Fig. 4.6.2-1 Login Menu of Geothermal Resource Databese

4-108

Fig. 4.6.2-1 Login Menu of Geothermal Resource Databese

Fig. 4.6.2-2 Main Menu of Geothermal Resource Databese

4-109

Fig. 4.6.2-3 Window for Geophysics of Geothermal Resource Databese

Fig. 4.6.2-4 Window for Geology of Geothermal Resource Databese

4-110

Fig. 4.6.2-5 Window for Geochemistry of Geothermal Resource Databese

Fig. 4.6.2-6 Window for Drilling Information of Geothermal Resource Databese

4-111

Fig. 4.6.2-7 Added Function by JICA Team for Drilling Information

Fig. 4.6.2-8 Added Function by JICA Team for Geothermal Resource Evaluation

4-112

Table. 4.7.1-1 Estimate of Geothermal Resource Potential by Stored Heat Method with Monte Carlo analysis

Min. Most Likely Max. Min. Most Likely Max. Min. Most Likely Max. Min. Most Likely Max. Min. Most Likely Max. Min. Most Likely Max.

Aceh 1 IBOIH - JABOI 3.4 5.1 6.8 180 250 290 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 10-20 PossibleAceh 2 LHO PRIA LAOTAceh 3 SEULAWAH AGAM 118 177 236 180 250 280 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 560-1,380 PossibleAceh 4 G. GEUREUDONGAceh 5 G. KEMBAR

SumUta 6 G. SINABUNGSumUta 7 LAU DEBUK-DEBUK / SIBAYAK InstalledSumUta 8 SARULA Ready to developSumUta 9 SIBUAL BUALI 7.1 10.65 14.2 220 270 310 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 60-115 ProvenSumUta 10 S. MERAPI - SAMPURAGA 89 133.5 178 190 250 290 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 500-1,120 PossibleSumUta 11 PUSUK BUKIT - DANAU TOBASumUta 12 SIMBOLON - SAMOSIR

41 61.5 82 180 240 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 160-420 Possible39.3 58.95 78.6 180 240 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 160-400 Hypothesis (Schl. ?)

SumBar 14 G. TALANG 3.4 5.1 6.8 180 250 290 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 15-40 Possible2 3 4 210 250 290 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 10-25 Proven

2.5 3.75 5 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 15-30 PossibleJambi 16 SUNGAI TENANG 33.8 77.1 138Jambi 17 SUNGAI PENUH 69 103.5 138 200 250 290 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 420-900 PossibleJambi 18 SUNGAI BETUNGJambi 19 AIR DIKITJambi 20 G. KACA

Bengkulu 21 B. GEDUNG HULU LAIS 128 192 256 180 250 290 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 640-1,580 PossibleBengkulu 22 TAMBANG SAWAH 60.6 90.9 121.2 210 230 250 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 300-560 PossibleBengkulu 23 BUKIT DAUN 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 180SumSel 24 MARGA BAYUR 21 31.5 42 180 230 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 80-200 PossibleSumSel 25 LUMUT BALAI 70 105 140 230 270 300 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 600-1,140 PossibleSumSel 26 RANTAU DADAP - SEGAMIT

Lampung 27 ULUBELU 50 75 100 200 270 330 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 380-860 PossibleLampung 28 SUOH ANTATAI 77.6 116.4 155.2 230 270 300 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 680-1,280 PossibleLampung 29 G. SEKINCAU 37.3 55.95 74.6 220 260 300 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 280-540 PossibleLampung 30 RAJABASA 20.1 30.15 40.2 200 250 280 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 120-250 PossibleLampung 31 WAI RATAI 18.8 28.2 37.6 220 250 290 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 135-260 PossibleJavaBar 32 KAMOJANG InstralledJavaBar 33 G. SALAK InstralledJavaBar 34 DARAJAT InstralledJavaBar 35 CISOLOK - CISUKARAME 50.4 75.6 100.8 180 250 280 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 240-580 PossibleJavaBar 36 G. PATUHA Ready to developJavaBar 37 G. WAYANG - WINDU InstralledJavaBar 38 G. KARAHA Ready to developJavaBar 39 G. TELAGABODAS Ready to developJavaBar 40 TANGKUBANPERAHU 3.4 5.1 6.8 180 230 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 10-30 PossibleBanten 41 BATUKUWUNGBanten 42 CITAMAN - G. KARANG 4 6 8 180 230 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 15-35 PossibleBanten 43 G. ENDUT

