1-s2 0-S0301421513007982-main

Long term strategy for electricity generation in PeninsularMalaysia – Analysis of cost and carbon footprint using MESSAGE

S.M.C. Fairuz a, M.Y. Sulaiman b,n, C.H. Lim b, S. Mat b, B. Ali b, O. Saadatian b, M.H. Ruslan b,E. Salleh b, K. Sopian b

a Malaysian Nuclear Agency, 43000 Kajang, Selangor Darul Ehsan, Malaysiab Solar Energy Research Institute, Universiti Kebangsaan Malaysia, 43600 UKM Bangi, Selangor Darul Ehsan, Malaysia

H I G H L I G H T S

� We analyzed the cost of energy expansion and resulting carbon emission using software MESSAGE.� We studied the energy situation for the next 20 years beginning 2009 for Peninsular Malaysia.� We maintained the present energy resources of natural gas, coal and internal hydropower.� We included nuclear, hydropower import and renewable energy as new strategies.

a r t i c l e i n f o

Article history:Received 6 February 2012Accepted 2 August 2013

Keywords:Energy strategyCarbon footprintMESSAGE

a b s t r a c t

Malaysia envisages becoming a developed nation by 2020. To sustain industrial expansion and attractinvestments Malaysia must introduce new energy strategies. These strategies should also moderatecarbon footprint. The new energy strategies introduced by the government are (i) installation of nuclearpower plant by 2021, (ii) import of Sarawak hydropower from 2015 and (iii) enhancement of use ofrenewable energy from 2015. In this paper we analyze the cost and resulting carbon footprint of energyexpansion for 12 energy scenes (inclusive of new strategies) to produce electricity for PeninsularMalaysia for the period 2009–2030. We use a computer model MESSAGE to provide optimization. Thebest strategy is for the following accumulated percentage of energy resource in the fuel mix: 49.3%(natural gas), 28.4% (coal), 4.06% (nuclear), 2.98% (hydropower), 4.45% (renewable), 10.82% (importhydropower). The minimum cost of expanding this strategy from 2009 until 2030 is USD6.090B. The CO2

emission index of this strategy is 0.329 t/MWh. The accumulated carbon dioxide emission for this periodis 1825.96 Mton CO2 eq.

& 2013 Elsevier Ltd. All rights reserved.

1. Introduction

Malaysia has set its sight on becoming a developed nation by2020. To maintain annual average growth of 6% Malaysia mustsustain industrial expansion (Ang, 2008). This makes electricitygeneration high priority. Fig. 1 shows the positive correlationbetween Gross Domestic Product of Malaysia and the supply ofelectricity for the period 1990–2008 (KETTHA, 2007; BNM, 2009).

The reason why Malaysia must continually review its energypolicy is twofold.

First, by 2019 Malaysia will become a net importer of oil andnatural gas (Noriyah Ahmad, 2010; EPU, 2009). Currently, Malaysiais overly dependent on fossil fuel such as natural gas and coal toproduce electricity (Oh et al., 2010). To address energy sufficiency,Malaysia must put in place smart energy initiatives to boost theconfidence of investors and to ensure growth.

Second, at the Conference of Parties in Copenhagen at the endof 2009 (COP 15, 2009) Malaysia has pledged to reduce carbonemission by 40% from the base year 2005 by the year 2020.However, if business as usual is the energy scenario the releasecarbon dioxide will increase to 130% by 2050 (Oh et al., 2010).

2. Emission of green house gases

Report by the Ministry of Natural Resources and EnvironmentMalaysia (NC2, 2000) showed the amount of green house gases

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0301-4215/$ - see front matter & 2013 Elsevier Ltd. All rights reserved.http://dx.doi.org/10.1016/j.enpol.2013.08.005

n Corresponding author. Tel.: þ60 389118583; fax: þ60 389118574.E-mail addresses: [email protected] (S.M.C. Fairuz),

[email protected], [email protected] (M.Y. Sulaiman),[email protected] (C.H. Lim), [email protected] (S. Mat),[email protected] (B. Ali), [email protected] (O. Saadatian),[email protected] (M.H. Ruslan), [email protected] (E. Salleh),[email protected] (K. Sopian).

Please cite this article as: Fairuz, S.M.C., et al., Long term strategy for electricity generation in Peninsular Malaysia – Analysis of cost andcarbon footprint using MESSAGE. Energy Policy (2013), http://dx.doi.org/10.1016/j.enpol.2013.08.005i

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(GHG) emitted in the year 2000 was 222.99 Mton CO2 eq. Table 1gives the breakdown according to sectors.

From Table 1 the energy sector emits the highest amount ofgreen house gases.

GHG is made up of several polluting gases such as carbondioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluoro-carbon (HFC) and sulfur hexafluoride (SF6). Fig. 2 shows thepercentage emission of these gases in the year 2000 and Table 2gives the emission indices in terms of GDP and population. Theamount of carbon dioxide emitted in the year 2000 was167.44 Mton CO2 eq. (NC2, 2000).

In the study by Haslenda et al. (2005), proper energy balancingto produce electricity was able to reduce carbon dioxide emission by3%. The study evaluated emission from power plants such as coal,natural gas, nuclear, hydropower and renewable in Ontario, Canada.

The emission was for the operational period of the power plant. Thework used an optimization model known as General AlgebraicModeling System (GAMS).

