Stockholm CHP potential—An opportunity for CO2 reductions?

The potential for combined heat and power (CHP) generation in Stockholm is large and a total heat demand of about 10 TWh/year can be met in a renewed large district heating system. This model of the Stockholm district heating system shows that CHP generation can increase from 8% in 2004 to 15.5% of the total electricity generation in Sweden. Increased electricity costs in recent years have awakened an interest to invest in new electricity generation. Since renewable alternatives are favoured by green certificates, bio-fuelled CHP is most profitable at low electricity prices. Since heat demand in the district heating network sets the limit for possible electricity generation, a CHP alternative with a high electricity to heat ratio will be more profitable at when electricity prices are high. The efficient energy use in CHP has the potential to contribute to reductions in carbon dioxide emissions in Europe, when they are required and the European electricity market is working perfectly. The potential in Stockholm exceeds Sweden's undertakings under the Kyoto protocol and national reduction goals.     

The impact of the European Union emission trading scheme on the electricity-generation sector

In order to comply with their commitments under the Kyoto Protocol, France and Germany participate in the European Union Emission Trading Scheme (EU ETS) which predominantly concerns the electricity-generation sectors. In this paper we ask whether the EU ETS provides the appropriate economic incentives to produce an efficient system in line with the Kyoto commitments. If so, electricity producers in the countries concerned should include the price of carbon in their cost functions. After identifying different sub-periods of the EU ETS during its pilot phase (2005–2007), we model the prices of various electricity contracts in France and Germany and look at the volatility of electricity prices around their fundamentals while evaluating the correlation between electricity prices in the two countries. We find that electricity producers in both countries were constrained to include the carbon price in their cost functions during the first two years of the EU ETS. Over this period, German electricity producers were more constrained than their French counterparts, and the inclusion of the carbon price in the electricity-generation cost function was much more stable in Germany than in France. We also find evidence of fuel switching in electricity generation in Germany after the collapse of the carbon market. Furthermore, the European market for emission allowances has greatly contributed to the partial alignment of the wholesale price of electricity in France to that in Germany.     

Fuel cell electric vehicle as a power plant: Fully renewable integrated transport and energy system design and analysis for smart city areas

Reliable and affordable future zero emission power, heat and transport systems require efficient and versatile energy storage and distribution systems. This paper answers the question whether for city areas, solar and wind electricity together with fuel cell electric vehicles as energy generators and distributors and hydrogen as energy carrier, can provide a 100% renewable, reliable and cost effective energy system, for power, heat, and transport. A smart city area is designed and dimensioned based on European statistics. Technological and cost data is collected of all system components, using existing technologies and well-documented projections, for a Near Future and Mid Century scenario. An energy balance and cost analysis is performed. The smart city area can be balanced requiring 20% of the car fleet to be fuel cell vehicles in a Mid Century scenario. The system levelized cost in the Mid Century scenario is 0.09 €/kWh for electricity, 2.4 €/kg for hydrogen and specific energy cost for passenger cars is 0.02 €/km. These results compare favorably with other studies describing fully renewable power, heat and transport systems.     

European perspective on absorption cooling in a combined heat and power system – A case study of energy utility and industries in Sweden

Mankind is facing an escalating threat of global warming and there is increasing evidence that this is due to human activity and increased emissions of carbon dioxide. Converting from vapour compression chillers to absorption chillers in a combined heat and power (CHP) system is a measure towards sustainability as electricity consumption is replaced with electricity generation. This electricity produced in Swedish CHP-system will substitute marginally produced electricity and as result lower global emissions of carbon dioxide. The use of absorption chillers is limited in Sweden but the conditions are in fact most favourable. Rising demand of cooling and increasing electricity prices in combination with a surplus of heat during the summer in CHP system makes heat driven cooling extremely interesting in Sweden. In this paper we analyse the most cost-effective technology for cooling by comparing vapour compression chillers with heat driven absorption cooling for a local energy utility with a district cooling network and for industries in a Swedish municipality with CHP. Whilst this case is necessarily local in scope, the results have global relevance showing that when considering higher European electricity prices, and when natural gas is introduced, absorption cooling is the most cost-effective solution for both industries and for the energy supplier. This will result in a resource effective energy system with a possibility to reduce global emissions of CO₂ with 80%, a 300% lower system cost, and a 170% reduction of the cost of producing cooling due to revenues from electricity production. The results also show that, with these prerequisites, a decrease in COP of the absorption chillers will not have a negative impact on the cost-effectiveness of the system, due to increased electricity production.     

