Electricity network planning targeting Low-Carbon energy transition

Electricity sector, as one of the major emission sources of carbon dioxide (CO₂), is responsible for reducing carbon emissions and is a major player that addresses global climate change. In the efforts to mitigate the impacts of climate change over the coming decades, decarbonizing power systems is critical. To achieve this goal, power generation systems need a transition from a high reliance on coal-fired power stations to a low-carbon energy mix. This paper proposes a transition planning method that includes the retirement of coal-fired generators and the integration of large-scale renewable power plants. Hence, transmission systems need to be upgraded simultaneously with the changing of generation mix to ensure system reliability. This paper also considers carbon emission cost and introduces and compares two models, which include carbon trading and carbon tax. Furthermore, issues related to the ramping of renewable power systems that are caused by the large penetration of renewable power generators are taken into account by adding the cost related to the sudden change of renewable generation (ramping cost) in the objective function. The proposed model is demonstrated on a modified IEEE 24-bus RTS system.     

Achieving 60% CO2 reductions within the UK energy system—Implications for the electricity generation sector

This paper explores how investment in the UK electricity generation sector can contribute to the UK goal of reducing CO₂ emissions with 60% by the year 2050 relative to the 1990 emissions. Considering likely development of the transportation sector and industry over the period, i.e. a continued demand growth and dependency on fossil fuels and electricity, the analysis shows that this implies CO₂ emission reductions of up to 90% by 2050 for the electricity sector. Emphasis is put on limitations imposed by the present system, described by a detailed database of existing power plants, together with meeting targets on renewable electricity generation (RES) including assumptions on gas acting as backup technology for intermittent RES. In particular, it is investigated to what extent new fossil fuelled and nuclear power is required to meet the year 2050 demand as specified by the Royal Commission on Environmental Pollution (RCEP). In addition, the number of sites required for centralized electricity generation (large power plants) is compared with the present number of sites. A simulation model was developed for the analysis. The model applies the UK national targets on RES, taken from Renewable Obligation (RO) for 2010 and 2020 and potentials given by RCEP for 2050, and assumed technical lifetimes of the power plants of the existing system and thus, links this system with targets for the years 2010, 2020 and 2050.     

Environmental emission mitigation potential of efficient electrical appliances in Sri Lanka

This study assesses the techno-economic potential of selected efficient demand-side appliances to mitigate emission of air pollutants from the power sector of Sri Lanka. The study shows that through the use of the selected efficient appliances a total of about 38 646 GWh (i.e. 18·5% of total electricity generation) and about 25·6% (29 541, 000 tons), 34·2% (293,000 tons) and 34·6% (374,000 tons) of the total CO₂, SO₂ and NO_x emission respectively could be avoided during 1997–2015 with the use of the efficient appliances from the technical and national economic perspectives. The generation savings from utility and user perspectives and emission mitigation potential are, however, significantly smaller as all the selected appliances are not found cost effective from these perspectives. This is mainly because electricity prices in the commercial and industrial sectors exceed the corresponding long-run marginal cost (LRMC) of electricity supply. © 1998 John Wiley & Sons, Ltd.     

Supply- and demand-side effects of power sector planning with CO2 mitigation constraints in a developing country

In this paper, the implications of CO₂ emission mitigation constraints in the power sector planning in Indonesia are examined using a long term integrated resource planning model. An approach is developed to assess the contributions of supply- and demand-side effects to the changes in CO₂, SO₂ and NO_x emissions from the power sector due to constraints on CO₂ emissions. The results show that while both supply- and demand-side effects would act towards the reduction of CO₂, SO₂ and NO_x emissions, the supply-side options would play the dominant role in emission mitigations from the power sector in Indonesia. The CO₂ abatement cost would increase from US$7.8 to US$9.4 per ton of CO₂, while the electricity price would increase by 3.1 to 19.8% if the annual CO₂ emission reduction target is raised from 10 to 25%.     

Use of wastes as option for the mitigation of CO2 emissions in the Brazilian power sector

The present study presents an analysis of the options available for the mitigation of CO₂ emissions in the Brazilian power sector. The objective is to verify the potential use of wastes for electrical energy generation and its competitiveness in comparison with other sources of renewable energy. A comparison was made using marginal abatement cost curves derived from a reference scenario obtained from earlier studies dealing with the expansion of the Brazilian power sector. The results showed that the availability of wastes is significant and that they can be used at a cost 20–60% lower than that of wind power generation, a subsidized source of energy in Brazil. It can therefore be concluded that it would be more efficient if incentives were applied to the use of wastes for electrical power generation since it offers socio-environmental benefits which go far beyond the reduction of CO₂ emissions.     

