Economics of clean development mechanism power projects under alternative approaches for setting baseline emissions

Economics of clean development mechanism power projects under alternative approaches for setting baseline emissions Ram M Shrestha , and Rabin Shrestha Energy Program, School of Environment, Resources and Development, Asian Institute of Technology, P.O Box 4, Klong Luang, Pathumthani 12120, Thailand Available online 27 May 2003 Abstract Setting the baseline emission and estimating emission reductions associated with a climate friendly project are among the key issues involved in identification of a clean development mechanism (CDM) project under the Kyoto Protocol This paper presents a methodology for identification of a CDM project and assessment of its environmental and economic implications under alternative approaches for establishing baseline emission, that is, traditional supply based planning and integrated resource planning (IRP) The paper also examines the role of "rebound effect" in the assessment of emission reductions from the CDM project under the IRP approach A case study of India based on the methodology is presented in the paper The study shows that the level of emission mitigation from the power system with a particular CDM project and the associated emission abatement cost could vary significantly with the type of approach used for determining the baseline emission It also shows that the optimal timing for implementation of the CDM project could vary with the type of the baseline approach used Furthermore, our analysis shows that under each of the baseline approaches, the net benefit from a candidate CDM project need not increase with its size (i.e., generating capacity) Author Keywords: Author Keywords: Baseline emission; Clean development mechanism; Incremental abatement cost Article Outline Introduction Overview of the Southern Regional Electricity Board power system in India Alternative baseline emission cases 3.1 Traditional electricity planning case 3.2 Integrated resource planning case without RE 3.3 Integrated resource planning case with RE Methodology Results and discussions 5.1 Least cost generation technologies under different cases 5.1.1 TEP baseline case 5.1.2 IRP baseline case without RE 5.1.3 IRP baseline case with RE 5.2 Candidate CDM projects based on the cost criterion 5.3 CO2 emission reduction with CDM projects under different cases 5.4 Incremental CO2 abatement cost under different baseline cases 5.5 Economic viability of CDM projects 5.6 Effects on local/regional environmental emissions 5.7 Effects of variation in the year of the CDM power plant addition 5.8 Effect of variation in CDM project capacity Conclusion Acknowledgements References Introduction The clean development mechanism (CDM) of the Kyoto Protocol allows developed countries (i.e., countries listed in Annex B of the Protocol) to sponsor greenhouse gas (GHG) emission reduction projects in developing countries (i.e., non-Annex B countries) One of the key conditions for a CDM project is that the project must result in GHG emission reductions that are additional to any that would occur in the absence of the project In other words, total GHG emissions with the implementation of the CDM project must be less than the baseline emissions (i.e., emissions without the project) Thus, the determination of baseline emission becomes an important step in evaluating a candidate CDM project However, the task of setting the baseline emission and determining emission reduction from the power system with a CDM project involves a number of technical and methodological issues (see e.g., Matsuo, 1999; Chomitz, 1999) Traditionally, utilities in most developing countries consider only the supply side options in meeting the projected electricity demand and ignore demand-side options (hereafter, we refer to this approach as "traditional electricity planning (TEP)") In recent years, the need to follow an integrated resource planning (IRP) approach, which considers both supply and demand-side options in the power sector development, has been widely recognized (e.g., see Hirst, 1991) The IRP approach is preferred to the TEP approach from the social perspective as it promotes an efficient use of both supply and demandside resources However, the level of baseline emissions under the IRP would be different from that under the TEP The levels of GHG emissions avoided from the power system and increase in total system cost due to a candidate CDM project under the IRP need not be the same as that under the TEP As a result, the marginal cost of emission abatement, which serves as an indicator of the cost effectiveness of a CDM project to potential investors from Annex B countries could be different under the alternative planning approach Furthermore, an important issue related to the determination of baseline emissions under the IRP is the "rebound effect (RE)" of energy efficient demand-side management programs (also known as the "feedback effect") which implies that actual electricity savings after the introduction of an energy efficient demand-side technologies would be less than the savings based on engineering estimates This reduction in savings is due to reduction in effective "price" (i.e., cost) of energy using service with the adoption of the DSM program (Khazzoom (1980) and Khazzoom (1987)) For similar reasons as stated earlier, the baseline emission under the IRP considering the RE and the corresponding