JavaTen 44 DIENG InstralledJavaTen 45 MANGUNANJavaTen 46 TELOMOYO 15.1 22.65 30.2 190 230 250 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 60-125JavaTen 47 UNGARAN 24.5 36.75 49 180 250 320 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 140-355 PossibleJavaTen 48 G. SLAMETJavaTim 49 G. ARJUNO - WELIRANGJavaTim 50 WILIS / NGEBEL 20.8 31.2 41.6 190 250 300 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 120-280 PossibleJavaTim 51 IJEN 21.2 31.8 42.4 180 230 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 80-200 Possible

Bali 52 BEDUGUL 51.1 76.65 102.2 250 285 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 460-820 ProvenNTB 53 HU'U DAHA 30.4 45.6 60.8 180 230 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 115-290 PossibleNTT 54 WAI SANO 9.1 13.65 18.2 200 250 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 50-105 PossibleNTT 55 ULUMBU 17 25.5 34 220 250 300 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 125-250 ProvenNTT 56 BENA - MATALOKO 3 4.5 6 190 230 300 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 15-35 ProvenNTT 57 SOKORIA - MUTUBUSA 16.4 24.6 32.8 180 250 320 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 90-235 PossibleNTT 58 OKA - LARANTUKA 23.9 35.85 47.8 180 230 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 90-230 PossibleNTT 59 ILI LABALEKENNTT 60 ATADEI 14.9 22.35 29.8 180 230 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 55-140 Possible

SulUta 61 LAHENDONG InstralledSulUta 62 KOTAMOBAGU 30 45 60 180 250 300 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 155-390 PossibleSulUta 63 TOMPASO 39.9 59.85 79.8 200 250 320 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 260-600 PossibleSulTen 64 BORA 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180SulTen 65 MERANA 63.3 94.95 126.6 180 230 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 240-600 PossibleSulSel 66 BITUANGSul SE 67 LAINEAMalUta 68 TONGA WAYANAMaluku 69 TULEHU 4.4 6.6 8.8 180 230 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 15-40 PossibleMalUta 70 JAILOLO 44.3 66.45 88.6 190 240 280 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 220-500 Hypothesis SumUta 71 SIPAHOLON-TARUTUNG 14.2 21.3 28.4 180 230 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 55-135 PossibleJavaTim 72 Iyang Agropuro

Golontaro 73 SUWAWA-GOLONTALO 33.9 50.85 67.8 180 230 270 2,400 2450 2600 5 10 20 0.8 0.9 0.95 11 12 13 2.5*Porosity 30 90 180 130-325 Possible

MUARALABUH

LEMPUR / KERINCI

SumBar 13

Jambi 15

Rock Porosity (%)Names of the 70 fields in thisSurveyNo Temperature(oC)Region Rock Density (kg/m3) Rock Specific heat (kJ/kg oC)Reservoir Volume ( x 10 9 m3) Remarks

Conversion Efficiency (%) AbandonmentTemperature (oC)

Range of ResourcePotential (MWe)Plant Life (year) Load Factor

(%)Recovey Factor

(%)

4-113

Table. 4.7.2-1 Reservoir Properties and Single Well Productivity

No. Class

Feed Zone ( m )

ProductionCasing ( m )

Reservoir Press.(kg/cm2 Abs)

ReservoitTemp. (℃）

Permeability-ThicknessProducts(kh:darcy-m)

WellheadPress.(ata)

SteamFlow Rate(t/h)

WaterFlow Rate(t/h)

P1-T1 1000 700 70 210 5 4 25 1532 P1-T2 1000 700 230 5 4 48 2133 P1-T3 1000 700 250 5 8 49 2264 P1-T4 1000 700 270 5 8 71 2405 P2-T1 1500 1000 100 210 4 4 14 866 P2-T2 1500 1000 230 4 4 37 1647 P2-T3 1500 1000 250 4 8 41 1868 P2-T4 1500 1000 270 4 8 65 2249 P2-T5 1500 1000 290 4 12 75 227

