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

The objective of the IRP model is tominimize the total cost comprising generation capacity, fuel, operation and maintenancecost of plants as well as the DSM costs of power sector develop

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

Energy Program, School of Environment, Resources and Development, Asian Institute ofTechnology, P.O Box 4, Klong Luang, Pathumthani 12120, Thailand

Abstract

Setting the baseline emission and estimating emission reductions associated with aclimate friendly project are among the key issues involved in identification of a cleandevelopment mechanism (CDM) project under the Kyoto Protocol This paper presents amethodology for identification of a CDM project and assessment of its environmental andeconomic implications under alternative approaches for establishing baseline emission,that is, traditional supply based planning and integrated resource planning (IRP) Thepaper also examines the role of "rebound effect" in the assessment of emission reductionsfrom the CDM project under the IRP approach A case study of India based on themethodology is presented in the paper The study shows that the level of emissionmitigation from the power system with a particular CDM project and the associatedemission abatement cost could vary significantly with the type of approach used fordetermining the baseline emission It also shows that the optimal timing forimplementation of the CDM project could vary with the type of the baseline approachused Furthermore, our analysis shows that under each of the baseline approaches, the netbenefit from a candidate CDM project need not increase with its size (i.e., generatingcapacity)

Author Keywords: Author Keywords: Baseline emission; Clean development

Article Outline

1 Introduction

2 Overview of the Southern Regional Electricity Board power system in India

3 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

4 Methodology

5 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

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 CDMproject 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 acandidate CDM project However, the task of setting the baseline emission anddetermining emission reduction from the power system with a CDM project involves anumber 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, theneed to follow an integrated resource planning (IRP) approach, which considers bothsupply and demand-side options in the power sector development, has been widelyrecognized (e.g., see Hirst, 1991) The IRP approach is preferred to the TEP approachfrom the social perspective as it promotes an efficient use of both supply and demand-side resources However, the level of baseline emissions under the IRP would be differentfrom that under the TEP

The levels of GHG emissions avoided from the power system and increase in total systemcost due to a candidate CDM project under the IRP need not be the same as that under theTEP As a result, the marginal cost of emission abatement, which serves as an indicator ofthe cost effectiveness of a CDM project to potential investors from Annex B countriescould be different under the alternative planning approach Furthermore, an importantissue related to the determination of baseline emissions under the IRP is the "reboundeffect (RE)" of energy efficient demand-side management programs (also known as the

"feedback effect") which implies that actual electricity savings after the introduction of anenergy efficient demand-side technologies would be less than the savings based onengineering 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 emissionunder the IRP considering the RE and the corresponding level of emission reduction by acandidate CDM project would be different from that under the IRP without consideringthe RE

An important issue related to a CDM power project is the determination of economicallythe most attractive size of the project Another issue is the optimal time forimplementation of the project, that is, the year of addition of the CDM power plantcapacity to the power system Thus, it is of interest to examine whether the alternativeapproaches for the baseline emissions would affect the size and optimal timing of a CDMproject In this paper, we examine the effect of alternative baseline approaches oneconomics of a CDM project We also discuss the issue of optimal timing and size of aCDM project under the alternative approaches

The organization of the paper is as follows: Section 2 presents a brief overview of thepower system under the Southern Regional Electricity Board in India Section 3 describesthe three alternative baseline emission cases considered in this study This is followed by

a description of the methodology used Section 5 discusses the least cost generationtechnologies selected under each approach considered and the candidate CDM projects Italso discusses the emission reduction and cost implications of selected candidate CDMprojects along with sensitivity analyses with respect to changes in size and time ofimplementing the CDM project Finally, the major conclusions of the paper aresummarized

2 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 ElectricityBoard (EREB) and North-Eastern Regional Electricity Board (NEREB) Under these fiveREBs there are 26 State Electricity Boards Table 1 shows the installed power generationcapacity of different REBs and the total figures for India as a whole

Table 1 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 installedgeneration capacity of India in 1997 At the end of 1997, the total installed capacity inSREB was 20,477 MW, with the share of thermal, hydropower and nuclear plant being54.9%, 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 2

Table 2 Peak load and energy requirement forecast for selected years

Source: CEA (1997).

3 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 electricitydemand during the planning horizon of 2005–2018 This is typically the case oftraditional supply side electricity planning defined hereafter as "TEP case" Thirteencandidate hydropower plants and seven types of candidate thermal power plants areconsidered The candidate thermal plants include two types of coal-fired plants, gas basedcombined cycle plants (i.e., CCGT), nuclear plant, two types of efficient and clean coalplants (integrated gasification combined cycle (IGCC) and pressurized fluidized bedcombustion (PFBC)), and biomass integrated gasification combined cycle (BIGCC)

plants that use biomass at a sustainable rate (thus, net emission from electricitygeneration from BIGCC would be zero) Furthermore, solar PV and wind power plantseach of 2 MW capacity are also considered The technical, economic and environmentalcharacteristics of the candidate power plants are shown in Table 3

Source: Srivastava (2001)

