Putting renewables and energy efficiency to work: How many jobs can the clean energy industry generate in the US?

An analytical job creation model for the US power sector from 2009 to 2030 is presented. The model synthesizes data from 15 job studies covering renewable energy (RE), energy efficiency (EE), carbon capture and storage (CCS) and nuclear power. The paper employs a consistent methodology of normalizing job data to average employment per unit energy produced over plant lifetime. Job losses in the coal and natural gas industry are modeled to project net employment impacts. Benefits and drawbacks of the methodology are assessed and the resulting model is used for job projections under various renewable portfolio standards (RPS), EE, and low carbon energy scenarios We find that all non-fossil fuel technologies (renewable energy, EE, low carbon) create more jobs per unit energy than coal and natural gas. Aggressive EE measures combined with a 30% RPS target in 2030 can generate over 4 million full-time-equivalent job-years by 2030 while increasing nuclear power to 25% and CCS to 10% of overall generation in 2030 can yield an additional 500,000 job-years.     

The production of hydrogen fuel from renewable sources and its role in grid operations

Understanding the scale and nature of hydrogen's potential role in the development of low carbon energy systems requires an examination of the operation of the whole energy system, including heat, power, industrial and transport sectors, on an hour-by-hour basis. The Future Energy Scenario Assessment (FESA) software model used for this study is unique in providing a holistic, high resolution, functional analysis, which incorporates variations in supply resulting from weather-dependent renewable energy generators. The outputs of this model, arising from any given user-definable scenario, are year round supply and demand profiles that can be used to assess the market size and operational regime of energy technologies. FESA was used in this case to assess what - if anything - might be the role for hydrogen in a low carbon economy future for the UK.In this study, three UK energy supply pathways were considered, all of which reduce greenhouse gas emissions by 80% by 2050, and substantially reduce reliance on oil and gas while maintaining a stable electricity grid and meeting the energy needs of a modern economy. All use more nuclear power and renewable energy of all kinds than today's system. The first of these scenarios relies on substantial amounts of ‘clean coal’ in combination with intermittent renewable energy sources by year the 2050. The second uses twice as much intermittent renewable energy as the first and virtually no coal. The third uses 2.5 times as much nuclear power as the first and virtually no coal.All scenarios clearly indicate that the use of hydrogen in the transport sector is important in reducing distributed carbon emissions that cannot easily be mitigated by Carbon Capture and Storage (CCS). In the first scenario, this hydrogen derives mainly from steam reformation of fossil fuels (principally coal), whereas in the second and third scenarios, hydrogen is made mainly by electrolysis using variable surpluses of low-carbon electricity. Hydrogen thereby fulfils a double facetted role of Demand Side Management (DSM) for the electricity grid and the provision of a ‘clean’ fuel, predominantly for the transport sector. When each of the scenarios was examined without the use of hydrogen as a transport fuel, substantially larger amounts of primary energy were required in the form of imported coal.The FESA model also indicates that the challenge of grid balancing is not a valid reason for limiting the amount of intermittent renewable energy generated. Engineering limitations, economic viability, local environmental considerations and conflicting uses of land and sea may limit the amount of renewable energy available, but there is no practical limit to the conversion of this energy into whatever is required, be it electricity, heat, motive power or chemical feedstocks.     

Electricity consumption and CO2 capture potential in Spain

In this paper, different electricity demand scenarios for Spain are presented. Population, income per capita, energy intensity and the contribution of electricity to the total energy demand have been taken into account in the calculations. Technological role of different generation technologies, i.e. coal, nuclear, renewable, combined cycle (CC), combined heat and power (CHP) and carbon capture and storage (CCS), are examined in the form of scenarios up to 2050. Nine future scenarios corresponding to three electrical demands and three options for new capacity: minimum cost of electricity, minimum CO₂ emissions and a criterion with a compromise between CO₂ and cost (CO₂-cost criterion) have been proposed. Calculations show reduction in CO₂ emissions from 2020 to 2030, reaching a maximum CO₂ emission reduction of 90% in 2050 in an efficiency scenario with CCS and renewables. The contribution of CCS from 2030 is important with percentage values of electricity production around 22–28% in 2050. The cost of electricity (COE) increases up to 25% in 2030, and then this value remains approximately constant or decreases slightly.     