3. Objective

In this paper we analyze the long-term strategy for electricitygeneration in Peninsular Malaysia using the software MESSAGE.An acronym for Model for Energy Supply System Alternatives andtheir General Environment Impacts, MESSAGE guides policymakers on the best strategies to adopt, such as energy securityand carbon footprint. In this work, MESSAGE determines the costof expanding several energy systems over 21 years (2009–2030)for different energy related inputs and constraints. It is to beemphasized that the study does not cover the following aspects ofelectricity generation: (i) energy distribution cost and (ii) costrelating to security aspect of fuel storage and disposal as in anuclear power plant. The energy expansion cost is largely deter-mined by the fuel cost in the energy mix. The analysis determinesthe contribution of available and new power plants to the totalgenerating capacity of electricity generation. Analysis of pollutionis limited to carbon dioxide emission from the energy sector.MESSGE gives the amount of carbon dioxide emitted from powergenerations accumulated over the 21 year period. From this outputand the generating capacity, the CO2 emission index can bedetermined.

The previous work on electricity generation and consumptionin Malaysia were reported by Abdul Hamid et al., 2008; Chor,2008; Chandran et al., 2010. Applications related to MESSAGE canbe found in the publications by Klaassen and Riahi (2007) andHainoun et al. (2010). The following study however differs fromprevious studies with regard to long term energy planning as itwill provide decision makers with data on the cost implication ofadopting particular energy mix and the subsequent carbon dioxideemission.

4. Methodology

MESSAGE sets up models of energy supply and utilization andfinds the best expansion path for the energy system based oncertain fuel management in the medium and long-term period.Developed by International Institute for Applied Systems Analysisand enhanced by International Atomic Energy Agency (IAEA, 2007)many countries use the software to help build an energy model.MESSAGE assures sufficient energy supply for the given technol-ogies and resources according to the specified energy demand.Simulation continues along an energy chain from supply todemand. Various stages of the energy chain have inputs makingup the reference energy system.

The reference energy system has four stages shown in Fig. 3. Thestages are resources, primary, secondary and final. At the resourcesstage, the inputs are crude oil and natural gas since they aredomestic resources of Malaysia. Refining of the crude oil and

Fig. 1. Variation of Gross Domestic Product and the supply of electricity forMalaysia between 1990 and 2008 (USD1¼RM3.2).

Table 1GHG inventory for the year 2000.

Sector Pollution (Mton CO2 eq.)

Energy 147.00Industrial process 14.13Agriculture 5.91LULUCFa 29.59Waste 26.36

Total 222.99

a LULUCF refers to forest and grassland conversion.

Fig. 2. Percentage of GHG gases emitted for the year 2000.

Table 2Malaysian GHG emission indices for the year 2000.

NC2 (2000)

GDP (million RM) 356,401Population (million) 23.5CO2 eq. (Mton) 223CO2 eq. per GDP (ton/thousand RM) 0.62CO2 eq. per capita (ton/capita) 9.5

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natural gas constitutes the primary stage. Processed coal anduranium from import are also primary inputs. Feeding of powerplants with fuel occurs at the secondary stage. Distributions ofelectricity to the industry, commercial, residential and transportsectors make up the final stage.

By default, MESSAGE minimizes the total system costs as acriterion for optimization. Investment costs, operational cost andpenalty costs make up the total system cost. Discounting all costsoccurring at later points in time to the base year gives the presentvalue. The sum of all discounted costs gives the best solution.In this work we use a discount rate of 10% (BNM, 2009).

5. Input data

MESSAGE requires inputs such as (i) extrapolated energydemand, (ii) fraction of load demand, (iii) capacity and investmentin technology and (iv) limits, bounds, constraints on existing andnew power plant technologies. Below is a description of theseinputs.

5.1. Extrapolated power demand

Table 3 gives the extrapolated power demand of PeninsularMalaysia for the period 2010–2030 with 2009 as the referenceyear (TNB, 2009). MESSAGE will analyze within the bounds ofthese power demand.

5.2. Fraction of load demand

The demand for electricity varies with time. MESSAGE simu-lates this condition based on the load at the time of use. Table 4gives the load data for Peninsular Malaysia provided by the UtilityCompany (TNB, 2009). The yearly load division considers twomonsoon seasons. The south west monsoon is April to October andnortheast monsoon is October to February. The demand forelectricity is higher during the northeast monsoon affecting widerregion of the Peninsular as a result of heavy rainfall, strong windand overcast sky. The weekly load comprises working days,Saturday, Sunday and public holiday. These are split into time

domain. Working days and Saturday are split into six timedomains; Sunday and public holiday into five.

5.3. Capacity and investment in technology

Capacity and investment in technology relies on the type,efficiency and year of decommissioning of various power plants.Tables 5–8 give the respective data for existing conventional andthermal power plants, existing hydropower plants, new powerplants and new hydropower plants in Peninsular Malaysia.

5.4. Limits, bounds and constraints on existing power planttechnology

Tables 9 and 10 give the limits, bounds and constraints on thecapacity of the existing and new power plant technologies and fuelresources provided by the Utility Company.

6. Results and discussion

Table 11 gives the accumulated energy mix for the variousenergy scenarios analyzed by MESSAGE. Table 12 tabulates thecost of expanding these energy systems and the accumulatedamount of carbon dioxide emitted from 2009 until 2030. Table 12also gives the CO2 emission index. Table 13 lists the accumulatedpower capacity produced by the different power plants forall cases.