Significance of CO2-free hydrogen globally and for Japan using a long-term global energy system analysis

In this paper, the significance of CO₂-free hydrogen is discussed using a long-term global energy system. The energy demand–supply system including CO₂-free hydrogen was assumed, though there are still large uncertainties as to whether a global CO₂-free hydrogen energy system will be deployed. System analysis was conducted using the global and long-term intertemporal optimization energy model GRAPE under severe CO₂ emission constraints. Applied global CO₂ constraints for 2050 were a 50% reduction from 1990 levels. CO₂ constraints accounting for Intended Nationally Determined Contributions (INDCs) in each region were also considered. A variety of energy resources and technologies were considered in this model. Hydrogen can be produced from low-grade coal or natural gas with CO₂ capture and electricity from renewable energy. The hydrogen CIF (cost, insurance, and freight) price for Japan was about 3.2 cents/MJ in 2030. Hydrogen demand technologies considered in this paper are hydrogen-fired power plants, direct combustion, combined heat and power (fuel cells, gas engines, and gas turbines), fuel cell vehicles, and hydrogen internal combustion engine vehicles. The majority of CO₂-free hydrogen was deployed in the transportation sector. CO₂-free hydrogen was utilized in the power sector, where deployment of other zero emission technology has some constraints. From an economic viewpoint, CO₂-free hydrogen can reduce the global energy system cost. From the viewpoint of a localized region, such as Japan, deployment of CO₂-free hydrogen can improve energy security and environmental indicators.     

Five-year technology selection optimization to achieve specific CO2 emission reduction targets

Long-term planning for replacement of fossil fuel energy technologies with renewables is of great importance for achieving GHG emission reduction targets. The current study is focused on developing a five-year mathematical model for finding the optimal sizing of renewable energy technologies for achieving certain CO₂ emission reduction targets. A manufacturing industrial facility which uses CHP for electricity generation and natural gas for heating is considered as the base case in this work. Different renewable energy technologies are developed each year to achieve a 4.53% annual CO₂ emission reduction target. The results of this study show that wind power is the most cost-effective technology for reducing emissions in the first and second year with a cost of 44 and 69 CAD per tonne of CO₂, respectively. Hydrogen, on the other hand, is more cost-effective than wind power in reducing CO₂ emissions from the third year on. The cost of CO₂ emission reduction with hydrogen doesn't change drastically from the first year to the fifth year (107 and 130 CAD per tonne of CO₂). Solar power is a more expensive technology than wind power for reducing CO₂ emissions in all years due to lower capacity factor (in Ontario), more intermittency (requiring mores storage capacity), and higher investment cost. A hybrid wind/battery/hydrogen energy system has the lowest emission reduction cost over five years. The emission reduction cost of such hybrid system increases from 44 CAD per tonne of CO₂ in the first year to 156 CAD per tonne of CO₂ in the fifth year. The developed model can be used for long-term planning of energy systems for achieving GHG emission targets in a regions/country which has fossil fuel-based electricity and heat generation infrastructure.     

Targeting existing power plants: EPA emission reduction with wind and demand response

Electricity generation accounts for 40% of CO₂ emissions from fossil fuel combustion in the United States. Section 111 of the Clean Air Act (CAA) allows for greenhouse gas emission regulation by the US Environmental Protection Agency (EPA). In June 2014, EPA issued the Clean Power Plan that proposes regulation of existing power plants via a “best system of emission reduction” or BSER. Reducing carbon dioxide emissions caused by electricity generation is one of the main motivations for increasing wind power and other renewable energy use, and this option is included in the BSER. This paper applies Monte Carlo simulation with a two-stage power flow optimization framework to analyze the potential CO₂ emission reduction with 10% and 20% wind penetration using the proposed BSER. The results show that EPA's BSER does achieve significant emission reduction, but an increase in cost of electricity and load curtailment can result if significant wind is installed without other measures. These concerns are eliminated by including recourse to real-time demand response along with EPA's BSER, suggesting that the proposed BSER, implemented alone, could be insufficient for reaching EPA's target CO₂ reductions while also safeguarding power system reliability and cost.     