10 P2-T6 1500 1000 300 4 12 86 22511 P3-T1 2000 1500 150 210 3 4 16 9712 P3-T2 2000 1500 230 3 4 37 16613 P3-T3 2000 1500 250 3 8 42 19114 P3-T4 2000 1500 270 3 8 70 24015 P3-T5 2000 1500 290 3 12 86 26216 P3-T6 2000 1500 310 3 12 114 26617 P4-T1 2500 2000 200 210 2 4 15 9218 P4-T2 2500 2000 230 2 4 34 15319 P4-T3 2500 2000 250 2 8 39 17620 P4-T4 2500 2000 270 2 8 65 22221 P4-T5 2500 2000 290 2 12 80 24722 P4-T6 2500 2000 310 2 12 113 26723 P5-T1 3000 2500 250 210 1 4 22 13524 P5-T2 3000 2500 230 1 4 39 17225 P5-T3 3000 2500 250 1 8 42 19426 P5-T4 3000 2500 270 1 8 66 22627 P5-T5 3000 2500 290 1 12 80 24728 P5-T6 3000 2500 310 1 12 112 265

Total FlowRate(t/h)

Enthalpy(kcal/kg)

TurbineInlet Press.(ata)

TurbineInlet Steam(t/h)

reinjectionWater (t/h)

Power Outputby the PrimarySteam (kW)

Power Output(MW)

178 215 2 32 150 3000 3261 237 2 58 200 5500 6275 259 6 55 220 7300 7311 283 6 77 230 10100 10100 215 2 18 80 1700 2201 237 2 45 160 4200 4227 259 6 45 180 6000 6289 283 6 71 220 9400 9302 308 10 79 220 11800 12311 321 10 90 220 13400 13113 216 2 20 90 1900 2203 237 2 45 160 4300 4233 259 6 47 190 6200 6310 283 6 76 230 10100 10348 307 10 90 260 13500 14380 333 10 119 260 17800 18107 216 2 19 90 1800 2187 238 2 42 150 4000 4215 260 6 43 170 5700 6287 282 6 70 220 9300 9327 306 10 85 240 12600 13380 332 10 118 260 17700 18157 217 2 29 130 2700 3211 238 2 47 160 4500 5236 260 6 47 190 6300 6292 283 6 71 220 9500 10327 306 10 84 240 12600 13377 331 10 117 260 17400 17

4-114

Table. 4.7.2-2 General Estimate of The Initial Capital Investiment Per KW of Each Geothermal Field.

Demand

Surface Geotherm Measured T/L D/L (MW). Speculative Hypothesis possible Probable Proven