level of emission reduction by a candidate CDM project would be different from that under the IRP without considering the RE An important issue related to a CDM power project is the determination of economically the most attractive size of the project Another issue is the optimal time for implementation of the project, that is, the year of addition of the CDM power plant capacity to the power system Thus, it is of interest to examine whether the alternative approaches for the baseline emissions would affect the size and optimal timing of a CDM project In this paper, we examine the effect of alternative baseline approaches on economics of a CDM project We also discuss the issue of optimal timing and size of a CDM project under the alternative approaches The organization of the paper is as follows: Section presents a brief overview of the power system under the Southern Regional Electricity Board in India Section describes the three alternative baseline emission cases considered in this study This is followed by a description of the methodology used Section discusses the least cost generation technologies selected under each approach considered and the candidate CDM projects It also discusses the emission reduction and cost implications of selected candidate CDM projects along with sensitivity analyses with respect to changes in size and time of implementing the CDM project Finally, the major conclusions of the paper are summarized Overview of the Southern Regional Electricity Board power system in India The power sector in India is organized into five Regional Electricity Boards (REBs) viz., Northern Regional Electricity Board (NREB), Southern Regional Electricity Board (SREB), Western Regional Electricity Board (WREB), Eastern Regional Electricity Board (EREB) and North-Eastern Regional Electricity Board (NEREB) Under these five REBs there are 26 State Electricity Boards Table shows the installed power generation capacity of different REBs and the total figures for India as a whole Table Installed power generation capacity of REBs and India in 1997, MW Source: CEA (1997) The SREB covers four southern states of India, namely Andhra Pradesh, Kerala, Karnataka and Tamil Nadu and it accounted for about 24% of the total installed generation capacity of India in 1997 At the end of 1997, the total installed capacity in SREB was 20,477 MW, with the share of thermal, hydropower and nuclear plant being 54.9%, 42.8% and 2.3%, respectively Hydroelectric potential of this region is estimated to be about 61.8 TWh/yr Energy requirements and peak load (i.e., power demand) forecast for SREB up to the end of year 2012 are shown in Table Table Peak load and energy requirement forecast for selected years Source: CEA (1997) Alternative baseline emission cases We consider the following three baseline emission cases: 3.1 Traditional electricity planning case In this case, only supply side options are considered in meeting the projected electricity demand during the planning horizon of 2005–2018 This is typically the case of traditional supply side electricity planning defined hereafter as "TEP case" Thirteen candidate hydropower plants and seven types of candidate thermal power plants are considered The candidate thermal plants include two types of coal-fired plants, gas based combined cycle plants (i.e., CCGT), nuclear plant, two types of efficient and clean coal plants (integrated gasification combined cycle (IGCC) and pressurized fluidized bed combustion (PFBC)), and biomass integrated gasification combined cycle (BIGCC) plants that use biomass at a sustainable rate (thus, net emission from electricity generation from BIGCC would be zero) Furthermore, solar PV and wind power plants each of MW capacity are also considered The technical, economic and environmental characteristics of the candidate power plants are shown in Table Table Characteristics of candidate power plants Source: Srivastava (2001) The data on projected values of peak load and electricity generation requirements used in this study are based on CEA (1998) while the system load profile as well as the data on existing and candidate power plants are based on Srivastava (2001) 3.2 Integrated resource planning case without RE In this case, the same set of supply side options and load growth projections as in the TEP case is considered In addition, four efficient DSM options are considered for which the maximum level of penetration and incremental costs are shown in Table However, the RE of DSM options on electricity demand (and thus on generation) is not taken into account in this case Hereafter, we call this case as the "IRP case" Table DSM Options considered Note: CFL=compact fluorescent lamp, EEM=energy efficient motors, IL=incandescent lamp 3.3 Integrated resource planning case with RE This case is the same as the IRP case except that we now consider the RE of efficient DSM options selected on electricity demand Hereafter, this case is referred to as "IRP+RE Case" Table shows the values of RE of selected efficient end-use devices based on the literature Note here that RE in Table is expressed as the reduction in savings due to the fall in effective price of energy services due to a adoption of energy efficient end use technologies as a percentage of total savings based on purely engineering estimates In the absence of information on RE specific to the SREB, India, we assume the RE to be 25% Table Values of rebound effect from selected studies