Electricity Selling Price Research Articles

Comparing electricity storage technologies for small insular grids

The objective of this article is to investigate the technically and economically optimum electricity storage technologies for small, insular, autonomous electrical grids, integrated with Renewable Energy Sources (RES) power plants. Three autonomous Greek islands are investigated as case studies: Symi, Astypalaia and Kastelorizo, with annual peak demand at 4.0 MW, 2.2 MW and 0.9 MW respectively. All three islands exhibit excellent wind and solar potential, with ideal sites for the installation of seawater Pumped Hydro Storage (PHS). Two different approaches are investigated, regarding the electricity storage plants: PHS systems (for the two largest islands) and electrochemical storage, alternatively realized with lead acid or lithium-ion batteries. Wind parks and photovoltaic stations are considered as the potential RES units. Relevant operation algorithms are introduced. The dimensioning of the examined plants is optimized with a common target: the achievement of RES annual penetration percentage higher than 70%, ensuring the investments’ economic feasibility, with electricity selling prices lower than the existing specific production cost. Given the favorable land morphology for PHS installations, it is shown that wind-PHS still remains a competitive alternative for Symi and Astypalaia, despite their relatively small size, while for Kastelorizo, a wind-photovoltaic-batteries features as the optimum option. 100% annual RES penetration can be achieved only with the PHS support. With electrochemical storage systems, the RES annual penetration can be between 80 and 90%. The economic feasibility is ensured with electricity selling prices between 200 and 350 €/kWh. The investments’ payback periods are estimated between 6 and 10 years.

Techno-Economic Evaluation of a Grid-Connected Solar PV Plant in Syria

The main objective of this paper is to analyze the techno-economic feasibility of installing a 300 kW grid-connected solar photovoltaic (PV) plant in Syria. Umm Al-Zaytun village in As-Suwayda province was chosen as a location of the plant, because it is characterized by the high annual solar irradiance on the horizontal surface of about 1900 kW h/m2. Technical performance analysis, system configuration, detailed losses and energy yield simulation for a proposed PV plant were performed, using the PVsyst software. The simulation results show, that the annual optimal tilt angle of PV modules is 25°, energy production is 493 MWh/yr, the annual average performance ratio is 0.799 and the capacity factor is 18.7%. In addition, by considering, that the electric power consumption per capita in Syria is 2232 kW h/yr, so the proposed solar power plant with 493 MW h/yr can provide energy to 220 capita/yr and save about 42.4 tons of oil equivalent yearly with carbon emission reduction of about 320.45 tCO2/yr. The economic evaluation of the proposed PV plant was carried out by Excel software with consideration, that the discount rate is 9%, the lifetime of the project is 25 years and the selling price of electricity to Syrian electricity distribution establishment is 0.119 $/kW h. The results of economic calculations show, that levelized cost of electricity is 0.094 $/kW h, the discounted payback period is about 11 years, the internal rate of return is 14%, profitability index is 1.46 and the net present value is 190587.3 $. As a result, the proposed grid-connected PV solar plant is considered economically, technically and environmentally feasible in Syria.

Economic analysis of residential solar photovoltaic electricity production in Canada

This paper presents the results of a comparative economic analysis of residential solar photovoltaic systems throughout the provinces of Canada in 2013 and 2016. The study was conducted using the discounted cash flow method. Basic economic theory involving the concepts of net present value, payback period, and internal rate of return was used, based on data from 2013 and 2016. The solar photovoltaic market is dependent on supporting policies and incentives. Thus, the relevant federal and provincial supporting policies for building implementation are briefly described and considered in the calculations. Results are presented in the form of summary tables showing selected major cities, classified into different categories, in terms of financial viability. The results show that in 2013 there were 9 cities out of 13 for which the payback period was expected to be higher than 30 years but in 2016, only Montreal PV projects remain infeasible. Furthermore, sensitivity analyses were conducted to establish new values for the selling price of electricity, initial cost of the proposed project, and percentage of subsidy required to ensure project attractiveness, that is, a short payback period of only 5 years for residential buildings.