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.     

Decarbonizing Europe's power sector by 2050 — Analyzing the economic implications of alternative decarbonization pathways

The European Union aims to reduce greenhouse gas emissions by 80–95% in 2050 compared to 1990 levels. The transition towards a low-carbon economy implies the almost complete decarbonization of Europe's power sector, which could be achieved along various pathways. In this paper, we evaluate the economic implications of alternative energy policies for Europe's power sector by applying a linear dynamic electricity system optimization model in over 36 scenarios. We find that the costs of decarbonizing Europe's power sector by 2050 vary between 139 and 633 bn €₂₀₁₀, which corresponds to an increase of between 11% and 44% compared to the total system costs when no CO₂ reduction targets are implemented. In line with economic theory, the decarbonization of Europe's power sector is achieved at minimal costs under a stand-alone CO₂ reduction target, which ensures competition between all low-carbon technologies. If, however, renewable energies are exempted from competition via supplementary renewable energy (RES-E) targets or if investments in new nuclear and CCS power plants are politically restricted, the costs of decarbonization significantly rise. Moreover, we find that the excess costs of supplementary RES-E targets depend on the acceptance of alternative low carbon technologies. For example, given a complete nuclear phase-out in Europe by 2050 and politically implemented restrictions on the application of CCS to conventional power plants, supplementary RES-E targets are redundant. While in such a scenario the overall costs of decarbonization are comparatively high, the excess costs of supplementary RES-E targets are close to zero.     

Review of Japan's power generation scenarios in light of the Fukushima nuclear accident

Following on from the Fukushima Daiichi nuclear power plant accident, the Japanese government is now in the throes of reviewing its power policy. Under continuing policies of economic revival and greenhouse gas reduction, it is crucial to consider scenarios for the country to realize reliable, low‐carbon, and economic electricity systems in the future. On the other hand, the social acceptance of nuclear power will affect the final political decision significantly. Therefore, in the present study, proposed power generation scenarios in Japan in light of the Fukushima accident were reviewed comprehensively from economic, environmental, technological, resource, security, and social perspectives. The review concludes that in Japan, (i) renewable energy mainly solar and wind needs to be developed as fast as possible subject to various constraints, (ii) more gas power plants will be used to absorb the fluctuations of intermittent renewable energy and supply electricity gap, (iii) nuclear power will be reduced in the future, but a 0% nuclear power scenario by 2030 is unlikely to be a reasonable choice on most measures and (iv) the effective communication with the public is vital important. Copyright © 2014 John Wiley & Sons, Ltd.     

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.     

Representation of variable renewable energy sources in TIMER,an aggregated energy system simulation model

The power system is expected to play an important role in climate change mitigation. Variable renewable energy (VRE) sources, such as wind and solar power, are currently showing rapid growth rates in power systems worldwide, and could also be important in future mitigation strategies. It is therefore important that the electricity sector and the integration of VRE are correctly represented in energy models. This paper presents an improved methodology for representing the electricity sector in the long-term energy simulation model TIMER using a heuristic approach to find cost optimal paths given system requirements and scenario assumptions. Regional residual load duration curves have been included to simulate curtailments, storage use, backup requirements and system load factor decline as the VRE share increases. The results show that for the USA and Western Europe at lower VRE penetration levels, backup costs form the major VRE cost markup. When solar power supplies more than 30% of the electricity demand, the costs of storage and energy curtailments become increasingly important. Storage and curtailments have less influence on wind power cost markups in these regions, as wind power supply is better correlated with electricity demand. Mitigation scenarios show an increasing VRE share in the electricity mix implying also increasing contribution of VRE for peak and mid load capacity. In the current scenarios, this can be achieved by at the same time installing less capital intensive gas fired power plants. Sensitivity analysis showed that greenhouse gas emissions from the electricity sector in the updated model are particularly sensitive to the availability of carbon capture and storage (CCS) and nuclear power and the costs of VRE.     