Reference case. The reference case is a business as usual based onthe 2009 energy mix with fuel price subsidized by the govern-ment. No new energy strategy is introduced. Table 11 shows theaccumulated percentage of energy resource in the fuel mix. Themix consists of natural gas (49.98%), coal (47.03%) and hydropower(2.98%). From 2010 until 2030 natural gas utilization of PeninsularMalaysia increases by only 16.5%. This is because of the capping

Fig. 3. MESSAGE reference energy system.

Table 3Extrapolated power demand of Peninsular Malaysia for 2010–2030.

Year Powerdemand(MW)

Yearly growth inpower demand frombase year 2009 (%)

Year Powerdemand(MW)

Yearly growth inpower demand frombase year 2009 (%)

2009 14,577 – 2020 20,669 41.792010 15,131 3.80 2021 21,308 46.182011 15,674 7.53 2022 21,741 49.152012 16,228 11.33 2023 21,911 50.312013 16,760 14.98 2024 22,452 54.022014 17,271 18.48 2025 22,967 57.562015 17,799 22.10 2026 23,449 60.862016 18,352 25.90 2027 23,893 63.912017 18,895 29.62 2028 24,333 66.932018 19,467 33.55 2029 24,771 69.932019 20,057 37.59 2030 25,193 72.83

Table 4Proportion of yearly and daily load regions in Peninsular Malaysia.

Time domain Yearly Weekday Saturday Sunday and holiday

1 0.52 0.08 0.06 0.082 0.48 0.25 0.29 0.353 – 0.13 0.15 0.254 – 0.23 0.16 0.115 – 0.10 0.15 0.216 – 0.21 0.19 –

Total 1.00 1.00 1.00 1.00

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introduces by the government at 21,200 MWyr (refer to Table 9).Hydropower from Peninsular Malaysia increases by only 15.2% andthis is because of limited capacity. Thus, coal increases from4915 MW in 2009 to 13,939 MW in 2030.

Theminimum cost of expansion of the energy system for the entireduration is USD5.897B (Table 12). This consists of fuel cost, overheadand maintenance (O&M) cost and investment on new and old powerplants. Total O&M cost comprises fixed and variable costs.

During 2009 until 2030 the accumulated amount of releasedcarbon dioxide from electricity generation is 2506.77 Mton CO2 eq.(Table 12). The amount release in 2030 is higher by 98.2% than

2009. The increase is due to the expanded capacity of coal powerplants. The CO2 emission index is 0.460 t/MWh.

As shown in Table 13 the accumulated capacity for electricitygeneration in Peninsular Malaysia for the 21 year period is621,692 MWyr. Table 13 also gives the contribution of the variouspower plants to the generating capacity.

Case 1. The accumulated percentage of energy resource in the fuelmix (Table 11) is 49.99% (natural gas), 42.96% (coal), 4.06% (nuclear)and 2.98% (hydropower). The nuclear energy plant will beginoperation in 2021 with an initial power capacity of 2000 MW (referto Table 10). The introduction of nuclear energy decreases the

Table 5Parameters of existing conventional and thermal power plants in Peninsular Malaysia (TNB, 2009).

Name of plant Fuel Number Yearoperational

Total capacity(MW)

Capacity factor(%)/plant factor

Fixed O&M cost(USD'00/kWyr)

Variable O&M cost(USD'00/kWyr)

Plantlifetime

Class

TNB Port Klang Ph. I Gas/oil

2 1999 600 90 13.7 9.23 30 Thermal1

TNB Pasir GudangThermal

Gas/oil

2 1983 240

TNB Paka CCYC1 Gas 3 1986 870 85 13.7 14.09 31 CCGT 1TNB Paka CCYC2 Gas 1 1986 266

TNB CBPS CCYC Gas 1 1983 312 90 11.71 22.98 31 CCGT 2TNB Pasir Gudang CCYC Gas 1 1987 269Genting Sanyen CCYC Gas 1 1985 762Segari CCYC Gas 2 1986 1304Pahlawan CCYC Gas 1 1990 322

TNB Gelugor CCYC Gas 1 1997 330 90 14.09 15.49 27 CCGT 3TNB TJPS CCYC Gas 1 2001 750GB3 Gas 1 1995 640TTPC CCYC Gas 1 1997 650Panglima CCYC Gas 1 1996 720SKS Prai Gas 1 1997 350

YTL CCYC Gas 3 1994 1170 90 9 14.09 21 CCGT 4

TNB Janamanjung Coal 3 2003 2070 90 25.7 13.79 28 COAL 1SKS Tanjung Bin Coal 3 2003 2100

TNB Port Klang Ph. II Coal 2 2001 600 90 13.7 13.79 28 COAL 2TNB Port Klang Ph. III Coal 2 2001 1000

TNB Langkawi GTs Diesel 2 1997 68 70 13.7 34.04 21 OCGT Oil

Powertek GTs Gas 4 1995 432 20 16.1 31.29 21 OCGT 1PD Power GTs Gas 4 1995 436

TNB CBPS OCGT Gas 4 1998 520 20 16.1 24.6 25 OCGT 2TNB Serdang GT1 Gas 2 1990 220TNB Serdang GT2 Gas 3 1991 405

TNB Port Klang GTs Gas 2 1987 220 20 16.1 19.02 30 OCGT 3

CCGT: Combined Cycle Gas Turbine.OCGT: Open Cycle Gas Turbine.