Comparing electricity storage technologies for small insular grids

This article investigates the technically and economically optimum electricity storage technologies for small, insular, autonomous electrical grids, integrated with Renewable Energy Sources (RES) power plants. Three autonomous Greek islands are investigated as case studies: Symi, Astypalaia and Kastelorizo, with annual peak demand at 4.0 MW, 2.2 MW and 0.9 MW respectively. All the investigated islands exhibit excellent wind and solar potential, with ideal sites for the installation of seawater Pumped Hydro Storage (PHS).Two different approaches are investigated, regarding the electricity storage plants: PHS systems (for the two largest islands) and electrochemical storage, alternatively realized lead acid or lithium-ion batteries. Wind parks and photovoltaic stations are considered as the potential RES units. The dimensioning of the examined plants is optimized with a common target: the achievement of RES annual penetration percentage higher than 70%, maintaining the electricity selling price lower than the existing specific production cost. The study is integrated with the economic evaluation of the examined systems.Given the appropriate land morphology for PHS installations, it is shown that wind-PHS still remains a competitive alternative for Symi and Astypalaia, while for Kastelorizo, a wind-p/v- batteries features as the optimum option. 100% annual RES penetration can be achieved only with the PHS support, while with the electrochemical batteries the RES annual penetration can be between 80 and 90%. The economic feasibility is ensured with electricity selling prices between 200 and 350 €/kWh, leading to payback periods between 5 and 9 years.

A price decision approach for multiple multi-energy-supply microgrids considering demand response

Multi-energy-supply microgrids covering different types of demands are expected to play an important role in smart grids. Local generation, energy storage systems, and renewable energy sources can form load service entities, which can provide ancillary services to the utility grid and to consumers. On the other hand, microgrids can also sell energy to load service entities or the utility grid to obtain profits. But how the load service entities can decide the electricity selling price to multiple microgrids, and how the microgrids can decide the electricity selling price to load service entities are problems. In this paper, we present a price decision method for multiple microgrids considering demand response. Mixed integer linear programming is used to control the operation of each microgrid, and is also used to operate the load service entities. A genetic algorithm is used to search for the best price for each microgrid and the load service entities. The combined method is deployed in a decentralized way, namely, each microgrid runs its own operation problem. The simulation results show that the new searched price works better than a basic time of use price, which can reduce the operation cost of the whole system. The searching method is compared with a method based on the Cournot model. At last, a large system is tested, in which 4 load service entities, 16 microgrids and an IEEE30-node network are considered. In order to reduce the searching time, a neural network model is presented to estimate the operation of the whole system. Based on the neural network model, the prices are obtained, and the results show that the prices based on neural network model are better than with the time of use price.

Integration of compressed air energy storage with wind generation into the electricity grid

Integration of renewable electricity from wind farms into the electricity grid presents challenges because wind is a highly variable resource whereby the amount of power generated depends on local wind speed, air density and wind turbine characteristics. Energy storage is one possible approach to mitigate power fluctuations and quality issues. Among presently available technologies to store energy, Compressed Air Energy Storage (CAES) shows many attractive features. This work focuses on techno-economic modelling and analysis for the integration of wind turbines with CAES into the power grid. To have a deep understanding of the performance, characteristics and benefits of system integration, technical and economic models for CAES processes are developed in the processes simulation software ECLIPSE. To conduct this study, two scenarios that are each dependent on generation scales and locations were proposed; (1) centralised CAES (based on the diabatic method) (2) distributed CAES (based on the adiabatic approach). The nominal power generation of centralised and distributed CAES systems were given as 280 MWe and 5 MWe, respectively. The impact of CAES systems on the electricity market is also discussed. Techno-economic analysis of the modelled centralised CAES system showed round-trip efficiency of around 53.6% (and around 56.7% for the modelled distributed CAES system). Specific investment was found to be around €585/kWe (€2452/kWe) and break-even electricity selling price to be around €111/MWh (€275/MWh). Their CO2 emissions were found to be compatible with the average CO2 emissions of UK CCGT power generation.