Methodology This study basically involves determination of GHG emission levels from the power system during 2005–2018 both with and without the candidate CDM project in total power generation capacity under each of the cases considered (i.e., TEP, IRP, and IRP+RE) The flow chart of methodology is illustrated in Fig The least cost power development plan and the corresponding level of GHG emission are determined by using a long-term power sector generation planning model called IRP The IRP model is capable of considering both the supply and demand-side options to derive the least cost generation-, fuel- and DSM-mixes to meet the projected power demand during the planning horizon (2005–2018) The model can also be used to determine the least cost generation- and fuel-mix without DSM options in which case it serves the purpose of a traditional electricity generation planning model The objective of the IRP model is to minimize the total cost (comprising generation capacity, fuel, operation and maintenance cost of plants as well as the DSM costs) of power sector development over the planning horizon subject to relevant constraints of the power system The model includes the following constraints: (10K) Fig Flowchart of methodology Demand constraint: This constraint requires that the sum of power generation by all power plants (existing and candidate) and generation avoided by DSM options should not be less than total projected power demand in each period of the year during the planning horizon Reliability constraint: This constraint ensures that the total power generation capacity of all the plants (existing and candidate) must not be less than the sum of the peak power demand and the reserve margin in each year of the planning horizon Annual energy constraint: This constraint sets the maximum limit on energy generation of each thermal plant according to installed capacity, availability and duration of schedule maintenance of the plant Hydroenergy constraint: Total energy output of each hydro plant in each season should not exceed the plant's maximum available quantity of hydroenergy Fuel or resource availability constraint: Energy generation from a plant cannot exceed the level corresponding to the maximum available quantity of fuel resource The IRP model is formulated as a mixed-integer linear programming problem [see Shrestha et al (2001) for details of the IRP model formulation] In the present study, the mathematical programming software CPLEX version 7.10 developed by ILOG (2001) was used to solve the problem The levels of electricity demand and generation profile with RE included in the IRP case would be different from that without RE For an illustration, Fig shows the electricity generation profile (L2) under the IRP+RE case along with the profiles under the TEP and IRP cases (i.e., L0 and L1, respectively) (5K) Fig Power generation profile under three baseline emission cases In order to derive the level of emission reduction from the power system with a candidate CDM project under different cases during the planning horizon, we first define the following notations: Thus, total CO2 emission mitigation from the power sector with a candidate CDM project j under the TEP case (ΔETj) can be expressed as ΔETj=ET0−ETj (1) Total CO2 emission mitigation from the power sector with a CDM project j under the IRP case, i.e., without considering the RE (ΔEI,NRj) is given by ΔEI,NRj=EI,NR0−EI,NRj (2) Similarly, the total CO2 emission mitigation from the power sector with a candidate CDM project j under the IRP+RE case (ΔEI,REj) is ΔEI,REj=EI,RE0−EI,REj (3) The power sector planning model (i.e., IRP model) computes total cost, including capacity cost, operation and maintenance (O&M) cost and fuel cost as well as emission levels of different pollutants including GHG (only CO considered in the present study) The incremental carbon abatement cost (IAC) of a candidate CDM option is calculated under different cases., Fig presents the basic framework for identification of a CDM project in this study In order to determine whether an electricity generation plant would qualify for implementation as a CDM project, three criteria are proposed: (a) cost criterion, (b) emission criterion, and (c) net present value (NPV) criterion (16K) Fig Flow chart for identification of CDM Projects The cost criterion states that the total cost with a CDM option (TC 1) should be greater than the total cost (TC0) without the CDM option The emission criterion requires that the total GHG emission reduction from the power sector during the planning horizon should be positive with addition of the candidate CDM option in the generation capacity of the power system, whereas the NPV criterion states that the NPV of a CDM project at a given price of carbon mitigation (or market price of emission permits) should be positive , Results and discussions 5.1 Least cost generation technologies under different cases 5.1.1 TEP baseline case The least cost generation planning exercise here shows that all the candidate hydropower plants with total installed capacity of 6123 MW would be selected during 2005–2018 Among the thermal power plants, only gas based combined cycle plants, conventional coal fired plants and lignite plants are selected during the period A total of 41,484 MW generating capacity would be added during the period in this case PFBC, IGCC, BIGCC, solar and nuclear plants are not selected mainly due to high capital cost An addition of wind power