Table 6Parameters of available hydropower stations in Peninsular Malaysia (TNB, 2009).

Name ofplant

Quantity Commissioningyear

Maxcapacity(MW)

Totalcapacity(MW)

Mincapacity(MW)

Efficiency(%)

Energy perannum (GWh)

Reservedenergy(GWh)


Class Variable O&Mcost (USD'00/kWyr)

Kenyir 4 1985 100 400 17.5 99 1635 2280 24 Hydro-storage

7.3Temengor 4 1979 84.5 348 1 683.8 287Pergau 4 1997 150 600 1 515.1 62.1

Bersia 3 1983 23.3 70 1 99 223.7 3.4 45 Hydro-ROR

7.3Kenering 3 1983 37 111 1 384.5 24.7Chenderoh 4 1930 8.5 34 1 208.5 2Jor 4 1963 25 100 1 287.6 6Woh 3 1967 49.3 148 1 435.4 1.9Piah andOrdak

1 1993 67 67 1 380 0.1

Hydro-ROR: hydro-plant using run-of-river scheme.






contribution of coal in the energy mix. The contributions of naturalgas and hydropower remain the same as the reference case.

The minimum cost of expanding the energy system from 2009until 2030 is USD5.99B (Table 12). Compared to the reference casethe cost increases by 1.59%. This is because of the capital costrequires to install the nuclear plant.

The accumulated amount of carbon dioxide emission is2356.37 Mton CO2 eq. (Table 12). The introduction of the nuclearpower plant reduces carbon dioxide emission. There is a reductionin carbon dioxide emission by 8.9% from 2020 to 2021. In total there isa decrease of 6% in the amount of carbon dioxide emitted compared tothe reference case. The CO2 emission index is 0.432 t/MWh.

The accumulated generating capacity is 622,542 MWyr asshown in Table 13. Also shown is the contribution of the availableand new power plants to the generating capacity.

If Malaysia is to build a nuclear power plant, issues regardingsafety and its associated economics (that could be substantial)must be accounted for by other means. This is in addition tolooking at the impact on environment and cost of nuclear fuelusing MESSAGE.

Case 2. For this case the energy mix includes renewable energy.Table 10 gives the capacity of renewable energy (PTM, 2009) from2009 until 2030. The promotion of renewable energy includes theintroduction of incentive program such as Feed-in-Tariff that willbegin in 2012. Electricity generation from renewable energy willstart with a total capacity of 975 MW in 2015. The capacity willincrease in stages until it reaches 3484 MW in 2030. Table 11shows the accumulated percentage of energy resource in the fuelmix. The mix consists of natural gas (49.78%), coal (45.13%),hydropower (2.98%) and renewable (2.11%).

As shown in Table 12 the minimum cost of energy expansionfor the 21 year period is USD5.820B. This amount is less than thereference case by 1.31%. In evaluating the cost we have used thesubsidized price of fossil fuel.

Since renewable displaces certain fraction of coal in the energymix the amount of released carbon dioxide is less than thereference. As shown in Table 12 the amount of released carbondioxide is 2436.43 Mton CO2 eq. This is less than the reference caseby 2.81%. The CO2 emission index is 0.449 t/MWh.

The accumulated generating capacity of the power plants from2009 to 2030 is 618,916 MWyr as shown in Table 13. Also shown isthe percentage contribution of the various power plants to thegenerating capacity.

Expansion in renewable energy is subject to several constraints.These include high cost of renewable energy plant, longer payback

Table 7Parameters of new power plants: gas, coal, nuclear, renewable energy and import from Sarawak (TNB, 2009).

Plant name Fuel Unit size(MW)

Efficiency(%)


Fix O&M cost(USD'00/kWyr)

Variable O&M cost(USD'00/kWyr)

Investment cost(USD'00/kW)

Construction(year)

Plant life(year)

New OCGT Gas 240 35 45 16.1 31.29 541 2 20New CCGT Gas 750 50 90 13.7 30 765 3 25New Coal Coal 700 36 90 22.3 15 1000 4 30New RE RE – – – – 425.48 – – 20New Nuclear Uranium 1000 39 90 42.29 4.3 2560.90 6 40Sarawak Import Hydro 1000 – 85 – 425.2 – 1.5 60

OCGT: Open Cycle Gas Turbine.CCGT: Combined Cycle Gas Turbine.RE: renewable.

Table 8Parameters of new hydropower stations in Peninsular Malaysia (TNB, 2009).

Name Unit size(MW)

Start year Energy per annum(GWh)

Storage energy(GWh)

VariableO&M cost(USD'00/kWyr)

Constructionyear

Plant life Investment cost(USD'00/kW)

Class

Ulu Terengganu 212 2013 405.7 331.2 7.3 3 60 1144 New hydro-storageUlu Jelai 372 2013 393.8 5.5 60Nenggiri 416 2016 732.7 331.1 60Telom 132 2016 261.8 68.8 60Tekai 156 2016 274.2 127.8 60Lebir 274 2016 388.7 220.6 60

Kerian 21 2016 165.3 0 7.3 3 60 2497 New hydro-RORRaub 70 2016 315.9 0 60Pelus 35 2016 199.2 0 60

Table 9Limits, bounds and constraints of available technologies (TNB, 2009).

