Levelized cost of electricity (LCOE) of renewable energies and required subsidies in China

The development and utilization of renewable energy (RE), a strategic choice for energy structural adjustment, is an important measure of carbon emissions reduction in China. High cost is a main restriction element for large-scale development of RE, and accurate cost estimation of renewable power generation is urgently necessary. This is the first systemic study on the levelized cost of electricity (LCOE) of RE in China. Results indicate that feed-in-tariff (FIT) of RE should be improved and dynamically adjusted based on the LCOE to provide a better support of the development of RE. The current FIT in China can only cover the LCOE of wind (onshore) and solar photovoltaic energy (PV) at a discount rate of 5%. Subsidies to renewables-based electricity generation, except biomass energy, still need to be increased at higher discount rates. Main conclusions are drawn as follows: (1) Government policy should focus on solving the financing problem of RE projects because fixed capital investment exerts considerable influence over the LCOE; and (2) the problem of high cost could be solved by providing subsidies in the short term and more importantly, by reforming electricity price in the mid-and long-term to make the RE competitive.     

Viability of a concentrated solar power system in a low sun belt prefecture

Concentrating solar power (CSP) is considered as a comparatively economical, more efficient, and large capacity type of renewable energy technology. However, CSP generation is found restricted only to high solar radiation belt and installed where high direct normal irradiance is available. This paper examines the viability of the adoption of the CSP system in a low sun belt region with a lower direct normal irradiance (DNI). Various critical analyses and plant economics have been evaluated with a lesser DNI state. The obtained results out of the designed system, subjected to low DNI are not found below par, but comparable to some extent with the performance results of such CSP plants at a higher DNI. The analysis indicates that incorporation of the thermal energy storage reduces the levelized cost of energy (LCOE) and augments the plant capacity factor. The capacity factor, the plant efficiency, and the LCOE are found to be 32.50%, 17.56%, and 0.1952 $/kWh, respectively.     

Incorporating externalities into a full cost approach to electric power generation life-cycle costing

This study presents a full cost approach to determine the levelized cost of energy (LCOE) of 14 electricity generation technologies. It encompasses costs incurred at all stages of the fuel cycle, including those that are traditionally omitted from economic evaluations of generation technologies. Incorporating these “externalities” increases the likelihood of developing the most economical and sustainable power resource from a societal perspective. The following externalities are included in this analysis: damage from air pollution, energy security, transmission and distribution costs, and other environmental impacts. Incorporating externalities has a large impact on the LCOE and the relative attractiveness of electricity generation options. Results indicate that clean and efficient generation technologies are the most attractive when all options are examined using a full cost, levelized approach.     

Economic implications of thermal energy storage for concentrated solar thermal power

Solar energy is an attractive renewable energy source because the sun's energy is plentiful and carbon-free. However, solar energy is intermittent and not suitable for base load electricity generation without an energy backup system. Concentrated solar power (CSP) is unique among other renewable energy options because it can approach base load generation with molten salt thermal energy storage (TES). This paper describes the development of an engineering economic model that directly compares the performance, cost, and profit of a 110-MW parabolic trough CSP plant operating with a TES system, natural gas-fired backup system, and no backup system. Model results are presented for 0–12 h backup capacities with and without current U.S. subsidies. TES increased the annual capacity factor from around 30% with no backup to up to 55% with 12 h of storage when the solar field area was selected to provide the lowest levelized cost of energy (LCOE). Using TES instead of a natural gas-fired heat transfer fluid heater (NG) increased total plant capital costs but decreased annual operation and maintenance costs. These three effects led to an increase in the LCOE for PT plants with TES and NG backup compared with no backup. LCOE increased with increasing backup capacity for plants with TES and NG backup. For small backup capacities (1–4 h), plants with TES had slightly lower LCOE values than plants with NG backup. For larger backup capacities (5–12 h), plants with TES had slightly higher LCOE values than plants with NG backup. At these costs, current U.S. federal tax incentives were not sufficient to make PT profitable in a market with variable electricity pricing. Current U.S. incentives combined with a fixed electricity price of $200/MWh made PT plants with larger backup capacities more profitable than PT plants with no backup or with smaller backup capacities. In the absence of incentives, a carbon price of $100–$160/tonne CO_2eq would be required for these PT plants to compete with new coal-fired power plants in the U.S. If the long-term goal is to increase renewable base load electricity generation, additional incentives are needed to encourage new CSP plants to use thermal energy storage in the U.S.     