Vision 2023: Feasibility analysis of Turkey's renewable energy projection

Electricity consumption of Turkey at the year 2023 is estimated to be around 530,000 GWh. Turkey plans to supply 30% or 160,000 GWh of this demand from renewable energy sources according to the recently avowed government agenda Vision 2023. However, the current installed renewable energy capacity is around 60,000 GWh. Detailed literature analysis showed that only wind and solar energy potential in Turkey can solely supply this demand. In this study, two different scenarios were generated to analyse the cost and environmental impacts of supplying this demand. Scenario 1, which is derived from the official Vision 2023 targets, suggests supplying this demand from wind, solar, geothermal energy and hydropower. The total projected cost based on Scenario 1 is estimated to be $31.000 billion and annual greenhouse gas emissions of 1.05 million tonnes of CO₂ equivalent. According to Scenario 2 or the contrary setup it is assumed that the required demand gap could not be supplied from new renewable energy investments but equally from coal and natural gas. The projected cost is estimated to be around $8.000 billion and annual greenhouse gas emissions at appalling 71.30 million tonnes of CO₂ equivalent. Assuming carbon tax at the year 2023 to be $50 per tonne of CO₂ emitted, supplying the demand from renewable energy sources according to Scenario 1 would generate savings worth nearly $2.175 billion from environmental taxes annually. Thus, making the payback time of the renewable energy investments less than 15 years.     

Quantifying CO2 abatement costs in the power sector

CO₂ cap-and-trade mechanisms and CO₂ emission taxes are becoming increasingly widespread. To assess the impact of a CO₂ price, marginal abatement cost curves (MACCs) are a commonly used tool by policy makers, providing a direct graphical link between a CO₂ price and the expected abatement. However, such MACCs can suffer from issues related to robustness and granularity. This paper focuses on the relation between a CO₂ emission cost and CO₂ emission reductions in the power sector. The authors present a new methodology that improves the understanding of the relation between a CO₂ cost and CO₂ abatement. The methodology is based on the insight that CO₂ emissions in the power sector are driven by the composition of the conventional power portfolio, the residual load and the generation costs of the conventional units. The methodology addresses both the robustness issue and the granularity issue related to MACCs. The methodology is based on a bottom-up approach, starting from engineering knowledge of the power sector. It offers policy makers a new tool to assess CO₂ abatement options. The methodology is applied to the Central Western European power system and illustrates possible interaction effects between, e.g., fuel switching and renewables deployment.     

Biomass and bio-energy utilisation in a farm-based combined heat and power facility

Five different renewable energy technologies located at an agricultural and environmental research centre in Northern Ireland, were monitored to assess the cost, performance and efficiency in real-time operation of solar and bio-energy produced from crops and farm wastes utilised for energy generation in industrial grade equipment. Monitoring was conducted over a six year period, with power units running simultaneously or intermittently according to demand from the local district heating system. The purpose of the work was to investigate fossil fuel (oil) displacement, carbon dioxide emission (CO₂e) reductions, financial and environmental sustainability of these technologies in a farm based scenario. Between 2009 and 2014, total heat output from the centre was 7.75 GWh with contributions of 47.2%, 17.1%, 9.8% and 13.5% from the biomass, biogas, multi-fuel boiler and biogas CHP unit respectively. Solar thermal produced 0.49% and the back-up oil boiler 11.9%. Total electrical output was 572.6 MWh with 95.2% generated from biogas CHP and 4.8% from the solar PV system. Fossil fuel and average CO₂e reductions ranged from 20.1% to 54.1% and 23.3–55.7% respectively, reductions that combined with financial savings to present a viable and sustainable renewable energy system.     