Technology Case Limits, bounds and constraints

Gas refineries Reference 21,200 MWyrCO2 emission 1.780 kton/yr

Oil refineries Reference CO2 emission 2.350 kton/yrCoal import Reference CO2 emission 3.000 kton/yrOCGT_Oil Reference No addition capacityOCGT 1 Reference No addition capacityOCGT 2 Reference No addition capacityOCGT 3 Reference No addition capacityCCGT 1 Reference No addition capacityCCGT 2 Reference No addition capacityCCGT 3 Reference 750 MW on 2009CCGT 4 Reference No addition capacity

Fix energy generation at 819 MWyr

Thermal 1 Reference No addition capacityCoal 1 Reference 1400 MW on 2009Coal 2 Reference No addition capacityHydro-storage Reference No addition capacity

Minimum energy flow at 17.5 MWyrHydro-ROR Reference No addition capacity






period, land acquisition problem, ecological displacement as in thecase of hydroelectric power plant, low efficiency (e.g. photovoltaicpower plant) and unreliable energy resources (solar, wind, bio-mass, marine waves etc.).

Case 3. This is a case where imported hydropower from Sarawakis included in the energy mix. Table 10 gives the capacity ofimported hydropower from 2014 until 2031. Table 11 gives theaccumulated percentage of energy resource in the fuel mix. Itconsists of natural gas (49.57%), coal (42.11%), hydropower (2.98%)and imported hydropower (5.34%).

The cost of system expansion is USD5.757B and is less than thereference by 2.38% (Table 12). As with the reference case thegovernment subsidizes the costs of natural gas and coal.

The accumulated amount of released carbon dioxide during theperiod 2009–2030 is 2324.96 Mton CO2 eq. This is less than thereference case by 7.25% (Table 12). The imported hydropowerdisplaces coal and this is the reason for the reduction in the

amount of emitted carbon dioxide. The CO2 emission index is0.424 t/MWh.

From Table 13 the accumulated generating capacity of the powerplants is 625,958 MWyr. The table also shows the percentagedistribution of the generating capacity among the power plants.

Case 4. In this energy strategy MESSAGE evaluates the case formarket price of natural gas. Table A1 gives the projected naturalgas price given by the Utility Company (TNB, 2009). Naturally theenergy mix will see a reduction in the natural gas contribution. Forthe 21 year period the accumulated percentage of energy resourcein the fuel mix is as follows; 10.11% (natural gas), 86.73% coal and3.17% (hydropower). Table 11 lists this energy mix. The contribu-tion of coal increases from 4915 MW to 24,056 MW.

The cost of energy expansion is USD7.587B and is 28.66% morethan the reference case (Table 12). Removing subsidy on the priceof natural gas causes high increase in the cost of energy expansion.

The accumulated carbon dioxide emission during the period2009–2030 is 3321.74 Mton CO2 eq. This is 32.51% more than thereference case. Coal replaces the contribution of natural gas. Wetherefore expect an increase in the carbon dioxide emission. Thecarbon dioxide emission index is 0.559 t/MWh and this is thehighest of all the cases.

Table 13 gives the accumulated generating capacity which is678,330 MWyr. Table 13 also shows the contribution of the old andnew power plants to the generating capacity.

Case 5. In this energy strategy we allow the price of natural gas tochange according to the price regulated by the government and isgiven in Table A2 (EPU, 2009). Natural gas and coal dominates theenergy mix. As shown in Table 11 the accumulated percentage ofenergy resource in the fuel mix is 49.98% (natural gas), 47.03%(coal) and 2.98% (hydropower). The distribution of the energy mixis the same as the reference case. The contribution of coalincreases from 4915 MW in 2009 to 13,938 MW in 2030.

As shown in Table 12, the cost of energy expansion for the 21year period is USD5.918B. This is 0.36% more than the referencecase. The small variation in the price of natural gas is the reasonfor the slight increase from the reference case. The released carbondioxide throughout the 21 year period is 2506.77 Mton CO2 eq.and this is the same as the reference case (Table 12). The CO2

emission index is 0.460 t/MWh.The accumulated generating capacity of all the power plants is

621,692 MWyr and is given in Table 13. The percentage distribu-tion of the generating capacity of the available and new powerplants is also given in Table 13.

Table 10Limits, bounds and constraints of new technologies (TNB, 2009).

Technology Case Limits/bounds/constraints

New OCGT Reference No capacity limitNew CCGT Reference No capacity limitNew coal Reference Addition capacity in 2010 of 1400 MW with

maximum limit 20,000 MW

New hydro-storage

Reference Addition capacity2015�584 MW2020�1016 MW2030�1600 MW

New RE Case 2 Addition capacity2009–50 MW2015–975 MW2020–2065 MW2025–2809 MW2030–3484 MW

New nuclear Case 1 Addition capacity of 2000 MW in 2021

Sarawakimport

Case 3 Addition capacity2014–805 MW2016–1610 MW2018–2415 MW2019–3220 MW2021–4024 MW2023–4829 MW2025–5634 MW2027–6439 MW2029–7244 MW2031–8049 MW

Table 11Model outcome of the accumulated energy mix for the various scenarios.

