Long-term CO2 emissions reduction target and scenarios of power sector in Taiwan

This study analyses a series of carbon dioxide (CO₂) emissions abatement scenarios of the power sector in Taiwan according to the Sustainable Energy Policy Guidelines, which was released by Executive Yuan in June 2008. The MARKAL-MACRO energy model was adopted to evaluate economic impacts and optimal energy deployment for CO₂ emissions reduction scenarios. This study includes analyses of life extension of nuclear power plant, the construction of new nuclear power units, commercialized timing of fossil fuel power plants with CO₂ capture and storage (CCS) technology and two alternative flexible trajectories of CO₂ emissions constraints. The CO₂ emissions reduction target in reference reduction scenario is back to 70% of 2000 levels in 2050. The two alternative flexible scenarios, Rt4 and Rt5, are back to 70% of 2005 and 80% of 2005 levels in 2050. The results show that nuclear power plants and CCS technology will further lower the marginal cost of CO₂ emissions reduction. Gross domestic product (GDP) loss rate in reference reduction scenario is 16.9% in 2050, but 8.9% and 6.4% in Rt4 and Rt5, respectively. This study shows the economic impacts in achieving Taiwan's CO₂ emissions mitigation targets and reveals feasible CO₂ emissions reduction strategies for the power sector.     

Multi-objective optimization model for sustainable Indonesian electricity system: Analysis of economic,environment, and adequacy of energy sources

This paper presents a multi-objective optimization model for a long-term generation mix in Indonesia. The objective of this work is to assess the economic, environment, and adequacy of local energy sources. The model includes two competing objective functions to seek the lowest cost of generation and the lowest CO₂ emissions while considering technology diffusion. The scenarios include the use of fossil reserves with or without the constraints of the reserve to production ratio and exports. The results indicate that Indonesia should develop all renewable energy and requires imported coal and natural gas. If all fossil resources were upgraded to reserves, electricity demand in 2050 could be met by domestic energy sources. The maximum share of renewable energy that can be achieved in 2050 is 33% with and 80% without technology diffusion. The least cost optimization produces lower generation costs than the least CO₂ emissions, as well as the combined scenario. Total CO₂ emissions in 2050 are five to six times as large as current emissions. The least CO₂ emissions scenario can reduce almost half of the CO₂ emissions of the least cost scenario by 2050. The proposed multi-objective optimization model leads some optimal solutions for a more sustainable electricity system.     

CCS: A future CO2 mitigation option for Germany?—A bottom-up approach

The role that carbon capture and storage (CCS) technologies could play within the framework of an overall CO₂ mitigation strategy is examined in the form of scenarios up to 2030 with the example of Germany. As the calculations show, the use of CCS can represent an interesting mitigation option in view of stringent CO₂ reduction goals. The scenarios, performed with the aid of the IKARUS optimization model, however, also show that according to cost-efficiency criteria a large number of measures would have to be taken covering all energy sectors. CCS can at best represent one element in an overall strategy. The model results show that a mitigation goal for 2030 corresponding to a 35% reduction of CO₂ as compared to 1990 is necessary to trigger a significant contribution of CCS. As an alternative to a CO₂ restriction, we also calculated reduction scenarios based on CO₂ penalties. These scenarios showed that a penalty price of approximately 30 €/tCO₂ is necessary before CCS can be included in the model.     

Emissions reduction scenarios in the Argentinean Energy Sector

In this paper the LEAP, TIAM-ECN, and GCAM models were applied to evaluate the impact of a variety of climate change control policies (including carbon pricing and emission constraints relative to a base year) on primary energy consumption, final energy consumption, electricity sector development, and CO₂ emission savings of the energy sector in Argentina over the 2010–2050 period. The LEAP model results indicate that if Argentina fully implements the most feasible mitigation measures currently under consideration by official bodies and key academic institutions on energy supply and demand, such as the ProBiomass program, a cumulative incremental economic cost of 22.8 billion US$(2005) to 2050 is expected, resulting in a 16% reduction in GHG emissions compared to a business-as-usual scenario. These measures also bring economic co-benefits, such as a reduction of energy imports improving the balance of trade. A Low CO₂ price scenario in LEAP results in the replacement of coal by nuclear and wind energy in electricity expansion. A High CO₂ price leverages additional investments in hydropower. By way of cross-model comparison with the TIAM-ECN and GCAM global integrated assessment models, significant variation in projected emissions reductions in the carbon price scenarios was observed, which illustrates the inherent uncertainties associated with such long-term projections. These models predict approximately 37% and 94% reductions under the High CO₂ price scenario, respectively. By comparison, the LEAP model, using an approach based on the assessment of a limited set of mitigation options, predicts an 11.3% reduction. The main reasons for this difference include varying assumptions about technology cost and availability, CO₂ storage capacity, and the ability to import bioenergy. An emission cap scenario (2050 emissions 20% lower than 2010 emissions) is feasible by including such measures as CCS and Bio CCS, but at a significant cost. In terms of technology pathways, the models agree that fossil fuels, in particular natural gas, will remain an important part of the electricity mix in the core baseline scenario. According to the models there is agreement that the introduction of a carbon price will lead to a decline in absolute and relative shares of aggregate fossil fuel generation. However, predictions vary as to the extent to which coal, nuclear and renewable energy play a role.     