The role of policy instruments for promoting combined heat and power production with low CO2 emissions in district heating systems

Policy instruments clearly influence the choice of production technologies and fuels in large energy systems, including district heating networks. Current Swedish policy instruments aim at promoting the use of biofuel in district heating systems, and at promoting electric power generation from renewable energy sources. However, there is increasing pressure to harmonize energy policy instruments within the EU. In addition, natural gas based combined cycle technology has emerged as the technology of choice in the power generation sector in the EU. This study aims at exploring the role of policy instruments for promoting the use of low CO₂ emissions fuels in high performance combined heat and power systems in the district heating sector. The paper presents the results of a case study for a Swedish district heating network where new large size natural gas combined cycle (NGCC) combined heat and power (CHP) is being built. Given the aim of current Swedish energy policy, it is assumed that it could be of interest in the future to integrate a biofuel gasifier to the CHP plant and co‐fire the gasified biofuel in the gas turbine unit, thereby reducing usage of fossil fuel. The goals of the study are to evaluate which policy instruments promote construction of the planned NGCC CHP unit, the technical performance of an integrated biofuelled pressurized gasifier with or without dryer on plant site, and which combination of policy instruments promote integration of a biofuel gasifier to the planned CHP unit. The power plant simulation program GateCycle was used for plant performance evaluation. The results show that current Swedish energy policy instruments favour investing in the NGCC CHP unit. The corresponding cost of electricity (COE) from the NGCC CHP unit is estimated at 253 SEK MWh^?1, which is lower than the reference power price of 284 SEK MWh^?1. Investing in the NGCC CHP unit is also shown to be attractive if a CO₂ trading system is implemented. If the value of tradable emission permits (TEP) in such as system is 250 SEK tonne^?1, COE is 353 SEK MWh^?1 compared to the reference power price of 384 SEK MWh^?1. It is possible to integrate a pressurized biofuel gasifier to the NGCC CHP plant without any major re‐design of the combined cycle provided that the maximum degree of co‐firing is limited to 27–38% (energy basis) product gas, depending on the design of the gasifier system. There are many parameters that affect the economic performance of an integrated biofuel gasifier for product gas co‐firing of a NGCC CHP plant. The premium value of the co‐generated renewable electricity and the value of TEPs are very important parameters. Assuming a future CO₂ trading system with a TEP value of 250 SEK tonne^?1 and a premium value of renewable electricity of 200 SEK MWh^?1 COE from a CHP plant with an integrated biofuelled gasifier could be 336 SEK MWh^?1, which is lower than both the reference market electric power price and COE for the plant operating on natural gas alone. Copyright © 2005 John Wiley & Sons, Ltd.     

Multi-objective optimization of large-scale grid-connected photovoltaic-hydrogen-natural gas integrated energy power station based on carbon emission priority

Establishing integrated energy systems is conducive for improving renewable energy utilization and promoting decarbonization. In this study, a grid-connected photovoltaic-hydrogen-natural gas integrated energy system is established to explore the effects of the configuration of the integrated energy system on its environment and economy. A multi-objective hierarchical optimization allocation model is developed, and an optimization strategy with carbon emission superior to total cost is established for the first time. Additionally, the economy, environment, and energy efficiency of the system are analyzed. A comparative study is performed using a strategy considering that the total cost is superior to carbon emission. A case study reveals that the levelized cost of electricity increases by 62.24%, levelized carbon emission of power decreases by 74.19%, and energy efficiency increases by 8.51%, as compared with those of the comparison strategy. Thus, the carbon emission of the system is reduced considerably, and the energy efficiency is improved. Although the cost of the system optimized by the proposed strategy is higher, it is economically feasible. Further analyses indicate that extending the grid-connected period would be infeasible, as it might increase the total cost and carbon emission of the system. Moreover, sensitivity analyses show that increasing the natural gas price or carbon tax base price will not reduce the carbon emission of the system.     