plants with a total capacity of 500 MW is also found cost-effective 5.1.2 IRP baseline case without RE The type of candidate plants selected in this case is similar to that under the TEP case As in TEP, all candidate hydropower plants are selected during the planning horizon in this case Total installed capacity in this case during the planning horizon would be 9300 MW less than that in the TEP case because of the use of cost-effective efficient demand-side options As a result, total generation capacity added to the power system during the planning horizon in this case is 32,184 MW All four candidate DSM programs considered were selected to their maximum potential As in the TEP case, none of the candidate solar, PFBC, IGCC, BIGCC and nuclear plants would be among the least cost generation capacity added during the period while wind power plants with a total capacity of 500 MW of capacity would be cost-effective 5.1.3 IRP baseline case with RE The types of candidate plants found cost-effective in this case are similar to that under the previous two cases Total hydro capacity added in this case is the same as that under the IRP case without the RE With the inclusion of the RE, total electricity demand and thus generation would be higher than that under IRP without the RE As a result, total generation capacity added during the planning horizon in this case exceeds that under the IRP case without RE by 2800 MW Total capacity added during the planning horizon under this case is 34,984 MW which is 8.5% more than that under IRP without the RE Like in the IRP case without the RE, solar, PFBC, IGCC, BIGCC and nuclear plants are not selected as a part of the least cost capacity expansion plan in this case Wind power plant with a total capacity of 450 MW would be added in this case 5.2 Candidate CDM projects based on the cost criterion As stated in Section 5.1, none of the solar PV, BIGCC, PFBC, IGCC and nuclear power plants are included in the least cost power development plans under the three cases considered as they were not found cost effective Therefore, these plants could be considered as a candidate CDM project based purely on the cost criterion However, nuclear power plant is not considered as a candidate CDM project in this study No candidate hydro- and wind-power plant would qualify as a candidate CDM project under the cost criterion as these projects are found to be among the least cost options in each of the three approaches (i.e., cases) considered Similarly, none of the candidate DSM options considered would qualify as a CDM project in this study as the full utilization of all of them is found cost effective under each of the three approaches 5.3 CO2 emission reduction with CDM projects under different cases Table shows total CO2 emission reduction from the power system with candidate CDM projects during the planning horizon under the alternative cases considered It also shows CO2 emission reduction from the power system per unit of electricity generation by a candidate CDM project (hereafter "specific CO2 emission reduction") during the planning horizon Note that all candidate CDM projects considered in the study, except the PFBC and solar PV plants, satisfy the emission criterion in all three cases An addition of PFBC plant in 2006 would result in a reduction of total CO emission from the power system during the planning horizon under the TEP However, there would be an increase in total CO2 emission with the addition of the plant under the IRP and IRP+RE cases Similarly, an addition of the solar PV plant to the power generation capacity would increase the total power system CO2 emission under the IRP while it would contribute towards reduction of total CO2 emission under the TEP and IRP+RE cases This is because the least cost technology- and fuel-mix of power generation would change with the addition of the CDM project to the system generation capacity It is thus interesting to note that a particular cleaner power generation project may qualify as a CDM project under one approach of setting baseline while the same project may not qualify under another approach Table CO2 emission reduction by candidate CDM projects during 2005–2018 NA=not applicable as the candidate project results in an overall increase in CO emission during the planning horizon Note that total CO2 emission reductions from the power system with different candidate CDM projects in Table are not directly comparable as the projects are of different capacities (sizes) Furthermore, candidate CDM projects have different technical and cost characteristics e.g., heat rate, and fuel-, O&M- and capital-costs The specific CO emission reduction figures offer a better measure of the relative effectiveness of candidate CDM options As can be seen from Table 6, in all cases considered, specific CO emission reduction is found to be the highest in the case of the solar PV plant followed by the BIGCC power plant It is interesting to note that although solar PV and BIGCC (with sustainable biomass use) plants both have zero net CO emission, the values of specific CO2 emission reduction from the power system as a whole are not the same with these options This is because the addition of these projects in the generation system would affect the generation- and fuel-mix of the power system differently due to differences in their technical and cost characteristics Note that the results presented in Table are based on the candidate CDM projects that