Decarbonization synergies from joint planning of electricity and hydrogen production: A Texas case study

Hydrogen (H₂) shows promise as an energy carrier in contributing to emissions reductions from sectors which have been difficult to decarbonize, like industry and transportation. At the same time, flexible H₂ production via electrolysis can also support cost-effective integration of high shares of variable renewable energy (VRE) in the power system. In this work, we develop a least-cost investment planning model to co-optimize investments in electricity and H₂ infrastructure to serve electricity and H₂ demands under various low-carbon scenarios. Applying the model to a case study of Texas in 2050, we find that H₂ is produced in approximately equal amounts from electricity and natural gas under the least-cost expansion plan with a CO₂ price of $30–60/tonne. An increasing CO₂ price favors electrolysis, while increasing H₂ demand favors H₂ production from Steam Methane Reforming (SMR) of natural gas. H₂ production is found to be a cost effective solution to reduce emissions in the electric power system as it provides flexibility otherwise provided by natural gas power plants and enables high shares of VRE with less battery storage. Additionally, the availability of flexible electricity demand via electrolysis makes carbon capture and storage (CCS) deployment for SMR cost-effective at lower CO₂ prices ($90/tonne CO₂) than for power generation ($180/tonne CO₂). The total emissions attributable to H₂ production is found to be dependent on the H₂ demand. The marginal emissions from H₂ production increase with the H₂ demand for CO₂ prices less than $90/tonne CO₂, due to shift in supply from electrolysis to SMR. For a CO₂ price of $60/tonne we estimate the production weighted-average H₂ price to be between $1.30–1.66/kg across three H₂ demand scenarios. These findings indicate the importance of joint planning of electricity and H₂ infrastructure for cost-effective energy system decarbonization.     

Comparing least cost scenarios for 100% renewable electricity with low emission fossil fuel scenarios in the Australian National Electricity Market

Policy makers face difficult choices in planning to decarbonise their electricity industries in the face of significant technology and economic uncertainties. To this end we compare the projected costs in 2030 of one medium-carbon and two low-carbon fossil fuel scenarios for the Australian National Electricity Market (NEM) against the costs of a previously published scenario for 100% renewable electricity in 2030. The three new fossil fuel scenarios, based on the least cost mix of baseload and peak load power stations in 2010, are: (i) a medium-carbon scenario utilising only gas-fired combined cycle gas turbines (CCGTs) and open cycle gas turbines (OCGTs); (ii) coal with carbon capture and storage (CCS) plus peak load OCGT; and (iii) gas-fired CCGT with CCS plus peak load OCGT. We perform sensitivity analyses of the results to future carbon prices, gas prices, and CO₂ transportation and storage costs which appear likely to be high in most of Australia. We find that only under a few, and seemingly unlikely, combinations of costs can any of the fossil fuel scenarios compete economically with 100% renewable electricity in a carbon constrained world. Our findings suggest that policies pursuing very high penetrations of renewable electricity based on commercially available technology offer a cost effective and low risk way to dramatically cut emissions in the electricity sector.     

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.     

Impacts of China's emissions trading schemes on deployment of power generation with carbon capture and storage

The establishment of an emissions trading scheme (ETS) in China creates the potential for a “least cost” solution for achieving the greenhouse gas (GHG) emissions reductions required for China to meet its Paris Agreement pledges. China has pledged to reduce CO₂ intensity by 60–65% in 2030 relative to 2005 and to stop the increase in absolute CO₂ emissions around 2030. In this series of studies, we enhance the MIT Economic Projection and Policy Analysis (EPPA) model to include the latest assessments of the costs of power generation technologies in China to evaluate the impacts of different potential ETS pathways on deployment of carbon capture and storage (CCS) technology. This paper reports the results from baseline scenarios where power generation prices are assumed to be homogeneous across the country for a given mode of generation. We find that there are different pathways where CCS might play an important role in reducing the emission intensity in China's electricity sector, especially for low carbon intensity targets consistent with the ultimate goals of the Paris Agreement. Uncertainty about the exact technology mix suggests that decision makers should be wary of picking winning technologies, and should instead seek to provide incentives for emission reductions. While it will be challenging to meet the CO₂ intensity target of 550 g/kWh for the electric power sector by 2020, multiple pathways exist for achieving lower targets over a longer timeframe. Our initial analysis shows that carbon prices of 35–40$/tCO₂ make CCS technologies on coal-based generation cost-competitive against other modes of generation and that carbon prices higher than 100$/tCO₂ favor a major expansion of CCS. The next step is to confirm these initial results with more detailed modeling that takes into account granularity across China's energy sector at the provincial level.     