The impact of the EU ETS on the sectoral innovation system for power generation technologies – Findings for Germany

This paper provides an overview of early changes in the sectoral innovation system for power generation technologies which have been triggered by the European Emission Trading System (EU ETS). Based on a broad definition of the sector, our research analyses the impact of the EU ETS on the four building blocks ‘knowledge and technologies’, ‘actors and networks’, ‘institutions’, and ‘demand’ by combining two streams of literature, namely systems of innovation and environmental economics. Our analysis for Germany is based on 42 exploratory interviews with experts in the field of the EU ETS, the power sector, and technological innovation. We find that the EU ETS mainly affects the rate and direction of technological change of power generation technologies within the large-scale, coal-based power generation technological regime, to which carbon capture technologies are added as a new technological trajectory. While this impact can be interpreted as the defensive behaviour of incumbents, the observed changes should not be underestimated. We argue that the EU ETS’ impact on corporate CO₂ culture and routines may prepare the ground for the transition to a low-carbon sectoral innovation system for power generation technologies.     

Ex-post investigation of cost pass-through in the EU ETS - an analysis for six industry sectors

In the discussion on the potential risk of carbon leakage related to the EU ETS and the effect of safeguard measures, the scope for passing through carbon costs into final product prices is considered a key issue. This study investigates whether and to what extent ETS-related carbon costs have been passed through into product prices by EU industry. Literature on the issue of carbon cost pass-through in industry, other than electric power generation, is relatively sparse and we therefore aim to add to the knowledge gathered in this area so far. We investigate a number of products in six industry sectors in several European countries and regions and provide estimates for carbon cost pass-through for more than 50 product/country pairs. In line with the literature, our econometric results imply significant cost pass-through for a number of products, with results being most conclusive for the cement, iron and steel, and refineries sectors. The extent of the estimated pass-through rates diverges between products and countries/regions. These findings are aimed at informing discussions about carbon leakage protection for industries covered by the EU ETS.     

Methodology to estimate the economic,emissions, and energy benefits from combined heat and power systems based on system component efficiencies

This paper presents a methodology to estimate the economic, emissions, and energy benefits that could be obtained from a base loaded CHP system using screening parameters and system component efficiencies. On the basis of the location of the system and the facility power to heat ratio, the power that must be supplied by a base loaded CHP system in order to potentially achieve cost, emissions, or primary energy savings can be estimated. A base loaded CHP system is analyzed in nine US cities in different climate zones, which differ in both the local electricity generation fuel mix and local electricity prices. Its potential to produce economic, emissions, and energy savings is quantified on the basis of the minimum fraction of the useful heat to the heat recovered by the CHP system (φ_min). The values for φ_min are determined for each location in terms of cost, emissions, and energy. Results indicate that in terms of cost, four of the nine evaluated cities (Houston, San Francisco, Boulder, and Duluth) do not need to use any of the heat recovered by the CHP system to potentially generate cost savings. On the other hand, in cities such as Seattle, around 86% of the recovered heat needs to be used to potentially provide cost savings. In terms of emissions, only Chicago, Boulder, and Duluth are able to reduce emissions without using any of the recovered heat. In terms of primary energy consumption, only Chicago and Duluth do not require the use of any of the recovered heat to yield primary energy savings. For the rest of the evaluated cities, some of the recovered heat must be used in order to reduce the primary energy consumption with respect to the reference case. In addition, the effect of the efficiency of the power generation unit and the facility power to heat ratio on the potential of the CHP system to reduce cost, emissions, and primary energy is investigated, and a graphical method is presented for examining the trade‐offs between power to heat ratio, base loading fraction, percentage of recovered heat used, and minimum ratios for cost, emissions, and primary energy. Copyright © 2014 John Wiley & Sons, Ltd.     

Short-term impact of green certificates and CO2 emissions trading in the Swedish district heating sector

Swedish district-heating (DH) systems use a wide range of energy sources and technologies for heat-and-power generation. This provides the DH utilities with major flexibility in changing their fuel and technology mix when the economic conditions for generation change. Two recently introduced policy instruments have changed the DH utilities’ costs for generation considerably; the tradable green-certificate (TGC) scheme introduced in 2003 in Sweden, and the tradable greenhouse-gas emission permit (TEP) scheme introduced in the EU on January 1, 2005. The objective of this study is to analyse how these two trading schemes impact on the operation of the Swedish DH sector in terms of changes in CHP generation, CO₂ emissions, and operating costs. The analysis was carried out by comparing the most cost-effective operation for the DH utilities, with and without, the two trading schemes applied, using a model that handles the Swedish DH-sector system-by-system. It was found that the volume of renewable power generated in CHP plants only increased slightly owing to the TGC scheme. The TGC and the TEP schemes in force together, however, nearly doubled the renewable power-generation. CO₂ emissions from the DH sector may either increase or decrease depending on the combination of TGC and TEP prices. The overall CO₂ emissions from the European power-generation sector would, however, be reduced for all price combinations assuming that increased Swedish CHP generation replaces coal-condensing power (coal-fired plants with power generation only) in other European countries. The trading schemes also lower the operational costs of the DH sector since the cost increase owing to the use of more expensive fuels and the purchase of TEPs is outweighed by the increased revenues from sales of electricity and TGCs.     