A fuzzy logic-based approach for pricing of electricity in Jordan

This paper aims to provide a feasible and practical tool for decision makers in the energy and electricity sectors, represented by EMRC, in order to calculate a reasonable selling price for electricity in Jordan. We propose an alternative approach using a fuzzy logic technique to help EMRC assign a fair and dynamic sale price for electricity, based on two categories of electricity consumption (low and high). Our experimental results, based on simulated data, show that the proposed method provides fair prices to both customer and service providers, allowing an easy and effective way to increase/decrease electricity prices.

Impact of Financing Instruments and Strategies on the Wind Power Production Costs: A Case of Lithuania

Abstract The paper aims at demonstrating the relevance of financing instruments, their terms and financing strategies in relation to the cost of wind power production and the ability of wind power plant (PP) to participate in the electricity market in Lithuania. The extended approach to the Levelized Cost of Energy (LCOE) is applied. The feature of the extended approach lies in considering the lifetime cost and revenue received from the support measures. The research results have substantiated the relevance of financing instruments, their terms and strategies in relation to their impact on the LCOE and competitiveness of wind PP. It has been found that financing of wind PP through the traditional financing instruments (simple shares and bank loans) makes use of venture capital and bonds coming even in the absence of any support. It has been estimated that strategies consisting of different proportions of hard and soft loans, bonds, own and venture capital result in the average LCOE of 5.1–5.7 EURct/kWh (2000 kW), when the expected electricity selling price is 5.4 EURct/kWh. The financing strategies with higher shares of equity could impact by around 6 % higher LCOE compared to the strategies encompassing higher shares of debt. However, seeking to motivate venture capitalists, bond holders or other new financiers entering the wind power sector, support measures (feed-in tariff or investment subsidy) are relevant in case of 250 kW wind PP. It has been estimated that under the unsupported financing strategies, the average LCOE of 250 kW wind PP will be 7.8–8.8 EURct/kWh, but it will reduce by around 50 % if feed-in tariff or 50 % investment subsidy is applied.

Flexible operation of post-combustion CO2 capture at pilot scale with demonstration of capture-efficiency control using online solvent measurements

Flexible post-combustion carbon capture and storage (CCS) has the potential to play a significant part in the affordable decarbonisation of electricity generation portfolios. PCC plant operators can modify capture plant process variables to adjust the CO2 capture level to a value which is optimal for current fuel cost, electricity selling price and CO2 emissions costs, increasing short-term profitability. Additionally, variation of the level of steam extraction from the generation plant can allow the capture facility to provide additional operating flexibility for coal-fired power stations which are comparatively slow to change output.A pilot-scale test campaign investigates the response of plant operating parameters to dynamic scenarios which are designed to be representative of pulverised coal plant operation. Online sensors continuously monitor changes in rich and lean solvent CO2 loading (30%wt monoethanolamine). Solvent loading is likely to be a critical control variable for the optimisation of flexible PCC operation, and since economic and operational boundaries can change on timescales 30 min or shorter, the development of methods for rapid, continuous online solvent analysis is key. Seven dynamic datasets are produced and insights about plant response times and hydrodynamics are provided. These include power output maximisation, frequency response, power output ramping and a comparison between two plant start-up strategies.In the final dynamic operating scenario, control of CO2 capture efficiency for a simple reboiler steam decoupling and reintroduction event is demonstrated using only knowledge of plant hydrodynamics and continuous measurement of solvent lean loading. Hot water flow to the reboiler is reduced to drop the capture efficiency. The “target” value for the minimum capture efficiency in the scenario was set at 30%, but a minimum CO2 capture efficiency of 26.4% was achieved. While there remains scope for improvement this represents a significant practical step towards the control of capture plant using online solvent concentration and CO2 measurements, and the next steps for its further development are discussed.