Classifications Scenarios Gas Coal Uranium Oil Hydro Renewable Import

Percentage

Reference Business as usual 49.98 47.03 0 0 2.98 0 0Case 1 Nuclear energy 49.99 42.96 4.06 0 2.98 0 0Case 2 Renewable energy 49.78 45.13 0 0 2.98 2.11 0Case 3 Import from Sarawak 49.57 42.11 0 0 2.98 0 5.34Case 4 Market price of natural gas 10.11 86.73 0 0 3.17 0 0Case 5 Increasing cost of natural gas 49.98 47.03 0 0 2.98 0 0Case 6 Increasing cost of coal 49.98 47.03 0 0 2.98 0 0Case 7 Energy efficiency program 51.74 45.16 0 0 3.10 0 0Case 8 All strategy with market price of natural gas 8.90 72.32 4.06 0 2.98 2.27 9.46Case 9 All strategy with increasing cost of fossil fuel 49.31 28.37 4.06 0 2.98 4.45 10.82Case 10 Strategy without nuclear with market price of natural gas 8.89 76.01 0 0 2.98 2.44 9.68Case 11 Strategy without nuclear with increasing cost of fossil fuel 49.49 30.80 0 0 2.98 4.99 11.74






Case 6. For this case we consider the market price of coal. Table A3gives the projected market price of coal given by the government(EPU, 2009). The accumulated percentage of energy resource inthe fuel mix is the same as the reference case. As given in Table 11the percentage is as follows; 49.98% for natural gas, 47.03% for coaland 2.98% for hydropower. The distribution remains the same asthe reference case since the increase in coal price is small aboutUSD4.12/GJ in 2009 to USD5.76/GJ in 2030.

The cost of energy expansion for the 21 year period isUSD6.285B (Table 12). This is higher than the reference case by6.58%. The increase in the price of coal is the reason for theincrease in the cost of the energy expansion.

The amount of carbon dioxide emitted, CO2 emission index andgenerating capacity are the same as the reference case.

Case 7. This is the same as the reference case but with considera-tion of energy efficiency. Table A4 (TNB, 2009) gives the revisedenergy demand to incorporate energy efficiency. The accumulatedpercentage of energy resources in the fuel mix as given in Table 11is 51.74% for natural gas, 45.16% for coal and 3.10% for hydropower.

As shown in Table 12, the cost of energy expansion isUSD5.638B which is less by 4.39% from the reference case.

The accumulated carbon dioxide released from 2009 to 2030 is2377.01 Mton CO2 eq. and is reduced by 5.18% from the referencecase (Table 12). The CO2 emission index is 0.451 t/MWh.

The total generating capacity of all the power plants is601,124 MWyr much less than the reference case. The distributionof this capacity among the available and new power plants is givenin Table 13.

Case 8. This is the case of including all energy resources and usingmarket price of natural gas. The accumulated percentage of energyresources in the fuel mix is 8.90% (natural gas), 72.32% (coal),4.06% (nuclear), 2.98% (hydropower), 2.27% (renewable) and 9.46%(imported hydropower). Table 11 gives this energy mix.

By the year 2020 natural gas contributes very little to theenergy mix because of the withdrawal of subsidy by 2012. Coaldominates the energy mix and increase from 4915 MW in 2009 to17,313 MW in2030.

The cost of energy expansion is USD7.387B which is 25.26%higher than the reference case (Table 12). The increase is due tothe use of market price for natural gas.

The accumulated carbon dioxide released throughout the 21year period is 2769.90 Mton CO2 eq. This is 10.50% more than thereference case (Table 12). The CO2 emission index is 0.460 t/MWhand is the same as the reference case. The increase in cost andreleased carbon dioxide gives the same emission index as thereference case.

Table 13 gives the total generating capacity produces by allavailable and new power plants and is 687,857 MWyr.

Table 12Cost of energy expansion, accumulated amount of carbon dioxide released and CO2 emission index for the period 2009–2030.

Classifications Scenarios Total cost of systemexpansion (USD billion)

Percentage differencefrom Reference (%)

Total CO2

emission(Mton)

Percentage differencefrom Reference (%)

CO2 emissionindex (ton/MWh)

Reference Business as usual 5.897 – 2506.77 – 0.460Case 1 Nuclear energy 5.990 1.59 2356.37 �6.00 0.432Case 2 Renewable energy 5.820 �1.31 2436.43 �2.81 0.449Case 3 Import from Sarawak 5.757 �2.38 2324.96 �7.25 0.424Case 4 Market price of natural gas 7.587 28.66 3321.74 32.51 0.559Case 5 Increasing cost of natural gas 5.918 0.36 2506.77 0.00 0.460Case 6 Increasing cost of coal 6.285 6.58 2506.77 0.00 0.460Case 7 Energy efficiency program 5.638 �4.39 2377.01 �5.18 0.451Case 8 All strategy with market price of

natural gas7.387 25.26 2769.90 10.50 0.460

Case 9 All strategy with increasing cost offossil fuel

6.090 3.27 1825.96 �27.16 0.329

Case 10 Strategy without nuclear withmarket price of natural gas

7.296 23.72 2905.64 15.91 0.484

Case 11 Strategy without nuclear withincreasing cost of fossil fuel

5.988 1.53 1911.88 �23.73 0.350

Table 13Accumulated energy capacity distributions of power plants.