Fuel cells for carbon capture and power generation: Simulation studies

The decarbonization of hydrocarbons is explored in this work as a method to produce hydrogen and mitigate carbon dioxide (CO₂) emissions. An integrated process for power generation and carbon capture based on a hydrocarbon fueled-decarbonization unit was proposed and simulated. Ethane and propane were used as fuels and subjected to the thermal decomposition (decarbonization) process. The system is also composed of a carbon fuel cell (CFC) and hydrogen fuel cell (HFC) for the production of power and a pure CO₂ stream that is ready for sequestration. The HFC is a high-temperature proton exchange membrane fuel cell operating at 200 °C. Simulations were performed using ASPEN HYSYS V.10 for the entire process including the CFC and HFC being operated at various operating temperatures (200–800 °C). The power output from the CFC and the HFC as well as the overall process efficiency were calculated. The model incorporates an energy recovery system by adopting a counter-current shell and tube heat exchangers and a turbine. The water produced from the fuel cell system can be utilized in the plant to recover the heat from the furnace. The results showed a 100% carbon capture with a nominal plant capacity of 108 MWe produced when propane fuel was fed to the decarbonizer. The CFC theoretical efficiency is 100% and the practical efficiency was taken as 70% when all internal polarizations were considered. The results showed that, in the case of propane, the CFC power output was 89 MWe when the CFC operated at 650 °C, and the HFC power output was around 45 MWe at 200 °C with an overall actual plant efficiency of 35% and 100% carbon capture. Sensitivity analysis recommends a hydrocarbon fuel cost of 0.011 $/kW as the most feasible option. The results reported here on the decarbonization of hydrocarbon fuels are promising toward the direct production of hydrogen with full carbon dioxide sequestration at a potentially lower cost especially in rural areas. The overall actual efficiencies are very competitive to those of conventional power plants operated without carbon capture.     

Implications of the EU Emissions Trading System for the South-East Europe Regional Electricity Market

As part of its climate policy, the European Union (EU) aims to reduce greenhouse gas (GHG) emissions levels by 20% by the year 2020 compared to 1990 levels. Although the EU is projected to reach this goal, its achievement of objectives under its Emissions Trading System (ETS) may be delayed by carbon leakage, which is defined as a situation in which the reduction in emissions in the ETS region is partially offset by an increase in carbon emissions in the non-ETS regions. We study the interaction between emissions and hydropower availability in order to estimate the magnitude of carbon leakage in the South-East Europe Regional Electricity Market (SEE-REM) via a bottom-up partial equilibrium framework. We find that 6.3% to 40.5% of the emissions reduction achieved in the ETS part of SEE-REM could be leaked to the non-ETS part depending on the price of allowances. Somewhat surprisingly, greater hydropower availability may increase emissions in the ETS part of SEE-REM. However, carbon leakage might be limited by demand response to higher electricity prices in the non-ETS area of SEE-REM. Such carbon leakage can affect both the competitiveness of producers in ETS member countries on the periphery of the ETS and the achievement of EU targets for CO₂ emissions reduction. Meanwhile, higher non-ETS electricity prices imply that the current policy can have undesirable outcomes for consumers in non-ETS countries, while non-ETS producers would experience an increase in their profits due to higher power prices as well as exports. The presence of carbon leakage in SEE-REM suggests that current EU policy might become more effective when it is expanded to cover more countries in the future.     