Techno-econo-environmental optimal operation of grid-wind-solar electricity generation with hydrogen storage system for domestic scale,case study in Chad

The rapidly growing of population in the developing countries and their lack of access to electricity, especially in the remote or rural areas, is causing huge challenges for on energy production. Energy is an enabler and a reliable energy supply is critical to sustainable socio-economic development for any nation. Most of Chad's people live in villages with no particular power supply system. Exploiting renewable energies is the only means of fostering development and improving people's welfare. This paper attempts at proposing an energy profile and storage model for Chad in vast remote towns. The paper addresses the key energy gap that is hindering on the development of such systems, it models and assess the potential on electricity generation and using hydrogen as surplus power storage system. A techno-econo-environmental survey on a solar-wind hybrid system in 25 towns in Chad is undertaken using NASA data and HOMER Software. Several hybrid scenarios of energy production and storage is analyzed. The results showed that in the electricity generation scenario, the average total NPC for the studied stations was $ 48164 and the average LCOE was $0.573. The lowest LCOE was related to Aouzou station with 0.507 $/kWh and the highest LCOE was obtained for Bol station with 0.604 $/kWh. In the simultaneous electricity and hydrogen generation scenario, the cheapest hydrogen ($4.695/kg) was produced in the “Grid” scenario, which was the same for all of the stations, with a total NPC of $2413770. The most expensive hydrogen ($4.707/kg) was generated in the “Grid-Wind” scenario and Bol stations with a total NPC of $2420186. The paper develops cost effective models for all hybrid systems combination for both electricity and hydrogen generation across Chad. These findings could help policy makers, investors and other developmental agencies make informed choices on energy access for sustainable development for rural communities in Sub Saharan Africa.     

Solar multiple optimization for a solar-only thermal power plant, using oil as heat transfer fluid in the parabolic trough collectors

Usual size of parabolic trough solar thermal plants being built at present is approximately 50 MW_e. Most of these plants do not have a thermal storage system for maintaining the power block performance at nominal conditions during long non-insolation periods. Because of that, a proper solar field size, with respect to the electric nominal power, is a fundamental choice. A too large field will be partially useless under high solar irradiance values whereas a small field will mainly make the power block to work at part-load conditions.This paper presents an economic optimization of the solar multiple for a solar-only parabolic trough plant, using neither hybridization nor thermal storage. Five parabolic trough plants have been considered, with the same parameters in the power block but different solar field sizes. Thermal performance for each solar power plant has been featured, both at nominal and part-load conditions. This characterization has been applied to perform a simulation in order to calculate the annual electricity produced by each of these plants. Once annual electric energy generation is known, levelized cost of energy (LCOE) for each plant is calculated, yielding a minimum LCOE value for a certain solar multiple value within the range considered.     

Is the concept of ‘grid parity’ defined appropriately to evaluate the cost-competitiveness of renewable energy technologies?

The concept of ‘grid parity’ has emerged as a key indicator of the competitiveness of renewable electricity generation technologies. In this study, we firstly summarize the definition of the current levelized cost of electricity (LCOE) based methodology for the concept and address its limitation in not taking into account the systematic changes in an electric power system. Secondly, we introduce a bottom-up energy system model based methodology to overcome the limitation. Lastly, we apply the methodology to a case study, the grid parity analysis of solar photovoltaic and onshore wind technologies in the Korean electric power system, to highlight the differences between the results obtained using both methodologies. The results of the study show three implications. First, even if the LCOE of onshore wind is already lower than that of natural gas technologies and the average price of grid electricity, the LCOE is required to be much lower to achieve cost-competitiveness in the electric power system. Second, different technologies might be required to have different LCOE levels to be cost-competitive in the same power system. Third, a policy or plan for the deployment of renewable energy technologies must be harmonized with other policies and plans within the same system.     

De-risking investment into concentrated solar power in North Africa: Impacts on the costs of electricity generation

A low-carbon energy transition on the basis of renewable energy sources (RES) is of crucial importance to solve the interlinked global challenges of climate change and energy security. However, large-scale deployment of RES requires substantial investments, including the participation of private capital. Scientific evidence shows that the economic feasibility of a RES project hinges on the availability of affordable project financing, which itself depends on risk perceptions by private investors. Since financing costs tend to be particularly high for capital-intensive RES projects and in developing countries, we investigate the impacts of addressing these perceived risks on electricity prices from semi-dispatchable concentrated solar power (CSP) in four North African countries. By employing a levelized cost of electricity (LCOE) model we find that comprehensively de-risking CSP investments leads to a 39% reduction in the mean LCOE from CSP. However, this reduction is still not sufficient to achieve economic competitiveness of CSP with highly subsidized conventional electricity from fossil fuels in North Africa. Hence, our results suggest that de-risking reflects an important strategy to foster the deployment of CSP in North Africa but additional measures to support RES, such as reconsidering fossil fuel subsidies, will be needed.     