are not only of different types but are also of different sizes In order to see how the results would vary if the capacity of the candidate CDM projects were of the same size, we fix the capacity of each type of candidate CDM project at 400 MW It should be noted here that, though the candidate power plant size is same for all the candidates, the total electricity generation might vary depending upon the operating cost, availability of the unit and maintenance requirements Table shows the total CO2 mitigation from the power system with each of the candidate CDM projects and specific CO2 emission reduction under all three cases Unlike in Table 6, where the selected CDM projects were of different sizes, all candidate projects satisfy the emission criterion in all three cases when all CDM projects are of 400 MW capacity This suggests that the size of the candidate CDM plant does matter in meeting the criteria of the CDM project Solar PV would result in the highest CO emission reduction from the power system under IRP+RE Among the clean coal technologies, total CO emission reduction from the power system with the IGCC plant is higher than that with the PFBC plant The values of specific CO2 emission reduction by candidate plants show that, when the candidate CDM capacity is fixed at 400 MW, the BIGCC plant would result in the highest CO2 emission reduction per unit of electricity generation in the TEP and IRP+RE cases, while the solar PV plant would yield the highest CO emission reduction under the IRP case Table Total CO2 emission reduction by 400 MW candidate CDM projects during 2005–2018 5.4 Incremental CO2 abatement cost under different baseline cases Table shows the incremental abatement cost (IAC) of candidate CDM projects under the three different baseline cases considered in the study As can be seen, IAC of a candidate project could exhibit significant variation across the baseline approaches considered For example, IAC of the BIGCC plant would vary from 132 $/ton C under the IRP to 223 $/ton C under the TEP approach Also note that the IGCC plant would have its lowest IAC under the IRP+RE approach while the BIGCC plant would have its lowest IAC under the IRP approach Furthermore, it is interesting to note here that IAC of the solar PV plant is negative in the TEP case The negative value is due to net increase in discounted value of total emission with the inclusion of solar PV plant This means the solar PV plant of MW capacity would not qualify as a CDM project under the TEP case On the contrary it is found to be the most attractive among the candidate CDM projects considered in the IRP+RE case These findings highlight the importance of selecting appropriate baselines for identifying the CDM projects Among the candidate CDM projects considered, BIGCC plant was found to be most expensive for CO emission reduction under all three approaches while the solar PV was the least costly candidate under the IRP+RE approach Table Incremental abatement cost at 1998 prices of the selected CDM candidates, $/ton C NA=Not applicable, as the candidate project does not satisfy the emission criterion How would the IAC vary, if all candidate CDM projects were of the same size? Table shows the IAC for the candidate CDM project of 400 MW each Solar PV plant of 400 MW capacity would have a positive IAC in all three baseline approaches unlike with the plant size of MW However, the smaller solar PV plant of MW is found to be far more cost effective under the IRP+RE case than when the plant capacity is increased to 400 MW Thus, while the solar PV plant of MW capacity could be cost effective under the IRP+RE based approach even at a relatively low price of certified emission reduction from a CDM project, a big solar capacity (here with 400 MW size) would not These results show the role of a candidate CDM project's size in its cost-effectiveness Table Incremental abatement cost at 1998 prices of 400 MW candidate CDM projects, $/ton C 5.5 Economic viability of CDM projects For a candidate CDM project to become cost-effective, IAC of the project should be less than the price of CO2 mitigation (hereafter price of carbon) in the international market besides satisfying the additionality criterion on CO mitigation There are wide variations in the estimated price of carbon among studies The estimated value of the price of carbon (expressed in terms of carbon abatement cost in 1998 prices) under the full global trading regime ranges from 22 to 88 $/ton C , (Painuly, 2001; Ellerman and Decaux, 1998) The price of carbon under the full global trading regime represents the lower bound It is, however, unlikely that a full global market for emission permit would be operational during the initial stages of the first commitment period of the Kyoto Protocol In case of trading only among the Annex B countries, the price ranges from 24 to 228 $/ton C, while in the case of emission trading among Annex B countries plus CDM (which perhaps is the more likely scenario), it is estimated to be in the range of 86–126.8 $/ton C In this study we consider two emission trading scenarios: (i) Full Global Trading, and (ii) Annex B Trading plus CDM., Under the Full Global Trading scenario, two cases are considered, i.e., one involving high value of the price of carbon and the other with low value Following Manne and Richels (1999), in Annex B Trading Plus CDM scenario, the price of carbon is taken as 126.8 $/ton C Table 10 shows the NPV of candidate CDM