Multi-stage stochastic optimization framework for power generation system planning integrating hybrid uncertainty modelling

In this paper, a multi-stage stochastic optimization (MSO) method is proposed for determining the medium to long term power generation mix under uncertain energy demand, fuel prices (coal, natural gas and oil) and, capital cost of renewable energy technologies. The uncertainty of future demand and capital cost reduction is modelled by means of a scenario tree configuration, whereas the uncertainty of fuel prices is approached through Monte Carlo simulation. Global environmental concerns have rendered essential not only the satisfaction of the energy demand at the least cost but also the mitigation of the environmental impact of the power generation system. As such, renewable energy penetration, CO_2,eq mitigation targets, and fuel diversity are imposed through a set of constraints to align the power generation mix in accordance to the sustainability targets. The model is, then, applied to the Indonesian power generation system context and results are derived for three cases: Least Cost option, Policy Compliance option and Green Energy Policy option. The resulting optimum power generation mixes, discounted total cost, carbon emissions and renewable share are discussed for the planning horizon between 2016 and 2030.     

Green hydrogen for heating and its impact on the power system

With a relatively high energy density, hydrogen is attracting increasing attention in research, commercial and political spheres, specifically as a fuel for residential heating, which is proving to be a difficult sector to decarbonise in some circumstances. Hydrogen production is dependent on the power system so any scale use of hydrogen for residential heating will impact various aspects of the power system, including electricity prices and renewable generation curtailment (i.e. wind, solar). Using a linearised optimal power flow model and the power infrastructure on the island of Ireland this paper examines least cost optimal investment in electrolysers in the presence of Ireland's 70% renewable electricity target by 2030. The introduction of electrolysers in the power system leads to an increase in emissions from power generation, which is inconsistent with some definitions of green hydrogen. Electricity prices are marginally higher with electrolysers whereas the optimal location of electrolysers is driven by a combination of residential heating demand and potential surplus power supplies at electricity nodes.     

Technology mix alternatives with high shares of wind power and photovoltaics—case study for Spain

The shift to a low carbon society is an issue of highest priority in the EU. For electricity generation, such a target counts with three main alternatives: renewable energies, nuclear power and carbon capture and storage. This paper focuses on the renewables’ alternative. Due to resource availability, a technology mix with a high share of PV and wind power is gaining increasing interest as a major solution for several EU member states and in part for the EU collectively to achieve decarbonization and energy security with acceptable costs. Due to their intermittency, the integration of high shares of PV and wind power in the electricity supply is challenging. This paper presents a techno-economic assessment of technology mix alternatives with a high share of PV and wind power in Spain, as an example. Thereby, the focus is on the option of increasing wind curtailment versus substituting rigid baseload generation in favor of the more flexible gas turbines and combined cycle gas turbines.     

Development modes analysis of renewable energy power generation in North Africa

North African countries generally have strategic demands for energy transformation and sustainable development. Renewable energy development is important to achieve this goal. Considering three typical types of renewable energies— wind, photovoltaic (PV), and concentrating solar power (CSP)—an optimal planning model is established to minimize construction costs and power curtailment losses. The levelized cost of electricity is used as an index for assessing economic feasibility. In this study, wind and PV, wind / PV / CSP, and transnational interconnection modes are designed for Morocco, Egypt, and Tunisia. The installed capacities of renewable energy power generation are planned through the time sequence production simulation method for each country. The results show that renewable energy combined with power generation, including the CSP mode, can improve reliability of the power supply and reduce the power curtailment rate. The transnational interconnection mode can help realize mutual benefits of renewable energy power, while the apportionment of electricity prices and trading mechanisms are very important and are related to economic feasibility; thus, this mode is important for the future development of renewable energy in North Africa.     

Techno-economic analysis of using corn stover to supply heat and power to a corn ethanol plant – Part 2: Cost of heat and power generation systems

This paper presents a techno-economic analysis of corn stover fired process heating (PH) and the combined heat and power (CHP) generation systems for a typical corn ethanol plant (ethanol production capacity of 170 dam³). Discounted cash flow method was used to estimate both the capital and operating costs of each system and compared with the existing natural gas fired heating system. Environmental impact assessment of using corn stover, coal and natural gas in the heat and/or power generation systems was also evaluated. Coal fired process heating (PH) system had the lowest annual operating cost due to the low fuel cost, but had the highest environmental and human toxicity impacts. The proposed combined heat and power (CHP) generation system required about 137 Gg of corn stover to generate 9.5 MW of electricity and 52.3 MW of process heat with an overall CHP efficiency of 83.3%. Stover fired CHP system would generate an annual savings of 3.6 M$ with an payback period of 6 y. Economics of the coal fired CHP system was very attractive compared to the stover fired CHP system due to lower fuel cost. But the greenhouse gas emissions per Mg of fuel for the coal fired CHP system was 32 times higher than that of stover fired CHP system. Corn stover fired heat and power generation system for a corn ethanol plant can improve the net energy balance and add environmental benefits to the corn to ethanol biorefinery.     

