the battery, both the upstate charging location and New York City benefit. At $20 per tonne of CO₂, the costs from CO₂ are small compared to those from air quality. We conclude that storage could be added to existing electricity grids as part of an integrated strategy from a human health standpoint.     

Concentrating solar thermal power as a viable alternative in China's electricity supply

Study of low-carbon and pollution renewable alternatives for China revealed that concentrating solar thermal (CST) electric power generation was underemphasized in China's renewable energy plan. The analysis shows the competitive viability of CST: (1) China has the key prerequisites to make CST power generation economical including high-quality insolation and appropriate land, (2) CST's proven history, scale, and dispatchability makes it a good utility-scale power option, especially in the economically underdeveloped Western regions, (3) while CST power is currently more expensive than coal-fired electricity on a nominal basis, when costs of externalities are accounted for, CST, at 11.4 US cents/kWh, can become 57% cheaper than scrubbed coal and 29% cheaper than nuclear power, (4) CST power continues dropping in cost due to economies of scale and technological improvements and can potentially realize a levelized electricity cost of around 4 cents/kWh within ten years, (5) it would significantly rise in competitiveness if and when China completes the extensive smart grid for connecting its solar-abundant western regions with the high-demand eastern regions, (6) CST has the potential to positively impact Western China's economy, but proper policy and deal structure must be in place to ensure that the local community shares the benefit.     

Thermo-economic modeling of a solid oxide fuel cell/gas turbine power plant with semi-direct coupling and anode recycling

Power generation using gas turbine (GT) power plants operating on the Brayton cycle suffers from low efficiencies, resulting in poor fuel to power conversion. A solid oxide fuel cell (SOFC) is proposed for integration into a 10 MW gas turbine power plant, operating at 30% efficiency in order to improve system efficiencies and economics. The SOFC system is semi-directly coupled to the gas turbine power plant, with careful attention paid to minimize the disruption to the GT operation. A thermo-economic model is developed for the hybrid power plant, and predicts an optimized power output of 21.6 MW at 49.2% efficiency. The model also predicts a breakeven per-unit energy cost of USD 4.70 ¢/kWh for the hybrid system based on futuristic mass generation SOFC costs. Results show that SOFCs can be semi-directly integrated into existing GT power systems to improve their thermodynamic and economic performance.     

Simulation and thermoeconomic analysis of different configurations of gas turbine (GT)-based dual-purpose power and desalination plants (DPPDP) and hybrid plants (HP)

This paper contains a simulation and a thermoeconomic analysis of several configurations of gas turbine (GT)-based dual-purpose power and desalination plants (DPPDP): Gas turbine with reverse osmosis (GT+RO), combined cycle with reverse osmosis (CC+RO), combined cycle with multi-effect distillation (CC+MED) and two different hybrid plant (HP) arrangements combining CC, MED and RO (CC+MED+RO, CC+MED+RO_bis). The last two configurations only differ from the feed solution to the MED units (raw seawater or brine coming from the RO discharge). A complete thermodynamic simulation at both design and at part load conditions has been made, as well as an exergy and an exergo-economic (thermoeconomic) analysis of each configuration, in order to compare the evolution of the water and electricity cost for different arrangements. The results show that even for a significantly reduced fuel cost (1.42 $/GJ), the CC is much more profitable than a GT operating in open cycle, with electricity cost values of 1.647 and 2.166 c$/kWh, respectively. As was expected, RO is more efficient and profitable than MED desalination processes, the difference in the obtained desalted water cost being significant. In the hybrid configuration with MED fed by the RO brine discharge, a decrease in the equivalent electrical consumption of nearly 2 kWh/m³ was achieved, but even in this case RO was more efficient (14.15 vs. 4.048 kWh/m³). The evolution of electricity cost in each configuration is more similar at part load operation than at full load, but in the case of water cost, RO is once again more profitable and less sensitive to load variations. Costs given in this paper correspond to investment and fuel costs. Further, profitability and operation strategies of HP, i.e., DPPDP combining distillation and membrane processes, are also analyzed. It is shown that HP can be more profitable than RO plants in the case of increasing the water production capacity of existing DPPDP, because the profit margin of HP remains positive within a substantial range for fuel price and investment costs. The operation strategies of HP were also studied in detail (by means of linear optimization) in order to minimize production costs; and it was concluded that electricity cost minimization gives the same result as the minimization of whole production cost; and water cost minimization could give a lower water cost than in the previous cases, but could lead to prohibitive electricity cost.     

The economics of using plug-in hybrid electric vehicle battery packs for grid storage

We examine the potential economic implications of using vehicle batteries to store grid electricity generated at off-peak hours for off-vehicle use during peak hours. Ancillary services such as frequency regulation are not considered here because only a small number of vehicles will saturate that market. Hourly electricity prices in three U.S. cities were used to arrive at daily profit values, while the economic losses associated with battery degradation were calculated based on data collected from A123 Systems LiFePO₄/Graphite cells tested under combined driving and off-vehicle electricity utilization. For a 16 kWh (57.6 MJ) vehicle battery pack, the maximum annual profit with perfect market information and no battery degradation cost ranged from ∼US$140 to $250 in the three cities. If the measured battery degradation is applied, however, the maximum annual profit (if battery pack replacement costs fall to $5000 for a 16 kWh battery) decreases to ∼$10-120. It appears unlikely that these profits alone will provide sufficient incentive to the vehicle owner to use the battery pack for electricity storage and later off-vehicle use. We also estimate grid net social welfare benefits from avoiding the construction and use of peaking generators that may accrue to the owner, finding that these are similar in magnitude to the energy arbitrage profit.     

Air conditioning in the region of Madrid, Spain: An approach to electricity consumption, economics and CO2 emissions

An understanding of electricity consumption due to residential air conditioning (AC) may improve production and environmental impact strategy design. This article reports on a study of peak and seasonal electricity consumption for residential air conditioning in the region of Madrid, Spain. Consumption was assessed by simulating the operation of AC units at the outdoor summer temperature characteristics of central Spain. AC unit performance when operating under part load conditions in keeping with weather conditions was also studied to find cooling demand and energy efficiency. Likewise final electricity consumption was computed and used to calculate energy costs and greenhouse gas emissions (GHGs). Cooling demand, when family holidays outside the region were factored into the calculations, came to 1.46 × 10⁹ kWh. Associated seasonal electricity demand was 617 × 10⁶ kWh and seasonal performance of AC units around 2.4. Electricity consumption in the whole region was observed to peak on 30 June 2008 at 5.44 × 10⁶ kW, being the load attributable to residential AC 1.79 × 10⁶ kW, resulting about 33% of the total peak consumption. The seasonal cost per household was about €156 and the total equivalent warming impact was 572 × 10³ t CO₂. The method proposed can be adapted for use in other regions.