Classifications Total expansion energy of electricitysystem in Peninsular Malaysia (MWyr)

Percentage contribution of power plant to capacity

CCGT Coal Hydro Others CCGT Coal Imported hydro (%) Nuclear (%) Renewable (%)

Existing (%) New (%)

Reference 621,692 17.40 24.86 6.76 5.76 31.38 13.84Case 1 622,542 17.37 24.82 6.75 5.75 30.96 11.12 3.21Case 2 618,916 17.47 24.97 6.79 5.78 27.44 12.41 5.14Case 3 625,958 17.28 24.69 6.72 5.72 24.50 9.91 11.19Case 4 678,330 15.94 22.78 6.20 5.88 3.82 45.38Case 5 621,692 17.40 24.86 6.76 5.76 31.38 13.84Case 6 621,692 17.40 24.86 6.76 5.76 31.38 13.84Case 7 601,124 17.99 25.71 6.99 5.95 31.32 12.04Case 8 687,857 15.72 22.47 6.11 5.20 2.40 30.39 10.18 2.91 4.62Case 9 634,018 17.06 24.37 6.63 5.65 22.44 4.64 11.04 3.15 5.02Case 10 685,884 15.77 22.53 6.13 5.22 2.41 33.10 10.21 4.64Case 11 624,366 17.32 24.75 6.73 5.73 24.44 4.71 11.22 5.09






Case 9. This is also a case of including all energy resources usingprice increase of natural gas and coal regulated by the govern-ment. Fig. 4 shows the variation of the energy mix from 2009until 2030.

According to Table 11, the accumulated percentage of energyresource in the fuel mix for the 21 year period is 49.31% (naturalgas), 28.37% (coal), 4.06% (nuclear), 2.98% (hydropower), 4.45%(renewable) and 10.82% (imported hydropower). Fig. 4 shows thatafter 2020 nuclear, renewable and imported hydropower willdisplace coal.

The cost of energy expansion for the 21 year period is USD6.09B(Table 12). This is higher than reference by 3.27%.

The accumulated amount of carbon dioxide emission duringthe 21 year period is 1825.96 Mton CO2 eq. (Table 12). There is areduction from the reference case by as much as 27.16%. The CO2

emission index is 0.329 t/MWh. Comparing to the other cases thisis the best carbon footprint strategy. As shown in Fig. 5, after 2020there is a reduction in the amount of carbon dioxide emission dueto the introduction of nuclear power. After 2024 the combinationof nuclear energy, renewable and imported hydropower causesfurther reduction in the emission of the carbon dioxide.

As given in Table 13, the accumulated generating capacity ofavailable and new power plants is 634,018 MWyr. Table 13 showshow this generating capacity is divided among the power plants.

Case 10. This case considers all energy strategies with the price ofnatural gas determined by market forces. The removal of naturalgas subsidy causes MESSAGE to choose all fuel mix with theexception of nuclear, in order to produce optimum outcome. Theoptimization is in term of lowest expansion cost and minimum

carbon dioxide emission. The accumulated percentage of energyresources in the fuel mix for the 21 year period is 8.89% (naturalgas), 76.01% (coal), 2.98% (hydro), 2.44% (renewable) and 9.68%(imported hydropower). Coal dominates the energy mix. Thecontribution of natural gas levels off from 2009 until 2011. From2012 onwards it decreases abruptly. After 2020 the contribution ofnatural gas in the energy mix is zero.

The energy expansion cost from 2009 until 2030 is USD7.296B(Table 12). This is higher than the reference case by 23.72%.

As shown in Table 12, the accumulated amount of carbondioxide emission during 2009–2030 is 2905.64 Mton CO2 eq. Thisis higher by 15.91% from the reference case. The CO2 emissionindex is 0.484 t/MWh.

Table 13 gives the accumulated generating capacity from 2009to 2030 of 685,884 MWyr. The table also shows the distribution ofthe generating capacity among the available and new powerplants.

Case 11. This is an energy scenario chosen by MESSAGE toproduce optimization in terms of cost and minimum emission ofcarbon dioxide. The constraints are the price of natural gas andcoal. The government determines the variation in the price of thefossil fuel.

Table 11 gives the accumulated percentage of energy resourcesin the fuel mix produced by MESSAGE for the period 2009–2030.These are 49.49%, 30.80%, 2.98%, 4.99% and 11.74% for natural gas,coal, hydropower, renewable energy and imported hydropowerrespectively. To optimize the cost MESSAGE does not choosenuclear power.

As shown in Table 12 the cost of the energy expansion for the21 year period is USD5.988B. This is only 1.53% more than thereference case.

The carbon dioxide emitted for the same period is given inTable 12. The accumulated amount is 1911.88 Mton CO2 eq. Thisamount is less than the reference case by 23.73%. As shown inTable 12 the CO2 emission index is 0.350 t/MWh.

Table 13 gives the accumulated generating capacity for theperiod 2009–2030. The capacity generated is 624,366 MWyr. Thisis shared among the available and new power plants and thefraction is given in Table 13.