projects in 1998 prices under the two emission trading scenarios from the host country's perspective While calculating the NPV of candidate CDM project, emission in any year exceeding the corresponding baseline emission is treated as a cost At a price of carbon of 22 $/ton C, which is an estimate at the lower side under the Full Global Trading scenario, solar PV plant would yield positive NPV only under the IRP+RE case In this case, the solar PV plant would breakeven when the international price of carbon is 5.4 $/ton C At a higher price of carbon under the Full Global Trading scenario, IGCC plant is found to have positive NPVs in all three cases At this price, PFBC plant also looks attractive under the TEP case Annex B Trading Plus CDM scenario also exhibit results similar to Full Global Trading Scenario at higher price of carbon Clearly, the economic viability of the candidate CDM projects would depend upon the international price of carbon Table 10 NPV of benefit of the candidate CDM projects under different scenarios, M$ (1998) NA—not applicable, because candidates not satisfy the emission criteria 5.6 Effects on local/regional environmental emissions A CDM project is expected to contribute towards sustainable development of the host country through project related benefits Apart from direct economic benefits (e.g., additional employment generation), the project related benefits could include any positive effects that the project would have on the local and/or regional environment Table 11 shows the levels of cumulative reduction during the planning horizon of SO and NOx emissions (i.e., the precursors of acid rain) from the power system with the addition of each of the candidate CDM projects in the generation capacity of the power system Note that there would be reductions of SO and NOx emissions from the power system with IGCC, and PFBC plants in all three cases considered However, with BIGCC and solar PV plants there would be an increase in SO emission in the IRP case Furthermore, the solar PV plant would also lead to higher NOx emission in all three cases Table 11 Total SO2 and NOx emission reduction by candidate CDM projects during 2005–2018, 103 tons 5.7 Effects of variation in the year of the CDM power plant addition Earlier, we analyzed the effect of adding each of the candidate CDM project capacity to the power system in 2006 How would the results vary if a CDM project was added to the power generation capacity of the system in a year other than 2006? For this purpose, we analyze the case of adding the IGCC plant in different years The IACs with the addition of the IGCC plant at different years under the three cases are shown in Fig The IAC is found to vary with the time of CDM project addition This variation is mainly due to different amount of generation capacity replacement and changes in generation-mix with the addition of the CDM project in different years Furthermore, the figure shows that the values of IAC not reveal any consistent pattern with the type of baseline considered The IAC would be minimum under both the TEP and IRP+RE when the IGCC plant as a CDM project is added to the power generation capacity in the year 2009 while it would be at the minimum in 2008 under the IRP Furthermore, IAC under the IRP is found to be higher than that under the TEP and IRP+RE for the selected years of plant addition except 2008 (8K) Fig Variation in IAC with the year of commitment of a 400 MW IGCC plant Two observations are worth making here First, IAC of the candidate CDM power plant need not show any consistent pattern with the year of the plant's addition to the power system That is, the IAC does not rise or fall monotonically with the year of commitment of the CDM plant Second, it is not necessary for the IAC under the IRP (without RE) to be always higher than that under the TEP and IRP+RE cases for most of years of the CDM plant addition For example, the IAC under the IRP in year 2008 is lower than that in the other two cases unlike in most other years In order to determine the most attractive (in terms of maximum benefits) timing for the introduction of the CDM project, NPVs of the IGCC plant are calculated for different years Assuming the value of 126.8 $/ton C for the price of carbon under the Annex B Trading Plus CDM scenario, the NPV of the IGCC plant as the CDM project at different years of its commissioning during 2006–2012 are shown in Table 12 It is interesting to note that the NPV of the IGCC plant would be highest when it is added to the power system in 2009 under the TEP, while it would be highest in 2008 and 2006 under the IRP and IRP+RE, respectively This suggests that the optimal timing of the CDM projects commissioning could also vary with the type of approach used for setting the baseline emission Table 12 NPV of a 400 MW IGCC plant committed at different years, 1998 M$ 5.8 Effect of variation in CDM project capacity How would the IAC vary with the size of the CDM project under alternative baseline approaches considered? To answer this, we calculate the values of IAC of the IGCC plant by varying its capacity from 400 to 2000 MW Fig shows IACs figures for different sizes of the IGCC plant as a CDM project under the three baseline approaches Note that the IAC does not reveal any clear trend under any of the three baseline approaches The IAC is found to be lowest with the IGCC plant capacity of 800 MW under the IRP while it is lowest with the IGCC plant of 400 MW