Economic analysis of bioethanol and electricity production from sugarcane in South Africa

AbstractAn economic analysis for ethanol and electricity production in the sugarcane crushing industry in South Africa through first‐ and second‐generation technologies, and integration strategies was carried out. The analysis included capital allowances to upgrade the energy efficiencies of existing sugar mills, to allow co‐production of electricity, production of second‐generation ethanol from hemicellulose, and export of lignocellulose residues from these facilities. Methodologies included mass and energy balances in Aspen Plus® and economic models in MS Excel to determine the required selling prices for electricity, sugarcane residues and ethanol, for these investments. The required selling price for electricity for the sugarcane crushing industry was US$ 97/MWhr, while that of bagasse residues was US$ 90/ton. A first‐generation ethanol plant with electricity co‐generation from bagasse has an ethanol selling price of US$ 0.84/l, which was highly dependent of the cane price, and reduced significantly when second‐generation production from hemicelluloses of bagasse and trash was incorporated. The selling price of US$ 0.38/l for integrated second‐generation ethanol at a sugar mill was the lowest, but however, was highly dependent on technological efficiency. Standalone second‐generation ethanol was unfeasible due to the costs of the infrastructure needed to provide bagasse as a ­feedstock. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd

Techno-economic study of compressed air energy storage systems for the grid integration of wind power

Integrating variable renewable energy from wind farms into power grids presents challenges for system operation, control, and stability due to the intermittent nature of wind power. One of the most promising solutions is the use of compressed air energy storage (CAES). The main purpose of this paper is to examine the technical and economic potential for use of CAES systems in the grid integration. To carry out this study, 2 CAES plant configurations: adiabatic CAES (A-CAES) and diabatic CAES (D-CAES) were modelled and simulated by using the process simulation software ECLIPSE. The nominal compression and power generation of both systems were given at 100 and 140 MWe, respectively. Technical results showed that the overall energy efficiency of the A-CAES was 65.6%, considerably better than that of the D-CAES at 54.2%. However, it could be seen in the economic analysis that the breakeven electricity selling price (BESP) of the A-CAES system was much higher than that of the D-CAES system at €144/MWh and €91/MWh, respectively. In order to compete with large-scale fossil fuel power plants, we found that a CO2 taxation scheme (with an assumed CO2-tax of €20/tonne) improved the economic performance of both CAES systems significantly. This advantage is maximised if the CAES systems use low carbon electricity during its compression cycle, either through access to special tariffs at times of low carbon intensity on the grid, or by direct coupling to a clean energy source, for example a 100-MW class wind farm.

Black-Scholes option pricing strategy and risk-averse coordination for designing vehicle-to-grid reserve contracts

Based on the conditional value-at-risk criterion and trading characteristics of the vehicle-to-grid reserve market, this paper establishes an option pricing strategy for a risk-neutral grid company, and builds two electricity reserve models for a risk-averse electric vehicle user before and after options implementation. Then, the impact of options, electricity selling price and risk aversion changes on feedback equilibrium strategies and optimal profits are comparatively analyzed between a Stackelberg game and a cooperative game. The results demonstrate that simply using protective market pricing mechanism to determine the contract price places all of the vehicle-to-grid market's trading risk onto the grid company, so that opportunistic behavior cannot be prevented in bad market conditions. To address this, the grid company can buy options to mitigate the risk of price fluctuations; the cooperation system can be further enhanced through a “Black-Scholes option pricing + reserve cooperation + deposit” joint contract, which achieves Pareto improvements of the optimal profits on both sides of the channel. Finally, the analytical relations among the vehicle-to-grid reserve's cooperation coefficient, trade deposit, and electricity contract price in equilibrium are derived, and the feasibility of the proposed models and theoretical analyses is verified by three numerical examples.

Integration of Organic Rankine Cycle with Lignite Flue Gas Pre-drying for Waste Heat and Water Recovery from Dryer Exhaust Gas: Thermodynamic and Economic Analysis

Abstract The flue gas pre-drying of lignite produces a moisture rich dryer exhaust gas which can be further cooled to recover the waste heat and water vapor. An environmental friendly power system is investigated in the present work, which integrates the lignite flue gas pre-drying system with an organic Rankine cycle (ORC) to utilize the waste heat to generate power and capture the condensed water. Simulation models of the integrated system are developed, incorporating thermodynamic and economic evaluation indicators. The optimal energy and exergy efficiencies of the ORC system are calculated to be 3.10% and 24.57%, respectively, for an evaporation temperature of 51 °C when R245fa is used as the working fluid. Accordingly, the ORC power output is 3.61 MW and the absolute plant efficiency improvement is 0.27% points. Moreover, 55.17% of the water vapor can be recovered. The economic performance significantly relies on the specific investment cost of ORC and the electricity selling price. Typically, the break-even points of the specific investment cost are 2300 €/kW and 3700 €/kW when electricity selling prices are 0.05 €/kWh and 0.08 €/kWh, respectively.