Identification of optimal strategies for sustainable energy management in Taiwan

In this study, an optimization model was developed for identifying optimal strategies in adjusting the existing fossil fuel‐based energy structure in Taiwan. In this model, minimization of the total system cost was adopted as the objective function, which was subject to a series of constraints related to energy demand, greenhouse gas (GHG) emission restriction, and energy balance. Feasibility of several potential energy structures was also evaluated through tradeoff analysis between energy system costs and GHG emission targets. Three scenarios were established under several GHG emission restriction targets and potential nuclear power expansion options. Under the three scenarios, optimal energy allocation patterns were generated. In terms of the total energy system cost, the scenario that restricted GHG emissions and nuclear power growth would result in the highest one, with an average annual increase of 4.2% over the planning horizon. Also, the results indicated that the energy supply structure would be directly influenced by energy cost and GHG emission reduction targets. Scenario 2 would lead to the greatest dependence on clean energy, which would take up 41.8% in 2025. In comparison, with no restriction on nuclear energy, it would replace several energy sources and contribute to 34.0% of the total energy consumption. Significant reduction in GHG emission could be identified under scenario 2 due to the replacement of conventional fossil fuels with clean energies. Under scenario 3, GHG emission would be significantly reduced due to the adoption of nuclear power. After 2015, energy structure in Taiwan would be slightly adjusted due to synthetic impacts of energy demand growth and GHG emission restriction. The results also indicated that further studies would be necessarily needed for evaluating impacts and feasibilities of clean energy and nuclear power utilization in Taiwan. Copyright © 2011 John Wiley & Sons, Ltd.     

An analysis of long-term scenarios for the transition to renewable energy in the Korean electricity sector

This paper analyzes the energy, environmental and economic influences of three electricity scenarios in Korea by 2050 using the “Long-range Energy Alternatives Planning system” (LEAP) model. The reference year was 2008. Scenarios include the baseline (BL), new governmental policy (GP) and sustainable society (SS) scenarios. The growth rate of electricity demand in the GP scenario was higher than that of the BL scenario while the growth rate in the SS scenario was lower than that of the BL scenario.Greenhouse gas emissions from electricity generation in 2050 in the BL and GP scenarios were similar with current emissions. However, emissions in 2050 in the SS scenario were about 80% lower than emissions in 2008, because of the expansion of renewable electricity in spite of the phase-out of nuclear energy.While nuclear and coal-fired power plants accounted for most of the electricity generated in the BL and GP scenarios in 2050, the SS scenario projected that renewable energy would generate the most electricity in 2050. It was found that the discounted cumulative costs from 2009 to 2050 in the SS scenario would be 20 and 10% higher than that of the BL and GP scenarios, respectively.     

An Analytical Network Process (ANP) evaluation of alternative fuels for electricity generation in Turkey

In this paper, we present an Analytical Network Process (ANP) model to determine the best fuel mix for electricity generation in Turkey from a sustainable development perspective. The proposed model is implemented in two alternative scenarios. These scenarios are structured along the lines of classification between weak and strong sustainability, and therefore reflect two basic dimensions of sustainability of energy production—environmental protection and sustainable supply of energy resources. The results of the study indicate the gap between goals of sustainable development and energy policies of Turkey in terms of energy security and environmental degradation. Under all alternative scenarios of our model, the highest value alternative is hydropower—domestic, renewable source—while the Turkish electricity sector mainly relies on imported natural gas. The share of nuclear energy is in the range of 8.12–10.21% in our model results, although nuclear energy is not available yet. The calculated percentages of renewable fuels (biomass, geothermal, wind, solar) are 35.7% and 28.9% for Scenario 1 and Scenario 2, respectively, while the total percentage of these fuels is 0.18% of the installed capacity of Turkey. The results of our model suggest that the share of renewable fuels in installed capacity should be increased to achieve sustainable development.     