The data on projected values of peak load and electricity generation requirements used inthis study are based on CEA (1998) while the system load profile as well as the data onexisting 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 TEPcase is considered In addition, four efficient DSM options are considered for which themaximum level of penetration and incremental costs are shown in Table 4 However, the

RE of DSM options on electricity demand (and thus on generation) is not taken intoaccount in this case Hereafter, we call this case as the "IRP case"

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 efficientDSM options selected on electricity demand Hereafter, this case is referred to as

"IRP+RE Case" Table 5 shows the values of RE of selected efficient end-use devicesbased on the literature Note here that RE in Table 5 is expressed as the reduction insavings due to the fall in effective price of energy services due to a adoption of energyefficient end use technologies as a percentage of total savings based on purelyengineering estimates In the absence of information on RE specific to the SREB, India,

IRP+RE) The flow chart of methodology is illustrated in Fig 1 The least cost powerdevelopment 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 iscapable of considering both the supply and demand-side options to derive the least costgeneration-, fuel- and DSM-mixes to meet the projected power demand during theplanning horizon (2005–2018) The model can also be used to determine the least costgeneration- and fuel-mix without DSM options in which case it serves the purpose of atraditional electricity generation planning model The objective of the IRP model is tominimize the total cost (comprising generation capacity, fuel, operation and maintenancecost of plants as well as the DSM costs) of power sector development over the planninghorizon subject to relevant constraints of the power system The model includes thefollowing constraints:

(10K) Fig 1 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 planninghorizon

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 powerdemand 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 schedulemaintenance 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 [seeShrestha et al (2001) for details of the IRP model formulation] In the present study, themathematical 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 casewould be different from that without RE For an illustration, Fig 2 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 2 Power generation profile under three baseline emission cases

In order to derive the level of emission reduction from the power system with a candidateCDM project under different cases during the planning horizon, we first define thefollowing 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

Total CO2 emission mitigation from the power sector with a CDM project j under the IRP case, i.e., without considering the RE (ΔE I,NR j) is given by

Similarly, the total CO2 emission mitigation from the power sector with a candidate CDM

project j under the IRP+RE case (ΔE I,RE j) is

ΔE I,RE j =E I,RE0−E I,RE j (3)The power sector planning model (i.e., IRP model) computes total cost, includingcapacity cost, operation and maintenance (O&M) cost and fuel cost as well as emissionlevels of different pollutants including GHG (only CO2 considered in the present study).The incremental carbon abatement cost (IAC) of a candidate CDM option is calculatedunder different cases., 2 Fig 3 presents the basic framework for identification of a CDMproject in this study In order to determine whether an electricity generation plant wouldqualify for implementation as a CDM project, three criteria are proposed: (a) costcriterion, (b) emission criterion, and (c) net present value (NPV) criterion

(16K) Fig 3 Flow chart for identification of CDM Projects

The cost criterion states that the total cost with a CDM option (TC1) should be greaterthan the total cost (TC0) without the CDM option The emission criterion requires that thetotal 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 thepower system, whereas the NPV criterion states that the NPV of a CDM project at agiven price of carbon mitigation (or market price of emission permits) should be positive.,

3

5 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 hydropowerplants with total installed capacity of 6123 MW would be selected during 2005–2018.Among the thermal power plants, only gas based combined cycle plants, conventionalcoal fired plants and lignite plants are selected during the period A total of 41,484 MWgenerating 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 ofwind 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 thiscase Total installed capacity in this case during the planning horizon would be 9300 MWless than that in the TEP case because of the use of cost-effective efficient demand-sideoptions As a result, total generation capacity added to the power system during theplanning horizon in this case is 32,184 MW All four candidate DSM programsconsidered were selected to their maximum potential As in the TEP case, none of thecandidate solar, PFBC, IGCC, BIGCC and nuclear plants would be among the least costgeneration capacity added during the period while wind power plants with a totalcapacity 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 theprevious two cases Total hydro capacity added in this case is the same as that under theIRP case without the RE With the inclusion of the RE, total electricity demand and thusgeneration would be higher than that under IRP without the RE As a result, totalgeneration capacity added during the planning horizon in this case exceeds that under theIRP case without RE by 2800 MW Total capacity added during the planning horizonunder 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 arenot selected as a part of the least cost capacity expansion plan in this case Wind powerplant 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 powerplants are included in the least cost power development plans under the three casesconsidered as they were not found cost effective Therefore, these plants could beconsidered 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 Nocandidate hydro- and wind-power plant would qualify as a candidate CDM project underthe cost criterion as these projects are found to be among the least cost options in each ofthe three approaches (i.e., cases) considered Similarly, none of the candidate DSMoptions considered would qualify as a CDM project in this study as the full utilization ofall of them is found cost effective under each of the three approaches

5.3 CO2 emission reduction with CDM projects under different cases

Table 6 shows total CO2 emission reduction from the power system with candidate CDMprojects 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 acandidate CDM project (hereafter "specific CO2 emission reduction") during the planninghorizon Note that all candidate CDM projects considered in the study, except the PFBCand solar PV plants, satisfy the emission criterion in all three cases An addition of PFBCplant in 2006 would result in a reduction of total CO2 emission from the power system