Techno-economic Modelling of Large Scale Compressed Air Energy Storage Systems

Interest in integrating energy storage systems into the power grid has increased in Europe over the past decade due to strategies to overcome the intermittent nature of renewable electricity sources. One of these technologies is compressed air energy storage (CAES). The main purpose of this paper is to examine the technical and economic potential of CAES systems. In this work, two configurations a) Adiabatic Compressed Air Energy Storage (A-CAES); and b) Conventional Compressed Air Energy Storage (C-CAES) were modelled using the ECLIPSE suite of process simulation software. The nominal compression and power generation of both systems were given at 100MWe and 140MWe respectively. For each mode of operation an energy analysis was carried out. Energy use was calculated and compared for each system mode. Based on the results of mass and energy balances, an economic evaluation of the systems was conducted. Technical results showed that the overall efficiency of the A-CAES system would be 64.7%, considerably better than that of the C-CAES system at 52.6%. However it could be seen in the economic analysis that the breakeven electricity selling price (BESP) of the A-CAES system was 152€/MWh, much higher than that of the C-CAES system at 95€/MWh on average.

Techno-economic Assessment of Biomass Gasification of Spartina argentinensis

Argentina has rangelands with high biomass production and low profitability such as the «Bajos Submeridionales», a depressed 33,000 km2 area mostly dominated by a perennial grass, Spartina argentinensis. In this work, we assessed the technoeconomic feasibility of S. argentinensis pellets gasification for combined heat and power purposes. The energy balance was estimated, resulting in an Energy Return On Investment (EROI) of 5.43. Breakeven energy price (BEPE) was calculated for:(i) business as usual (BAU) and (ii) alternative scenario (AS) considering an international natural gas price of 0.2 and 0.47 USD.m-3 respectively. Investment net present value (NPV) was calculated and a sensitivity analysis was performed. BEPE resulted in 149 and 126.2 USD.MWeh-1 for BAU and AS respectively. NPV was -4.4 and -1.6 million dollars for BAU and AS respectively, showing the relevance of natural gas price on economic results. Power efficiency and electricity selling price were the variables with higher impact on NPV.

Potential of brown algae for sustainable electricity production through anaerobic digestion

This paper assesses the economics of heat and power production from the anaerobic digestion (AD) of brown algae (Laminaria japonica) at a plant scale of 400,000 dry tons/year. The conversion process was simulated in Aspen Plus v.8.6 to obtain rigorous heat and material balance for energy assessments and the development of a techno-economic model. The breakeven electricity selling price (BESP) was found to be 18.81 ¢/kWh assuming 30years of plant life and a 10% internal rate of return. The results show that the AD unit has the highest energy demand in the entire process and consumes approximately 14% of all electricity produced. In addition, the seaweed cost of 11.95 ¢/kWh is the largest cost component that contributes to the calculated BESP, which means that a reduction in the cost of seaweed cultivation can significantly decrease the electricity production cost. A sensitivity analysis was performed on the economic and process parameters in order to assess the impact of possible variations and uncertainties in these parameters. Results showed that solids loading, anaerobic digestion yield, and time, respectively, have the highest impact on BESP.

Scenario analysis for sustainable woody biomass energy businesses: The case study of a Japanese rural community

Woody biomass is widely used as a renewable energy source to produce electricity and heat, with the goal of reducing CO2 emissions, enhancing energy security, and rejuvenating rural economies. In Japan, the energy usage of woody biomass is currently incentivized by feed-in tariff (FIT) programs. However, a variety of unpredictable factors (e.g., a drastic change in national energy policy and feedstock supply) might undermine the sustainability of woody biomass energy businesses. In order to clarify conditions for designing sustainable woody biomass energy businesses from environmental and economic viewpoints, this paper proposes a method for undertaking scenario analyses where the influences of future uncertainties are analyzed. For quantitative assessment, a woody biomass energy business is modeled as a sequence of processes using a discrete event simulation technique. A case study is carried out with a particular focus on the energy business with a 10 MW woody biomass power generation plant in a Japanese rural community in the period of 2015–2034 (20 years). The results reveal that the business has potential to gain economic profit and halve CO2 emissions when compared with the worst case scenario. Critical factors for enhancing the sustainability of the business include collecting the amount of wood residue used for electricity generation and keeping the selling price of electricity from woody biomass at over 35% of the current price.