Economic feasibility of large-scale hydro-solar hybrid power including long distance transmission

Solar PV is expected to become the most cost-competitive renewable energy owing to the rapidly decreasing cost of the system. On the other hand, hydropower is a high-quality and reliable regulating power source that can be bundled with solar PV to improve the economic feasibility of long-distance transmitted power. In this paper, a quantification model is established taking into account the regulating capacity of the reservoir, the characteristics of solar generation, and cost of hydro and solar PV with long-distance transmission based on the installed capacity ratio of hydro-solar hybrid power. Results indicate that for hydropower stations with high regulating capacity and generation factor of approximately 0.5, a hydro-solar installed capacity ratio of 1:1 will yield overall optimal economic performance, whereas for hydropower stations with daily regulating capacity reservoir and capacity factor of approximately 0.65, the optimal hydro-solar installed capacity ratio is approximately 1:0.3. In addition, the accuracy of the approach used in this study is verified through operation simulation of a hydro-solar hybrid system including ultra high-voltage direct current (UHVDC) transmission using two case studies in Africa.     

Quantifying key uncertainties in the costs of nuclear power

In power system portfolio decisions, cost risk (uncertainty over cost) should be an important consideration, in addition to central estimates of cost. This study quantifies the uncertainty in each of the cost components for nuclear power, and combines them using a Monte Carlo analysis, allowing a direct assessment of cost risk for this technology. This can be used as an input to sophisticated portfolio optimisation modelling tools that take cost risk into account. Levelised cost of energy (LCOE) estimates are also provided here to allow an indicative comparison of the scale of cost risk, compared with other technologies. The most important contributors to cost risk for nuclear power generation are identified to be overnight capital cost (OCC) estimates, the degree of cost escalation over the construction and pre‐construction periods and the duration of those periods. In the absence of cost escalation, the mean LCOE of nuclear power is found to be AU$145/MWh in jurisdictions excluding Asia (or AU$130/MWh if Asian plant costs are included in the distributions), with a standard deviation of AU$62/MWh. However, when cost escalation over construction and pre‐construction periods is included at rates observed during nuclear build programs in France and the USA, the mean LCOE increases to AU$515/MWh, with a standard deviation of AU$2646/MWh. These results indicate that nuclear power costs have an 80% probability of exceeding AU$170/MWh, and a 50% probability of exceeding AU$278/MWh, based upon Monte Carlo analysis. This suggests that for OECD jurisdictions without an established nuclear industry (such as Australia), nuclear power may be comparable in cost with ‘dispatchable’, synchronous renewable alternatives such as concentrating solar thermal. Furthermore, the considerable cost risk associated with nuclear power is a significant disadvantage. Copyright © 2016 John Wiley & Sons, Ltd.     

Comprehensive assessment of line‐/point‐focus combined scheme for concentrating solar power system

The line‐/point‐focus combined scheme for concentrating solar power (CSP) system is proposed. For solar field, the parabolic trough (PT) or linear Fresnel (LF) is used as the line‐focus preheating and evaporation stages while the solar tower is used as the point‐focus superheating and reheating stages. The combined schemes benefit from the high concentration ratio of point‐focus technology and low cost of line‐focus technology. Particularly, the combined scheme guarantees the concentrated solar thermal energy matching the temperature requirement of steam generation process with less exergy loss. Performance and economic assessments have been performed for 50 MW_e CSP system with two of the combined schemes, ie, PT (synthetic oil, SO) + Tower (molten salt, MS) and LF (direct steam generation, DSG) + Tower (DSG), as well as existing single schemes being the references, ie, PT (SO), LF (DSG), Tower (MS), and Tower (DSG). The comparative results show that the combined schemes are superior to liner‐focus schemes in efficiency and to point‐focus schemes in capital cost and scalability. Specifically, the PT (SO) + Tower (MS) system suggests the favorable potential in practical application with the highest annual net solar‐to‐electrical energy conversion efficiency of 16.07% and the reasonable levelized cost of electricity (LCOE) of 16.121 US cent/(kW·h). This work provides an alternative guidance for future development of the CSP technology.     