Transition scenarios of power generation in China under global 2 °C and 1.5 °C targets

Under the Paris Agreement, targets implemented for 2100 specify temperature increases well below 2 °C, with an ambitious target of 1.5 °C. China signed this agreement and will support these global targets. The question remains whether they are possible, especially considering the slow progress in recent decades, despite the fact that the Kyoto Protocol implemented these targets in 2010. The Intergovernmental Panel on Climate Change (IPCC) required modeling research teams to analyze possible pathways, policy options, and cost benefit analyses for GHG mitigation. China’s CO₂ emissions from the energy and cement industries already accounted for almost 29% of global emissions in 2017, and this trend is expected to continue increasing. The role of China in global GHG mitigation is therefore crucial. This study presents a scenario analysis for China’s power generation against the background of the global 2 °C and 1.5 °C targets. We discuss the possibility of a lower CO₂ emission power generation scenario in China in order to evaluate the national emission pathway towards these targets. Our findings suggest that China can accomplish rapid transition in the power generation sector, reaching its emission peak before 2025. This would make the global 2 °C target possible because energy system development is a key factor. Furthermore, the recent progress of key power generation technologies, potential for further investment in the power generation sector, and recent policy implementation all significantly contribute to China following a low carbon emission development pathway.     

Factors affecting CO2 emission from the power sector of selected countries in Asia and the Pacific

This study analyzes the key factors behind the CO₂ emissions from the power sector in fifteen selected countries in Asia and the Pacific using the Log-Mean Divisia Index method of decomposition. The roles of changes in economic output, electricity intensity of the economy, fuel intensity of power generation and generation structure are examined in the evolution of CO₂ emission from the power sector of the selected countries during 1980–2004. The study shows that the economic growth was the dominant factor behind the increase in CO₂ emission in ten of the selected countries (i.e., Australia, China, India, Japan, Malaysia, Pakistan, South Korea, Singapore, Thailand and Vietnam, while the increasing electricity intensity of the economy was the main factor in three countries (Bangladesh, Indonesia and Philippines). Structural changes in power generation were found to be the main contributor to changes in the CO₂ emission in the case of Sri Lanka and New Zealand.     

Effects of cross-border power trade between Laos and Thailand: Energy security and environmental implications

This paper analyzed the effects of hydropower development in Laos and power trade between Laos and Thailand on economy wide, energy resource mix, power generation capacity mix, energy system cost, environment, as well as, energy security. A MARKAL-based model for an integrated energy system of Laos and Thailand was developed to assess the effects of energy resource development and trade to meet the national energy demands of the two countries. Two national MARKAL-based energy system models of Laos and Thailand were formulated for the study. The results show that 80% exploitation of water resource in Laos would induce power trade between the countries. The integrated energy system cost is found to decrease marginally but it would mitigate the CO₂ emission by 2% when compared with the base case. Thailand is expected to gain benefit from the increased level of power imported from Laos in terms of the lower energy system cost, better environmental quality and, greater diversification of energy sources. As compared to the base case, Laos would become the net energy exporter, earn significant export revenue, and improve the increase in revenue of energy export per increase in total energy system cost from the maximum exploitation of hydropower resource.     

Supply- and demand-side effects of power sector planning with demand-side management options and SO2 emission constraints

This paper examines the implications of SO₂ emission mitigation constraints in the power sector planning in Indonesia—a developing country—during 2003–2017 from a long term integrated resource planning perspective. A decomposition model is developed to assess the contributions of supply- and demand-side effects to the total changes in CO₂, SO₂ and NO_x emissions from the power sector due to constraints on SO₂ emissions. The results of the study show that both the supply- and demand-side effects would act towards the reduction of CO₂, SO₂ and NO_x emissions. However, the supply-side effect would play the dominant role in emission mitigations from the power sector in Indonesia. The average incremental SO₂ abatement cost would increase from US$ 970 to US$ 1271 per ton of SO₂, while electricity price would increase by 2–18% if the annual SO₂ emission reduction target is increased from 10% to 25%.     

Performance analysis of a CO2 recycling system which utilizes solar energy

In this report, a CO₂ recycling system is proposed and designed for the purpose of CO₂ mitigation through utilization of solar energy (photovoltaic power generation). A performance analysis of the potential of this system for CO₂ reduction is performed as one of the life cycle analyses (LCA) of this system. The CO₂ emission from building the photovoltaic (PV) power generation facilities represents the largest fraction of CO₂ emission and accounts for 81 per cent of the CO₂ emission from building of plants. The CO₂ balance ratio of the system is approximately 1.4. It clearly reveals that this system would be an effective way to reduce CO₂ emissions and to utilize PV power generation as a natural energy source. Copyright © 2001 John Wiley & Sons, Ltd.     