Design and analysis of a diesel processing unit for a molten carbonate fuel cell for auxiliary power unit applications

Fuel cell-based auxiliary power units (APUs) are a promising technology for meeting global energy needs in an environmentally friendly way. This study uses diesel containing sulfur components such as dibenzothiophene (DBT) as a feed. The sulfur tolerance of molten carbonate fuel cell (MCFC) modules is not more than 0.5 ppm, as sulfur can poison the fuel cell and degrade the performance of the fuel cell module. The raw diesel feed in this study contains 10 ppm DBT, and its sulfur concentration should be reduced to 0.1 ppm. After desulfurization, the feed goes through several unit operations, including steam reforming, water-gas shift, and gas purification. Finally, hydrogen is fed to the fuel cell module, where it generates 500 kW of electrical energy. The entire process, with 52% and 89% fuel cell and overall system efficiencies, respectively, is rigorously simulated using Aspen HYSYS, and the results are input into a techno-economic analysis to calculate the minimum electricity selling price (MESP). The electricity cost for this MCFC-based APU was calculated as 1.57$/kWh. According to predictions, the cost reductions for fuel cell stacks will afford electricity selling prices of 1.51$/kWh in 2020 and 1.495$/kWh in 2030. Based on a sensitivity analysis, the diesel price and capital cost were found to have the strongest impact on the MESP.

Impacts of feed-in tariff policies on design and performance of CCHP system in different climate zones

In this paper, a feed-in tariff policy which can contribute to both energy and economic performance of a CCHP system is proposed. By applying this feed-in tariff policy, the impact on design optimization (power generation unit capacity and operation strategy) and system performance (economic, energy, and matching performance) of a hospital CCHP system used in different climate zones are evaluated and analyzed. In policy one (Pol1), no electricity is allowed to be sold. In policy two (Pol2), the electricity selling price is constant. In policy three (Pol3), the selling price of electricity is proportional to the PER (Primary Energy consumption Ratio) of the system when the PER is not lower than a critical value. Otherwise, the selling price is zero. The results show that Pol3 can ensure both energy and economic performances of CCHP system. The effect of feed-in tariff policy to improve the performance of CCHP system reduces gradually from the cold zone to the hot zone. Multi-criteria decision making results show that Pol3 with reasonable parameters is the best choice in all climate zones except for the hottest zone in this study. When improving PER is attractive, following thermal load operation strategy is the best choice under Pol3. In the hottest zone of this study, little excess electricity would be produced and sold to the grid. Feed-in tariff policy has little help to improve the economic and energy performance in this zone.

Performance analysis of biofuel fired trigeneration systems with energy storage for remote households

Technical and economic modelling and performance analysis of biofuel fired trigeneration systems equipped with energy storage for remote households were carried out. To adapt the dynamic energy demand for electricity, heating and cooling, both electrical and thermal energy storage devices were integrated to balance larger load changes. The proposed systems were modelled and simulated by using the ECLIPSE process simulation package. Based on the results achieved, technical performance and emissions from the system had been examined. The impact of electrical and thermal energy storages was also investigated. Finally, an economic evaluation of the systems was performed. It was found that for a household, the internal combustion (IC) engine based trigeneration/combined heat and power (CHP) system is more suitable for heat to electricity ratio value below 1.5 and the biomass boiler and Stirling engine based system is beneficial for heat to electricity energy demand ratio lying between 3 and 3.4. Techno-economic analysis of the modelled trigeneration systems showed efficiencies of around 64–70% and Break-even Electricity Selling Prices of around £313/MWh to £357/MWh when fired by biofuels. Results also indicated that the economic viability of this type of trigeneration systems is significantly improved by the Renewable Heat Incentive (RHI) and Feed-In Tariffs schemes (FITs) by up to 46%.