湖北省光伏发电项目经济性预测研究

基于平准化度电成本模型,结合湖北省实例样本数据,构建2016—2019年湖北省光伏发电的成本结构框架,分析影响建设及度电成本的主要因素。设置低等、中等与高等三种情景模式与作用因子,研究不同情形下湖北省光伏度电成本的未来发展趋势,讨论不同影响因子对度电成本下降的驱动效果。结果发现:若无外力干预,湖北省光伏度电成本下降缓慢,预计将于“十四五”末期甚至“十五五”初期方能达到平价上网要求;核心部件成本下降及能源利用效率提升将大幅促进度电成本的降低;政策因素可显著减少隐性成本从而推动光伏度电成本加速下降。     

碳价格对低碳基荷发电技术相对竞争力的影响评估

根据国际能源机构（IEA）的评估标准选出合适的低碳基荷发电技术,分析了引入碳价格后发电成本和温室气体排放强度的变动情况,并研究碳定价机制对各发电技术相对竞争力的影响。结果表明,核电成本的排放量最低,竞争优势最大;太阳能热利用成本的排放量最高,相对竞争力最小。目前依靠碳捕捉与封存技术（CCS）的传统煤粉蒸汽锅炉发电（PFcoal/ CCS）、联合循环发电系统（IGCC/ CCS）、联合循环燃气涡轮（CCGT/ CCS）技术是有风险的策略。     

Solar thermal power generation in India: effect of potential incentives on unit cost of electricity

For large-scale dissemination of solar thermal power plants, in countries identified with huge potential, governments are offering various incentives. In an attempt towards studying the effectiveness of various incentives in reducing the levelised cost of electricity (LCOE) delivered by solar thermal power plants in India, this paper presents simple mathematical frameworks that facilitate the determination of the required level of an incentive so as to ensure that the LCOE is within a pre-specified limit. For example, for a 50?MW solar thermal power plant at Barmer (Rajasthan), LCOE of Rs. 9.75 per kWh can be achieved by providing 6.3% viability gap funding or an interest subsidy of 3% or provision of 32% investment tax credits to the equity investor or provision of production tax credits to the equity investor at the rate of Rs. 0.81 per kWh for first 10 years of operation of a plant.     

Discrete harmony search based size optimization of Integrated Renewable Energy System for remote rural areas of Uttarakhand state in India

In the recent years, decentralized power generation using locally available renewable energy resources has been recognized as a cost effective alternative of uneconomical grid extension. The present paper deals with the size optimization of Integrated Renewable Energy System (IRES) for a cluster of villages of Uttarakhand state in India. The proposed IRES consists of locally available renewable energy resources of Micro Hydro Power (MHP), biogas, biomass, wind and solar energy in order to meet the electrical and cooking demands of the study area. A system operation strategy has been developed in the paper for size optimization of IRES. Also, the loss of power supply probability (LPSP) has been used as the reliability criteria in order to ensure the continuous supply of power without any failure problems. Further, in order to utilize renewable energy resources in different contributions, four different resource scenarios are considered for the study area. Finally, the total net present cost (NPC) of the considered scenarios has been optimized using discrete harmony search (DHS) algorithm. Among different scenarios, MHP-biogas-biomass-wind-solar-battery based IRES offers the lowest net present cost of INR 49.0309 million at the estimated LCOE of INR 5.47/kWh.     

A review of the IEA/NEA Projected Costs of Electricity – 2015 edition

The IEA/NEA recently issued their eighth edition of the Study on the “Projected Costs of Generating Electricity” – 2015 edition. The Study is mainly concerned with calculating the levelised cost of electricity (LCOE). The LCOE calculations are based on a levelised average life time cost approach using the discounted cash flow (DCF) method. The analysis was this year, and for the first time, performed using three discount rates (3%, 7%, and 10%). The LCOE can serve as a tool for calculating the cost of different generation technologies. However the Study's usefulness is affected by its narrow base of a limited set of countries that are not necessarily representative. It ignored the negative role of subsidies and did not provide a methodology for selective application of the discount rates and costing of carbon. The global power generation scene is changing. Generation growth in OECD countries has become very limited; simultaneously there is rapid growth of varying renewables (VRE) generation which needs special criteria for assessing its system cost. All this demands a rethinking of the application and usefulness of the LCOE in future generation planning.     