7. Conclusions

Of the twelve cases that were analyzed, Case 9 gives the bestenergy strategy with the following accumulated energy mix –

49.31% (natural gas), 28.37% (coal), 4.06% (nuclear), 2.98% (hydro-power), 4.45% (renewable), and 10.82% (imported hydropowerfrom Sarawak). All new energy strategies proposed by thegovernment are incorporated in this case. The expansion ofthe electricity system for Peninsular Malaysia for the period2009–2030 produces accumulated generating capacity of634,018 MWyr. The total cost of this expansion is USD6.090B.This corresponds to an increase of 3.27% compared to thereference case. For the same period the accumulated amount ofcarbon dioxide emission is 1825.96 Mton CO2 eq. This is less thanthe reference case by 27.16%. The CO2 emission index is 0.329t/MWh.

The next optimum energy strategy is Case 11. The accumulatedenergy mix consists of 49.49% natural gas, 30.80% coal, 2.98%hydropower, 4.99% renewable and 11.74% imported hydropower.Since nuclear power is not included in the expansion the cost isless than Case 9. The total cost is USD5.988B. However, thisis 1.53% more than the reference case. The accumulated amountof released carbon dioxide over the 21 year period is

Fig. 4. Variation of fuel mix of electricity generation from 2009 to 2030 for Case 9.

Fig. 5. Amount of carbon dioxide released from 2009 to 2030 for Case 9.






1911.88 Mton CO2 eq. which is higher than Case 9. This amount isstill less than the reference by 23.73%. For the same period theaccumulated power capacity is 624,366 MWyr.

To moderate the impact of future price increase of fossil fuel,Malaysia should incorporate other resources in the energy mix.This is even so because by 2019 Malaysia will be a net importer offossil fuel. Energy security of Malaysia should not be jeopardizedas this can cause setback in Malaysia's effort to become adeveloped nation by the year 2020. The reference case withbusiness as usual based on energy mix of 2009 results in lessexpansion cost compared to Case 9 or Case 11. But it relies highlyon fossil fuel. Also, the accumulated amount of released carbondioxide is higher and it is unsure whether Malaysia can addressthe carbon footprint by 2020.

Strategies 4, 8 and 10 produce increased energy expansion costby as much as 28.66%, 25.26% and 23.72% respectively compared tothe reference case. In these cases the scenario is to use the marketprice of natural gas and this is the reason for the increase in theircost of expansion. The lifting of subsidy on natural gas by thegovernment is therefore bad for the energy industry and willresult in inflation. Because of the increase in the price of naturalgas there is increase dependent on coal. As a consequence thereleased carbon dioxide increases. In Cases 4, 8 and 10 the increasein released carbon dioxide compared to the reference case is32.51%, 10.50% and 15.91% respectively.

New energy strategies such as import of hydropower fromSarawak and renewable energy can help reduce carbon dioxideemission. However, constraints on capacity and cost limit theirexpansion.

Acknowledgment

This work is an independent initiative and forms part of anassignment for the degree of M.Sc. (Energy Technology), UniversitiKebangsaan Malaysia. It does not represent the views of theGovernment of Malaysia. We would like to acknowledge withthanks the use of public data from Tenaga National Berhad, PusatTenaga Malaysia (now known as Perbadanan Teknologi HijauMalaysia), Suruhanjaya Tenaga and Economic Planning Unit. Fairuzwould like to thank the Malaysian Nuclear Agency for theopportunity to pursue a higher degree.

Appendix A

See Tables A1–A4.

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Table A1Projected natural gas price by the utility company (TNB, 2009).

Year US$'00/kWyr Year US$'00/kWyr

2009 91.38 2020 376.232010 101.47 2021 397.292011 111.97 2022 418.342012 223.34 2023 439.392013 233.46 2024 460.442014 242.95 2025 481.502015 251.84 2026 502.552016 292.02 2027 523.602017 313.08 2028 544.652018 334.13 2029 565.702019 355.18 2030 586.76

Table A2Projected natural gas price by the government (EPU, 2009).


2009 91.38 2020 90.002010 91.50 2021 87.102011 91.59 2022 87.782012 91.02 2023 88.592013 93.00 2024 90.452014 94.14 2025 91.832015 94.14 2026 93.692016 94.83 2027 95.422017 93.93 2028 96.322018 92.88 2029 97.012019 91.83 2030 97.82

Table A3Projected coal price by the government (EPU, 2009).


2009 120.46 2020 145.572010 122.74 2021 147.862011 125.03 2022 150.142012 127.31 2023 152.422013 129.59 2024 154.712014 131.88 2025 156.992015 134.16 2026 159.272016 136.44 2027 161.562017 138.73 2028 163.842018 141.01 2029 166.122019 143.29 2030 168.41

Table A4Power demand projection under energy efficiency program in Peninsular Malaysia(TNB, 2009).

Year Power demand for reference case(MW)

Power demand for Case 7(MW)

2009 14,577 14,577.02010 15,131 15,131.02011 15,674 15,674.02012 16,228 15,563.02013 16,760 16,073.02014 17,271 16,563.02015 17,799 17,069.02016 18,352 17,600.02017 18,895 18,120.02018 19,467 18,669.02019 20,057 19,235.02020 20,669 19,822.02021 21,308 20,434.02022 21,741 20,850.02023 21,911 21,013.02024 22,452 21,531.02025 22,967 22,025.02026 23,449 22,488.02027 23,893 22,913.02028 24,333 23,335.02029 24,771 23,755.02030 25,193 24,160.0



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