Impact of the German nuclear phase-out on Europe's electricity generation—A comprehensive study

The combination of the ambitious German greenhouse gas reduction goals in the power sector and the nuclear phase-out raises many questions concerning the operational security of the German electricity generation system. This paper focusses on the technical feasibility (electricity generation and transmission) and CO₂-impact of the German nuclear phase-out on the short term (2012–2022).A detailed electricity generation simulation model is employed, including the German transmission grid and its international connections. A range of different conventional and renewable energy sources (RES) scenarios is considered. Results are presented for the change in generation mix, on the flows on the transmission network and on operational reliability issues.The scenario analysis shows that nuclear generation will be replaced mainly by coal- and lignite-based generation. This increases the CO₂-intensity of the German electricity sector. Furthermore, the results indicate that the German electricity export will decrease and under certain circumstances, the system becomes infeasible. Keeping some nuclear power plants online, would mitigate these effects. The amount of electricity generated from RES is shown to be the main driver for grid congestion.     

Internalisation of external cost in the power generation sector: Analysis with Global Multi-regional MARKAL model

The Global MARKAL-Model (GMM), a multi-regional “bottom-up” partial equilibrium model of the global energy system with endogenous technological learning, is used to address impacts of internalisation of external costs from power production. This modelling approach imposes additional charges on electricity generation, which reflect the costs of environmental and health damages from local pollutants (SO₂, NO_x) and climate change, wastes, occupational health, risk of accidents, noise and other burdens. Technologies allowing abatement of pollutants emitted from power plants are rapidly introduced into the energy system, for example, desulphurisation, NO_x removal, and CO₂ scrubbers. The modelling results indicate substantial changes in the electricity production system in favour of natural gas combined cycle, nuclear power and renewables induced by internalisation of external costs and also efficiency loss due to the use of scrubbers. Structural changes and fuel switching in the electricity sector result in significant reduction of emissions of both local pollution and CO₂ over the modelled time period. Strong decarbonisation impact of internalising local externalities suggests that ancillary benefits can be expected from policies directly addressing other issues then CO₂ mitigation. Finally, the detailed analysis of the total generation cost of different technologies points out that inclusion of external cost in the price of electricity increases competitiveness of non-fossil generation sources and fossil power plants with emission control.     

Valuation of marginal CO2 abatement options for electric power plants in Korea

The electricity generation sector in Korea is under pressure to mitigate greenhouse gases as directed by the Kyoto Protocol. The principal compliance options for power companies under the cap-and-trade include the application of direct CO₂ emission abatement and the procurement of emission allowances. The objective of this paper is to provide an analytical framework for assessing the cost-effectiveness of these options. We attempt to derive the marginal abatement cost for CO₂ using the output distance function and analyze the relative advantages of emission allowance procurement option as compared to direct abatement option. Real-option approach is adopted to incorporate emission allowance price uncertainty. Empirical result shows the marginal abatement cost with an average of €14.04/ton CO₂ for fossil-fueled power plants and confirms the existence of substantial cost heterogeneity among plants which is sufficient to achieve trading gains in allowance market. The comparison of two options enables us to identify the optimal position of the compliance for each plant. Sensitivity analyses are also presented with regard to several key parameters including the initial allowance prices and interest rate. The result of this paper may help Korean power plants to prepare for upcoming regulations targeted toward the reduction of domestic greenhouse gases.     

Power-to-ammonia in future North European 100 % renewable power and heat system

Power-to-gas and other chemicals-based storages are often suggested for energy systems with high shares of variable renewable energy. Here we study the North European power and district heat system with alternative long-term storage, the power-to-ammonia (P2A) technology. Assuming fully renewable power and heat sectors and large-scale electrification of road transport, we perform simultaneous optimization of capacity investments and dispatch scheduling of wind, solar, hydro and thermal power, energy storages as well as transmission, focusing on year 2050. We find that P2A has three major roles: it provides renewable feedstock to fertilizer industry and it contributes significantly to system balancing over both time (energy storage) and space (energy transfer). The marginal cost of power-based ammonia production in the studied scenarios varied between 431 and 528 €/t, which is in the range of recent ammonia prices. Costs of P2A plants were dominated by electrolysis. In the power and heat sector, with our cost assumptions, P2A becomes competitive compared to fossil natural gas only if gas price or CO₂ emission price rises above 70 €/MWh or 200 €/tCO₂.