中国2050年低碳情景和低碳发展之路

利用IPAC模型对我国未来中长期的能源与温室气体排放情景进行分析。设计了3个排放情景,介绍了情景的主要参数和结果,以及实现减排所需的技术,同时探讨中国实现低碳情景所需要的发展路径。作为一个经济快速增长国家,中国未来的能源需求和相应的温室气体排放将快速明显增加。中国要实现低碳发展路径,必须从现在就采取适合于低碳发展的政策,着重发展具有国际领先地位的重大清洁能源开发、转换和利用技术,大力发展可再生能源和核电技术,提高公众意识,使低碳生活方式成为普遍行为,逐步实施能源税和碳税。     

Development of an Energy‐Economic Model with Endogenous Technological Progress and Feasibility Study of CCS Systems

The main objective of this research is to develop a bottom‐up energy‐economic model considering endogenous technological development. The designed model analyzes the feasibility of CCS technologies in the Japanese electricity market to derive an optimum carbon reduction scenario. Two factors, a learning curve based on learning‐by‐doing and public R&D investment, precede technological progress. The analysis is calculated with a set of scenarios, which is based on alternative assumptions for technological characteristics: chemical and physical carbon absorptive technology. From modeling estimation, we conclude that technological progress reduces the generation costs of conversion technologies with CCS, as a CCS system acquires an additional unit of installation. Generation cost with chemical absorption remarkably reduces its marginal unit cost through a learning mechanism. The supply fraction from a gas‐fired power plant increases over the analytical time period. The introduction of CCS reduces carbon emission level 17% compared to the baseline scenario in 2050. Technological progress has little impact on the total system costs; however, learning‐by‐doing pushes the introduction of CCS into the market rather than into a R&D activity. Research and development efforts in the private sector or knowledge spillover are not modeled in the study; however, they have the potential to contribute to the mitigation of carbon emission as well. © 2013 Wiley Periodicals, Inc. Heat Trans Asian Res, 43(4): 332–351, 2014; Published online 3 October 2013 in Wiley Online Library ( wileyonlinelibrary.com/journal/htj ). DOI 10.1002/htj.21078     

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.     

Biomass from agriculture in small-scale combined heat and power plants - A comparative life cycle assessment

Biomass produced on farm land is a renewable fuel that can prove suitable for small-scale combined heat and power (CHP) plants in rural areas. However, it can still be questioned if biomass-based energy generation is a good environmental choice with regards to the impact on greenhouse gas emissions, and if there are negative consequences of using of agricultural land for other purposes than food production.In this study, a simplified life cycle assessment (LCA) was conducted over four scenarios for supply of the entire demand of power and heat of a rural village. Three of the scenarios are based on utilization of biomass in 100 kW (e) combined heat and power (CHP) systems and the fourth is based on fossil fuel in a large-scale plant. The biomass systems analyzed were based on 1) biogas production with ley as substrate and the biogas combusted in a microturbine, 2) gasification of willow chips and the product gas combusted in an IC-engine and 3) combustion of willow chips for a Stirling engine. The two first scenarios also require a straw boiler.The results show that the biomass-based scenarios reduce greenhouse gas emissions considerably compared to the scenario based on fossil fuel, but have higher acidifying emissions. Scenario 1 has by far the best performance with respect to global warming potential and the advantage of utilizing a byproduct and thus not occupying extra land. Scenario 2 and 3 require less primary energy and less fossil energy input than 1, but set-aside land for willow production must be available. The low electric efficiency of scenario 3 makes it an unsuitable option.     

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.     

Cost effective integration of hydrogen in energy systems with CO2 constraints

The integration of hydrogen in national energy systems is illustrated in four extreme scenarios, reflecting four technological mainstreams (energy conservation, renewables, nuclear and CO₂ removal) to reduce C emissions. Hydrogen is cost-effective in all scenarios with higher CO₂ reduction targets. Hydrogen would be produced from fossil fuels, or from water and electricity or heat, depending upon the scenario. Hydrogen would be used in the residential and commercial sectors and for transport vehicles, industry, and electricity generation in fuel cells. At severe (50–70%) CO₂ reduction targets, hydrogen would cost-effectively supply more than half of the total useful energy demands in three out of four scenarios. The marginal emission reduction costs in the CO₂ removal scenario at severe CO₂ reduction targets are DFL 200/tCO₂ (ca $ 100/t). In the nuclear, renewable and energy conservation scenarios these costs are much higher. Whilst the fossil fuel scenario would be less expensive than the other scenarios, the possibility of CO₂ storage in depleted gas reservoirs is a conditio sine qua non.     