Overview of Concentrated Solar Power

CSP （concentrated solar power） has been viewed as the technology that if properly developed could lead to a large scale conversion of solar energy into electricity. CSP is a type of solar energy converter that is classified as thermal converter because the output power produced is a function of the operating temperature. The main components of a CSP plant are the solar field which is made up of the heliostat arrays, the receiver tower, the heat transfer fluid, the molten salt thermal energy storage tanks and the power conversion unit, which is made up of the turbine and the generator. The main advantage of CSP is that of a cheap thermal storage （i.e., molten salt storage） which makes it possible to dispatch power at a cost comparable to the grid electricity. Simulations run with the SAM （systems advisory model） developed by NREL （National Renewable Energy Laboratory） showed that CSP is capable of delivering electricity at the cost of 17UScents per kWh for the 30-year life of the plant. The main disadvantage of CSP however, is that of low efficiency （8%-16%）. There are ongoing research works to improve the efficiency of the CSP. One way to improve the efficiency is to increase the operating temperature of the system. In this paper, the authors discussed different modules of the CSP plant and suggested ways to improve on the conversion efficiencies of individual modules. Finally, an overall systems performance simulation is carried using SAM and the simulation results show that electricity can be produced using CSP at the cost of RI.05 per kWh.     

Comprehensive assessment on a hybrid PEMFC multi-generation system integrated with solar-assisted methane cracking

A hybrid proton exchange membrane fuel cell (PEMFC) multi-generation system model integrated with solar-assisted methane cracking is established. The whole system mainly consists of a disc type solar Collector, PEMFC, Organic Rankine cycle (ORC). Methane cracking by solar energy to generate hydrogen, which provides both power and heat. The waste heat and hydrogen generated during the reaction are efficiently utilized to generate electricity power through ORC and PEMFC. The mapping relationships between thermodynamic parameters (collector temperature and separation ratio) and economic factors (methane and carbon price) on the hybrid system performance are investigated. The greenhouse gas (GHG) emission reductions and levelized cost of energy (LCOE) are applied to environmental and economic performance evaluation. The results indicate that the exergy utilization factor (EXUF) and energy efficiency of the novel system can reach 21.9% and 34.6%, respectively. The solar-chemical energy conversion efficiency reaches 40.3%. The LCOE is 0.0733 $/kWh when the carbon price is 0.725 $/kg. After operation period, the GHG emission reduction and recovered carbon can reach 4 × 10⁷ g and 14,556 kg, respectively. This novel hybrid system provides a new pathway for the efficient utilization of solar and methane resources and promotes the popularization of PEMFC in zero energy building.     

Techno – Economic assessment of flexible decarbonized hydrogen and power co-production based on natural gas dry reforming

The need for flexible power plants could increase in the future as variable renewable energy (VRE) share will increase in the power grid. These power plants could balance the increasing strain on electricity grids by renewables. The proposed plant in this paper can adapt to these ramps in electricity demand of the power grid by maintaining a constant feed and producing also high purity hydrogen. Dry methane reforming (DMR) is incorporated into a flexible power plant model and the key performance indicators are calculated from a techno-economic perspective. The net output of the plant is 450 MW with the possibility to lower power production and produce hydrogen, maintaining a high CO₂ capture rate (72%). Two cases are compared to the base case to quantify: (i) energy and cost penalties for CO₂ capture and (ii) advantages of flexible power plant operation. The levelized cost of electricity (LCOE) for the base case is 67 Euro/MWh, the addition of a carbon capture unit increases it to 82 Euro/MWh. In the case of flexible operation, both the LCOE and levelized cost of hydrogen (LCOH) are calculated and the two depend on the cost allocation factor. The LCOE ranges from 65 to 85 Euro/MWh while the LCOH from 0.15 to 0.073 Euro/Nm³. The DMR power plant presented in Cases 1 and 2 present little advantages in today's market conditions however, the flexible plant (Case 3) can be viable option in balancing VRE.     

The cost benefit analysis of implementing photovoltaic solar system in the state of Kuwait

In addition to the high financial cost of energy resources required to meet the rising demand for electricity consumption in Kuwait, the negative environmental impact of fossil fuel is increasing. Hence, the objective of this paper is to determine the economic feasibility and viability of implementing PV solar energy in the State of Kuwait. It was found that the positive characteristics of solar radiation in Kuwait play a critical role in enhancing the feasibility of implementing solar systems. Under the present price of 5$/W and 15% efficiency, the LCOE of a 1 MW station is estimated to be around $0.20/kWh. This LCOE can be feasible only when the cost of oil is around 100$/barrel. The Cost Benefit Analysis showed that when the value of saved energy resources used in producing traditional electricity, and the cost of lowering CO₂ emissions are accounted for, the true economic cost of LCOE of a PV system will decline significantly. The preliminary economic analysis recommends the implementation of PV technology in Kuwait.