Achieving California's 80% greenhouse gas reduction target in 2050: Technology,policy and scenario analysis using CA-TIMES energy economic systems model

The CA-TIMES optimization model of the California Energy System (v1.5) is used to understand how California can meet the 2050 targets for greenhouse gas (GHG) emissions (80% below 1990 levels). This model represents energy supply and demand sectors in California and simulates the technology and resource requirements needed to meet projected energy service demands. The model includes assumptions on policy constraints, as well as technology and resource costs and availability. Multiple scenarios are developed to analyze the changes and investments in low-carbon electricity generation, alternative fuels and advanced vehicles in transportation, resource utilization, and efficiency improvements across many sectors. Results show that major energy transformations are needed but that achieving the 80% reduction goal for California is possible at reasonable average carbon reduction cost ($9 to $124/tonne CO₂e at 4% discount rate) relative to a baseline scenario. Availability of low-carbon resources such as nuclear power, carbon capture and sequestration (CCS), biofuels, wind and solar generation, and demand reduction all serve to lower the mitigation costs, but CCS is a key technology for achieving the lowest mitigation costs.     

Environmental analysis of a German strategy for carbon capture and storage of coal power plants

This paper combines an existing projection of the development of electricity production with a technology-specific environmental assessment. The combination of these two approaches, which so far have only been performed separately, allows a discussion about environmental effects of carbon capture and storage (CCS) implementation strategies on a national level. The results identify the future role of lignite and hard coal in German power production. The implementation of CCS technology leads to a considerable loss of efficiency. Due to CCS, about 50 million t of lignite will be additionally required in 2030 in comparison to the reference case without CCS in 2010. Increasing demand, the replacement of old plants and the compensation of efficiency losses lead to highly ambitious expansion rates. In the case of CCS implementation, the global warming potential (GWP) can be reduced by up to 70%. However, other environmental impacts increase in part considerably. Compliance with national ceilings for NO_x emissions can only be reached by compensation measures in other sectors. The results of the environmental assessment demonstrate the significant role of the coal composition, coal origin and the required transport. CO₂ pipeline transport and CO₂ storage make a fairly minor contribution to the overall environmental impact.     

Directed technical change and the adoption of CO2 abatement technology: The case of CO2 capture and storage

This paper studies the cost-effectiveness of combining traditional environmental policy, such as CO₂-trading schemes, and technology policy that has aims of reducing the cost and speeding the adoption of CO₂ abatement technology. For this purpose, we develop a dynamic general equilibrium model that captures empirical links between CO₂ emissions associated with energy use, directed technical change and the economy. We specify CO₂ capture and storage (CCS) as a discrete CO₂ abatement technology. We find that combining CO₂-trading schemes with an adoption subsidy is the most effective instrument to induce adoption of the CCS technology. Such a subsidy directly improves the competitiveness of the CCS technology by compensating for its markup over the cost of conventional electricity. Yet, introducing R&D subsidies throughout the entire economy leads to faster adoption of the CCS technology as well and in addition can be cost-effective in achieving the abatement target.     

Exploring the competitiveness of hydrogen-fueled gas turbines in future energy systems

Hydrogen is currently receiving attention as a possible cross-sectoral energy carrier with the potential to enable emission reductions in several sectors, including hard-to-abate sectors. In this work, a techno-economic optimization model is used to evaluate the competitiveness of time-shifting of electricity generation using electrolyzers, hydrogen storage and gas turbines fueled with hydrogen as part of the transition from the current electricity system to future electricity systems in Years 2030, 2040 and 2050. The model incorporates an emissions cap to ensure a gradual decline in carbon dioxide (CO₂) levels, targeting near-zero CO₂ emissions by Year 2050, and this includes 15 European countries.The results show that hydrogen gas turbines have an important role to play in shifting electricity generation and providing capacity when carbon emissions are constrained to very low levels in Year 2050. The level of competitiveness is, however, considerably lower in energy systems that still allow significant levels of CO₂ emissions, e.g., in Year 2030. For Years 2040 and 2050, the results indicate investments mainly in gas turbines that are partly fueled with hydrogen, with 30–77 vol.-% hydrogen in biogas, although some investments in exclusively hydrogen-fueled gas turbines are also envisioned. Both open cycle and combined cycle gas turbines (CCGT) receive investments, and the operational patterns show that also CCGTs have a frequent cyclical operation, whereby most of the start-stop cycles are less than 20 h in duration.     