Opportunities and challenges for thermally driven hydrogen production using reverse electrodialysis system

Ongoing and emerging renewable energy technologies mainly produce electric energy and intermittent power. As the energy economy relies on banking energy, there is a rising need for chemically stored energy. We propose heat driven reverse electrodialysis (RED) technology with ammonium bicarbonate (AmB) as salt for producing hydrogen. The study provides the authors’ perspective on the commercial feasibility of AmB RED for low grade waste heat (333 K–413 K) to electricity conversion system. This is to our best of knowledge the only existing study to evaluate levelized cost of energy of a RED system for hydrogen production. The economic assessment includes a parametric study, and a scenario analysis of AmB RED system for hydrogen production. The impact of various parameters including membrane cost, membrane lifetime, cost of heating, inter-membrane distance and residence time are studied. The results from the economic study suggests, RED system with membrane cost less than 2.86 €/m², membrane life more than 7 years and a production rate of 1.19 mol/m²/h or more are necessary for RED to be economically competitive with the current renewable technologies for hydrogen production. Further, salt solubility, residence time and inter-membrane distance were found to have impact on levelized cost of hydrogen, LCH. In the present state, use of ammonium bicarbonate in RED system for hydrogen production is uneconomical. This may be attributed to high membrane cost, low (0.72 mol/m²/h) hydrogen production rate and large (1,281,436 m²) membrane area requirements. There are three scenarios presented the present scenario, market scenario and future scenario. From the scenario analysis, it is clear that membrane cost and membrane life in present scenario controls the levelized cost of hydrogen. In market scenario and future scenario the hydrogen production rate (which depends on membrane properties, inter-membrane distance etc.), the cost of regeneration system and the cost of heating controls the levelized cost of hydrogen. For a thermally driven RED system to be economically feasible, the membrane cost not more than 20 €/m²; hydrogen production rate of 3.7 mol/m²/h or higher and cost of heating not more than 0.03 €/kWh for low grade waste heat to hydrogen production.     

A hybrid model for the optimum integration of renewable technologies in power generation systems

The main purpose of this work is to assess the unavoidable increase in the cost of electricity of a generation system by the integration of the necessary renewable energy sources for power generation (RES-E) technologies in order for the European Union Member States to achieve their national RES energy target. The optimization model developed uses a genetic algorithm (GA) technique for the calculation of both the additional cost of electricity due to the penetration of RES-E technologies as well as the required RES-E levy in the electricity bills in order to fund this RES-E penetration. Also, the procedure enables the estimation of the optimum feed-in-tariff to be offered to future RES-E systems. Also, the overall cost increase in the electricity sector for the promotion of RES-E technologies, for the period 2010–2020, is analyzed taking into account factors, such as, the fuel avoidance cost, the carbon dioxide emissions avoidance cost, the conventional power system increased operation cost, etc. The overall results indicate that in the case of RES-E investments with internal rate of return (IRR) of 10% the cost of integration is higher, compared to RES-E investments with no profit, (i.e., IRR at 0%) by 0.3–0.5 €c/kWh (in real prices), depending on the RES-E penetration level.     

Emissions trading and investment decisions in the power sector—a case study in Finland

Organizations, which consider investment in or divestment of power production licences/capacity within the European Community, are exposed to the impacts of the European Union Emission allowance Trading Scheme (EU ETS). In this paper, the consequences of the EU ETS on investment decisions are explored in a country-specific setting in Finland. First, we review the general mechanisms through which the EU ETS influences size, timing and cashflows of an investment. Next, we discuss the projected changes in Finnish power producers’ investment environment and examine the financial impacts due to the EU ETS on a case investment decision, a hypothetical condensing power plant (250 MW_e). The standard discounted cash flow (DCF) analysis is extended to take into account the value of two real options: the option to wait and the option to alter operating scale. In a quantitative investment appraisal, the impact of emissions trading not only depends on the expected level of allowance prices, but also on their volatility and correlation with electricity and fuel prices. The case study shows that the uncertainty regarding the allocation of emission allowances is critical in a quantitative investment appraisal of fossil fuel-fired power plants.