capacity plant under both TEP and IRP+RE (7K) Fig Variations in IAC with the sizes of IGCC plant How is the NPV of the CDM project related with the size (capacity) of the project? As can be seen from Fig 6, NPV does not necessarily increase with the size of the IGCC plant For example, under the TEP and IRP cases, NPV of the project at the plant capacity of 2000 MW would be higher than that at 400–1600 MW On the other hand, in the case of IRP+RE, the NPV of the project at the capacity of 1600 MW would be higher than that at 2000 MW Similarly, the project with a capacity of 800 MW would yield higher NPV than that with the capacity of 1200 MW under the IRP and IRP+RE cases The differences in the value of the NPV for different capacities of the CDM plant are mainly due to different levels of CO2 mitigation at different plant capacities It should be noted here that a higher capacity of CDM project may not necessarily mitigate a higher level of CO2 emission because generation mix of the system is determined so as to minimize the total cost and not on the basis of minimizing total CO emission Clearly, this result shows that the NPV of a CDM project need not necessarily increase with the size of the project (7K) Fig Variation in NPV with the sizes of IGCC plant Conclusion This paper has examined the effects of alternative approaches for setting baseline emission on the levels of CO emission reduction and additional cost associated with the adoption of a cleaner and more energy efficient power generation unit under the CDM The study shows that the eligibility of a cleaner power generation project for implementation under the CDM could very much depend upon the approach used for determining baseline emission In the case of India, the study shows that adoption of PFBC and solar PV plants would result in a reduction of CO emission from the power system under the TEP approach, while they would lead to an increase in CO emission from the power system under the IRP approach without considering the RE The incremental abatement cost (IAC) of CO emission with the adoption of some CDM power projects exhibit considerable variation among the alternative approaches considered For example, the IAC of the BIGCC power plant ranges from 132 $/ton C under the IRP (without the RE) to 223 $/ton C under TEP Sensitivity analysis shows that the eligibility and economics of a cleaner power generation project for implementation under the CDM could depend upon the size (i.e., generation capacity) of the project even under a particular baseline approach An addition of a solar PV project of MW capacity to the power system was found to result in an increased CO2 emission from the power system as a whole during the planning horizon under the IRP approach (without RE) On the contrary, total CO emission from the power system was found to decrease under the same approach when total capacity of the solar PV plant was 400 MW As to the question of whether a bigger sized project would necessarily improve the economics of the CDM project, the study finds no consistent result For example, the NPV of adopting a 1200 MW IGCC power plant (as a CDM project) under the IRP (without RE) was found to be smaller than that of plants with capacities of 800 MW and 1600 MW Under the TEP approach, an addition of a 1200 MW IGCC plant was found to yield a higher NPV than the plants with the capacity of 400, 800 and 1600 MW but a lower NPV than a plant with 2000 MW capacity The optimal timing for the addition of a plant capacity under the CDM can vary significantly depending upon the approach used for setting the baseline emission Our study shows that an addition of a 400 MW IGCC plant capacity to the power system in the year 2009 would result in the highest NPV under the TEP approach while the NPV of the plant addition under the IRP and IRP+RE approaches would be the highest if the plant addition would take place in 2008 and 2006, respectively When baseline emissions are set under the IRP approach, the RE can affect the eligibility and economics of a candidate CDM project This has been highlighted by the case of the solar PV power plant The plant was found to be eligible as a CDM project under the IRP with the RE considered, but it was not eligible under the IRP approach without the RE Similarly, the optimal timing of a candidate CDM project is also found to vary when RE is considered In the absence of empirical estimation of the RE for the energy efficient electrical end-use devices in India, this study has assumed the value of RE to be 25% Clearly, the quantitative results under the IRP+RE case would be different if the magnitude of the RE is to change A study to estimate the RE would, therefore, be very important for carrying out a more reliable quantitative analysis It should also be noted that the international market price of carbon permits without the participation of the US in the Kyoto Protocol would be significantly lower than what has been used in this study The economics of individual CDM projects could be affected in quantitative terms by a change in the carbon permit price However, most of the insights and qualitative results of the present study would still remain valid Acknowledgements This work is part of a project entitled "Mitigating Environmental Emission from Power Sector: Analysis of Technical and Policy Options in Selected Asian Countries" carried out under the framework of the second phase of the Asian Regional Research Programme in