中国中长期碳减排战略目标初探(Ⅱ)——中国煤炭消费过程的碳排放及减排措施

中国能源领域排放的二氧化碳主要来自煤炭,因此煤炭消费过程中的碳减排措施尤为重要。煤炭的主要用户是发电部门,基于应对气候变化的需要,煤电行业的低碳途径不得不考虑采用CCS技术。不论是新建燃煤电厂,还是今后在传统电厂改建过程中增设CCS设施已是大势所趋,预计多数仍将采用MEA法脱除烟气中二氧化碳这一成熟技术。由于MEA法技术经济指标不够先进,估计10~20年内必将出现更先进的脱二氧化碳工艺技术。传统的燃煤锅炉增加CCS的经济效益已经逊于IGCC-CCS,预计2020年后IGCC电厂将成为新建煤电厂的首选方案。20年后采用临氢气化炉与燃料电池FC发电相结合、把高温的热能和甲烷的化学能直接转化为电力的IGFC高效燃煤电厂或将成功应用,IGFC综合能量转化效率比IGCC相对高出1/2~3/4,发展前景不可低估。钢铁、水泥和化工等高耗煤工业部门可通过节能和采用CCS技术降低碳排放,其余用煤的工业部门和分散用户则应考虑节能或用天然气等低碳燃料替代,间接起到减排效果。预计2050年燃煤发电和高耗煤工业总计将排放二氧化碳4.6Gt,如果二氧化碳捕集量是2.9Gt,则净排放量为1.7Gt。加上其他难以捕集二氧化碳的工业、部门及民用煤排放二氧化碳1.0Gt,合计二氧化碳净排放量为2.7Gt(情景A)。如果采用更先进的技术和严格的节能减排措施,可减少煤炭消耗0.31Gt标煤,减少二氧化碳排放0.5Gt,使煤源二氧化碳净排放量减少到2.2Gt(情景B)。无论哪种情景,实施CCS的任务都十分艰巨。     

Farm-scale bio-power-to-methane: Comparative analyses of economic and environmental feasibility

Power-to-gas technologies are considered to be part of the future energy system, but their viability and applicability need to be assessed. Therefore, models for the viability of farm-scale bio-power-to-methane supply chains to produce green gas were analysed in terms of levelised cost of energy, energy efficiency and saving of greenhouse gas emission. In bio-power-to-methane, hydrogen from electrolysis driven by surplus renewable electricity and carbon dioxide from biogas are converted to methane by microbes in an ex situ trickle-bed reactor. Such bio-methanation could replace the current upgrading of biogas to green gas with membrane technology. Four scenarios were compared: a reference scenario without bio-methanation (A), bio-methanation (B), bio-methanation combined with membrane upgrading (C) and the latter with use of renewable energy only (all-green; D). The reference scenario (A) has the lowest costs for green gas production, but the bio-methanation scenarios (B-D) have higher energy efficiencies and environmental benefits. The higher costs of the bio-methanation scenarios are largely due to electrolysis, whereas the environmental benefits are due to the use of renewable electricity. Only the all-green scenario (D) meets the 2026 EU goal of 80% reduction of greenhouse gas emissions, but it would require a CO₂ price of 200 € t⁻¹ to achieve the levelised cost of energy of 65 €ct Nm⁻³ of the reference scenario. Inclusion of the intermittency of renewable energy in the scenarios substantially increases the costs. Further greening of the bio-methanation supply chain and how intermittency is best taken into account need further investigation.     

Greenhouse gases (GHG) emissions reduction in a power system predominantly based on lignite

In this paper the GHG mitigation potential of a power system with prevailing use of lignite is assessed through the example of the Macedonian power system. The analysis is conducted using the WASP model in order to develop three different scenarios (business as usual - BAU and two mitigation scenarios) for the power system expansion over the period 2008-2025. In the first mitigation scenario two gas power plants with combined cycle are planned to replace some of the lignite-based capacities. The second mitigation scenario, besides the gas power plants, assumes electricity consumption reduction related to the large industrial consumers and an increased share of new renewable energy sources. Detailed calculations of the GHG emissions are made for all scenarios. The comparison of emissions in 2025 and in 2008 shows that the increase of 78% in the case of predominantly lignite BAU scenario is reduced to 41% by the first mitigation scenario, and to 14% by the second mitigation scenario. The mitigation costs appeared to be less then 10 $/t CO₂-eq for the first mitigation scenario, and even negative for the second one.