The impact of regional convergence in energy-intensive industries on China's CO2 emissions and emission goals

In order to respond to climate change, China has committed to reduce national carbon intensity by 40–45% in 2020 and 60–65% in 2030, relative to 2005. Given that energy-intensive industries represent ~80% of total CO₂ emissions in China and that China is a large and diverse country, this paper aims to investigate the potential contribution of regional convergence in energy-intensive industries to CO₂ emissions reduction and to meeting China's emissions goals. To the best of our knowledge this matter has never been explored before. Using panel data from 2001 to 2015, we build three scenarios of future carbon intensities: business as usual (BAU), frontier (based on the directional distance function, in which all regions reach the efficiency frontier) and best available technology (BAT, in which all regions adopt the lowest-emitting technology). The frontier and BAT scenarios represent a weak and a strong form of regional convergence, respectively, and the BAU assumes that it develops following historical patterns. We then use the Kaya identity to estimate CO₂ emissions up to 2030 under the three scenarios. Our results are as follows: (1) Under BAU, the CO₂ emissions of energy-intensive industries increase from 7382.8 Mt in 2015 to 8127.6 Mt in 2030. Under the frontier scenario the emissions in 2030 are 44.23% lower than under business as usual, while under the BAT scenario this value becomes 84.81%. Electricity and ferrous metals are the sectors that most contribute to the reduction potential. (2) Even under BAU the carbon intensity of energy-intensive industries as a whole and all of its constituent sub-sectors except for electricity will decrease by more than the nationally-mandated averages. (3) Regional convergence could help the energy-intensive industries peak its CO₂ emissions before 2030, while under BAU the absolute emissions of the energy-intensive industries keep increasing.     

Energy and environmental implications of carbon emission reduction targets: Case of Kathmandu Valley,Nepal

This paper analyzes the sectoral energy consumption pattern and emissions of CO₂ and local air pollutants in the Kathmandu Valley, Nepal. It also discusses the evolution of energy service demands, structure of energy supply system and emissions from various sectors under the base case scenario during 2005–2050. A long term energy system planning model of the Kathmandu Valley based on the MARKet ALlocation (MARKAL) framework is used for the analyses. Furthermore, the paper analyzes the least cost options to achieve CO₂ emission reduction targets of 10%, 20% and 30% below the cumulative emission level in the base case and also discusses their implications for total cost, technology-mix, energy-mix and local pollutant emissions. The paper shows that a major switch in energy use pattern from oil and gas to electricity would be needed in the Valley to achieve the cumulative CO₂ emission reduction target of 30% (ER30). Further, the share of electricity in the cumulative energy consumption of the transport sector would increase from 12% in the base case to 24% in the ER30 case.     

Potential of new lighting technologies in reducing household lighting energy use and CO2 emissions in Finland

Using light-emitting diodes (LEDs) can significantly reduce the current household lighting energy use in Finland during 2020–2050. Our calculations show that the potential of using LEDs in reducing household lighting energy use and corresponding CO₂ emissions in Finland during 2020–2050 can be significant. Reductions from the current level of Finnish household lighting energy use (1.8 TWh/a) were 59 % in 2020, 72 % in 2030 and 78 % in 2050, when a high LED penetration was assumed. Lighting energy savings in 2020 would mean a 1.3 % reduction from the current total electricity use in Finland (84.2 TWh/a). The starting point in 2012 was that the share of incandescent lamps was 32 % and the share of LED lamps 6 % of the total amount of lamps in an average household. Using the current average emissions factor (current electricity production structure), the saved amount of energy in 2020 means 234,000 tonnes of CO₂. Using the marginal emissions factor, the saved amount of energy means 920,000 tonnes of CO₂ emissions.     