Energy, Environment and Climate (ARRPEEC) funded by Swedish International Development Cooperation Agency (Sida) We would like to thank anonymous reviewer for his helpful comments on the earlier version of the paper However, we are solely responsible for any remaining error References Central Electricity Authority (CEA), 1997 Fourth Electric National Power Plan 1997– 2012 CEA, New Delhi Central Electricity Authority (CEA), 1998 Electricity Supply Industry Salient Data 1995–1996 CEA, New Delhi Chomitz, K.M., 1999 Baselines for Greenhouse Gas Reductions: Problems, Precedents, Solutions Proceedings of Workshop on Baseline for CDM New Energy and Industrial Technology Development Organization Tokyo, February 25–26 Ellerman, A D., Decaux A., 1998 Analysis of Post-Kyoto CO2 Emissions Trading Using Marginal Abatement Curves, Report No 40, Joint Program on the Science and Policy of Global Change Massachusetts Institute of Technology, USA Greene, D.L., 1992 Vehicle use and fuel economy: how big is the "rebound" effect The Energy Journal 13 1, pp 117–143 Abstract-EconLit Greening, L.A., Greene, D.L and Difiglio, C., 2000 Energy efficiency and consumption —the rebound effect—a survey Energy Policy, 28, pp 389–401 Abstract-Compendex | Abstract-GEOBASE | Abstract-INSPEC | Abstract + References in Scopus | Cited By in Scopus Hirst, E., 1991 Creating the future: integrated resource planning for electric utilities Annual Review of Energy and the Environment 16, pp 91–121 Abstract-GEOBASE | Abstract + References in Scopus | Cited By in Scopus ILOG, 2001 CPLEX 7.1, ILOG Inc., USA Jones, C.T., 1993 Another look at US passenger vehicle use and the "rebound" effect 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References in Scopus | Cited By in Scopus Painuly, J.P., 2001 Kyoto protocol, emission trading and the CDM: an analysis from developing countries perspective The Energy Journal 22 3, pp 147–169 AbstractEconLit | Abstract-Compendex | Abstract + References in Scopus | Cited By in Scopus Ronald, K and Haugland, T., 1994 Joint implementation: difficult to implement In: Jepma, C.J., Editor, , 1994 The Feasibility of Joint Implementation, Kluwer Academic Publishers, Dordrecht, pp 359–366 Roy, J., 2000 The rebound effect: some empirical evidence from India Energy Policy 6–7, pp 433–438 SummaryPlus | Full Text + Links | PDF (95 K) | Abstract + References in Scopus | Cited By in Scopus Shrestha, R.M., Shrestha, R., Samarakoon, H., 2001 An electric utility integrated resource planning model Energy Program, Asian Institute of Technology, Pathumthani, Thailand, Mimeo Srivastava, A.K., 2001 Power sector development in India with GHG emission target: Effect of regional grid integration and the role of clean technologies ARRPEEC Fellowship Research Report, Asian Institute of Technology, Thailand Zein-Elabdin, E.O., 1997 Improved stoves in Sub-Saharan Africa: The case of the Sudan Energy Economics 19, pp 465–475 SummaryPlus | Full Text + Links | PDF (631 K) | Abstract + References in Scopus | Cited By in Scopus Corresponding author Tel.: +66-252-454-06; fax: +66-252-454-39 In the context of developing countries, very few studies exist on the estimation of enduse specific RE Roy (2000) estimated that the RE could be up to 50% for replacing low efficiency (1%) kerosene lamps by relatively efficient renewable lighting technology i.e., solar lanterns in the non-electrified rural household sector of India Some estimates in the case of industrialized countries suggest that the effect need not be small For example, Khazzoom (1987) reports that for electrically heated homes (in the US), "… approximately two-third of the initial saving due to the engineering effects of the increased efficiency got eroded because of the feedback effect" ( Khazzoom, 1987, p 89) 2 The incremental abatement cost (IAC) is calculated as: IAC=(TC I–TC0)/[ ] where TCi is the total discounted cost during the planning horizon with CDM i, TC0 the total discounted cost during the planning horizon without CDM, ej0 is the CO2 emission in year j without CDM, eji is the CO2 emission in year j with CDM i, r is the discount rate, and N is the number of years in the planning horizon The NPV of a project is the discounted value of cash inflows (benefits) less cash outflows (cost) of the project In the case of a CDM project, the benefit is revenue from the sell of emission permit (i.e., market price of emission permit times amount of mitigation) and the cost is the increase in total power system development cost with the implementation of the CDM project The carbon abatement cost figures here are taken from Painuly (2001) An annual inflation rate of 3% is assumed to convert the values in 1995 US dollars to 1998 US dollars Here we refer to Full Global Trading and Annex B Trading plus CDM scenarios as defined by Ellerman and Decaux (1998) and Manne and Richel (1999), respectively  ... time for implementation of the project, that is, the year of addition of the CDM power plant capacity to the power system Thus, it is of interest to examine whether the alternative approaches for. .. approaches for the baseline emissions would affect the size and optimal timing of a CDM project In this paper, we examine the effect of alternative baseline approaches on economics of a CDM project... the issue of optimal timing and size of a CDM project under the alternative approaches The organization of the paper is as follows: Section presents a brief overview of the power system under the