The potential role of concentrated solar power (CSP) in Africa and Europe—A dynamic assessment of technology development,cost development and life cycle inventories until 2050

Concentrated solar power (CSP) plants are one of several renewable energy technologies with significant potential to meet a part of future energy demand. An integrated technology assessment shows that CSP plants could play a promising role in Africa and Europe, helping to reach ambitious climate protection goals. Based on the analysis of driving forces and barriers, at first three future envisaged technology scenarios are developed. Depending on the underlying assumptions, an installed capacity of 120 GW_el, 405 GW_el or even 1,000 GW_el could be reached globally in 2050. In the latter case, CSP would then meet 13–15% of global electricity demand. Depending on these scenarios, cost reduction curves for North Africa and Europe are derived. The cost assessment conducted for two virtual sites in Algeria and in Spain shows a long-term reduction of electricity generating costs to figures between 4 and 6 ct/kWh_el in 2050. The paper concludes with an ecological analysis based on life cycle assessment. Although the greenhouse gas emissions of current (solar only operated) CSP systems show a good performance (31 g CO₂-equivalents/kWh_el) compared with advanced fossil-fired systems (130–900 CO₂-eq./kWh_el), they could further be reduced to 18 g CO₂-eq./kWh_el in 2050, including transmission from North Africa to Europe.     

CO2 emissions from electricity generation in seven Asia-Pacific and North American countries: A decomposition analysis

The Logarithmic Mean Divisia Index (LMDI) method of complete decomposition is used to examine the role of three factors (electricity production, electricity generation structure and energy intensity of electricity generation) affecting the evolution of CO₂ emissions from electricity generation in seven countries. These seven countries together generated 58% of global electricity and they are responsible for more than two-thirds of global CO₂ emissions from electricity generation in 2005. The analysis shows production effect as the major factor responsible for rise in CO₂ emissions during the period 1990–2005. The generation structure effect also contributed in CO₂ emissions increase, although at a slower rate. In contrary, the energy intensity effect is responsible for modest reduction in CO₂ emissions during this period. Over the 2005–2030 period, production effect remains the key factor responsible for increase in emissions and energy intensity effect is responsible for decrease in emissions. Unlike in the past, generation structure effect contributes significant decrease in emissions. However, the degree of influence of these factors affecting changes in CO₂ emissions vary from country to country. The analysis also shows that there is a potential of efficiency improvement of fossil-fuel-fired power plants and its associated co-benefits among these countries.     

Comparison of black liquor gasification with other pulping biorefinery concepts – Systems analysis of economic performance and CO2 emissions

Black liquor gasification (BLG) is being developed as an alternative technology for energy and chemical recovery in kraft pulp mills. This study compares BLG – with downstream production of DME (dimethyl ether) or electricity – with recovery boiler-based pulping biorefinery concepts for different types of mills. The comparison is based on profitability as well as CO₂ emissions, using different future energy market scenarios. The possibility for carbon capture and storage (CCS) is considered. The results show that, if commercialised, BLG with DME production could be profitable for both market pulp mills and integrated pulp and paper mills in all energy market scenarios considered. Recovery boiler-based biorefinery concepts including extraction of lignin or solid biomass gasification with DME production could also be profitable for market and integrated mills, respectively. If the mill is located close to an infrastructure for CO₂ collection and transportation, CCS significantly improves profitability in scenarios with a high CO₂ emissions charge, for both combustion- and gasification-based systems. Concepts that include CCS generally show a large potential for reduction of global CO₂ emissions. Few of the concepts without CCS achieve a significant reduction of CO₂ emissions, especially for integrated mills.     

CO2 savings of ground source heat pump systems – A regional analysis

In the current study the savings of CO₂ emissions due to the use of ground source heat pump (GSHP) systems was investigated in comparison to conventional heating systems. Based on a subsidy program for GSHP systems in southwest Germany, the regional, average, and total CO₂ savings of 1105 installed GSHP systems were determined on a regional scale. The emitted CO₂ per kWh of heating demand for the studied scenario resulted in 149 g CO₂/kWh for GSHP using the German electricity mix and 65 g CO₂/kWh using the regional electricity mix, which results in CO₂ savings of 35% or 72%, respectively. Similar CO₂ avoidances of GSHP systems were found in American and European studies ranging between 15% and 77% strongly depending on the supplied energy for the heat pumps and the efficiency of installation. The resulting CO₂ savings for one installed GSHP unit in the present study therefore range between 1800 and 4000 kg per year. Nevertheless, the minimum average total annual CO₂ savings of all installed GSHP systems due to the subsidy program amounted to 2000 tons per year. The maximum regional avoided additional CO₂ emissions are primarily associated with the affluent suburbs of the most densely populated area in the region. In 2006 the total contribution of CO₂ savings due to GSHP systems in Germany was only about 3.4% of the total renewable energies. However, continuously rising numbers of installed GSHP units and the increasing use of renewable electricity demonstrate that there is a fine opportunity to substantially avoid additional CO₂ emissions associated with the provision of heating (and cooling) of buildings and other facilities.