Aceh 1 IBOIH - JABOI 100 170-290 X 10 15 15 10

Aceh 2 LHO PRIA LAOT 101 170-220 X 10

Aceh 3 SEULAWAH AGAM 95 180-300 X 3,000 900 900 900

Aceh 4 G. GEUREUDONG 69 X 3,000

Aceh 5 G. KEMBAR 89 >190 X 3,000

SumUta 6 G. SINABUNG X 3,000

SumUta 7 LAU DEBUK-DEBUK / SIBAYAK 116 302 X 3,000 70 131 39 170 170

SumUta 8 SARULA 101 X 3,000 100 147 133 280 280

SumUta 9 SIBUAL BUALI 72 X 3,000 80 80 80

SumUta 10 S. MERAPI - SAMPURAGA 99 <290 X 3,000 700 700 700

SumUta 11 PUSUK BUKIT - DANAU TOBA 90 <290 X 3,000

SumUta 12 SIMBOLON - SAMOSIR 43 >170 X 3,000

SumBar 13 MUARALABUH 104 180-270 X 3,000 250 250 250 250

SumBar 14 G. TALANG 98 <290 X 3,000 25 25 25

Jambi 15 LEMPUR / KERINCI 97 210-290 X 3,000 20 15 35 35

Jambi 16 SUNGAI TENANG 96 X 3,000

Jambi 17 SUNGAI PENUH 102 200-250 X 3,000 600 600 600

Jambi 18 SUNGAI BETUNG 30 X 3,000

Jambi 19 AIR DIKIT 98 X 3,000

Jambi 20 G. KACA 41 X 3,000

Bengkulu 21 B. GEDUNG HULU LAIS 95 180-290 X 3,000 1,000 1,000 1000

Bengkulu 22 TAMBANG SAWAH 95 >230 X 3,000 400 400 400

Bengkulu 23 BUKIT DAUN 95 X 3,000

SumSel 24 MARGA BAYUR 96 180-250 X 3,000 130 130 130

SumSel 25 LUMUT BALAI 98 X 3,000 820 820 820

SumSel 26 RANTAU DADAP - SEGAMIT 96 X 3,000

Lampung 27 ULUBELU 99 X 3,000 580 580 580

Lampung 28 SUOH ANTATAI 99 230-300 X 3,000 920 920 920

Lampung 29 G. SEKINCAU 98 260-300 X 3,000 380 380 380

Lampung 30 RAJABASA 99 200-280 X 3,000 170 170 170

Lampung 31 WAI RATAI 92 220-290 X 3,000 180 180 180

JavaBar 32 KAMOJANG 96 252 X 20,000 73 227 300 300

JavaBar 33 G. SALAK 280 X 20,000 115 485 600 600

JavaBar 34 DARAJAT 77 245 X 20,000 362 362 362

JavaBar 35 CISOLOK - CISUKARAME 98 >250 X 20,000 400 400 400

JavaBar 36 G. PATUHA 89 245 X 20,000 65 247 170 417 417

JavaBar 37 G. WAYANG - WINDU 50 270 X 20,000 75 135 250 385 385

JavaBar 38 G. KARAHA 95 X 20,000 50 70 100 30 200 200

JavaBar 39 G. TELAGABODAS 92 X 20,000 75 120 80 200 200

JavaBar 40 TANGKUBANPERAHU 96 >170 X 20,000 20 20 20

Potential(MW)

Names of the 70 fields in thisSurveyNo

Temperature(oC) Grid. ResourcesRegion

ReservesPower

Plant (MW)

Banten 41 BATUKUWUNG 52 X 20,000

Banten 42 CITAMAN - G. KARANG 94 >180 X 20,000 50 25 25 25

Banten 43 G. ENDUT 84 X 20,000

JavaTen 44 DIENG 94 368 X 20,000 200 185 115 280 580 580

JavaTen 45 MANGUNAN 46 X 20,000

JavaTen 46 TELOMOYO >190 X 20,000 90 90 90

JavaTen 47 UNGARAN 86 180-320 X 20,000 230 230 230

JavaTen 48 G. SLAMET 51 X 20,000

JavaTim 49 G. ARJUNO - WELIRANG 70 X 20,000

JavaTim 50 WILIS / NGEBEL 93 190-250 20,000 180 180 180

JavaTim 51 IJEN 57 20,000 130 130 130

Bali 52 BEDUGUL 32 285 X 20,000 75 245 30 275 275

NTB 53 HU'U DAHA 86 X 10 190 190 10

NTT 54 WAI SANO 92 >250 X 30 70 70 30

NTT 55 ULUMBU 96 240 X 30 175 175 30

NTT 56 BENA - MATALOKO 95 270-300 X 30 20 20 20

NTT 57 SOKORIA - MUTUBUSA 97 180-320 X 30 150 150 30

NTT 58 OKA - LARANTUKA 90 X 30 145 145 30

NTT 59 ILI LABALEKEN X 30

NTT 60 ATADEI 97 X 30 90 90 30

SulUta 61 LAHENDONG 99 356 X 200 125 95 80 175 175

SulUta 62 KOTAMOBAGU 98 <320 X 200 260 260 200

SulUta 63 TOMPASO 98 >250 X 200 400 400 200

SulTen 64 BORA 81 X 500

SulTen 65 MERANA 90 X 500 380 380 380

SulSel 66 BITUANG 98 X 500

Sul SE 67 LAINEA 85 X 500

MalUta 68 TONGA WAYANA 60 X 10

Maluku 69 TULEHU 92 >230 X 30 25 25 25

MalUta 70 JAILOLO 97 X 20 320

SumUta 71 SIPAHOLON-TARUTUNG 47 >170 X 3,000 85 85 85

JavaTim 72 Iyang Agropuro 65

Golontaro 73 SUWAWA-GOLONTALO 83 >130 X 200 210 210 200

1500 4 160 1000 200 70% 9 7 22.6 30.0 53 902

2000 10 260 1000 200 80% 73 95 265.1 696.0 961 457

1500 4 160 1000 200 70% 33 27 84.2 108.0 192 935

1500 6 190 1000 200 70% 55 52 148.0 276.0 424 643

1500 6 190 1000 200 70% 43 41 116.1 216.0 332 645

1500 4 160 1000 200 70% 47 38 119.4 156.0 275 918

2500 9 220 1500 200 80% 39 43 178.2 330.0 508 648

1500 4 160 1000 200 70% 4 4 11.0 12.0 23 1,100

1500 6 180 500 200 70% 8 7 17.1 36.0 53 568

1000 7 220 500 200 70% 7 7 11.6 36.0 48 385

1000 6 200 500 200 70% 5 5 8.3 24.0 32 413

1500 6 190 500 200 70% 8 7 17.1 36.0 53 568

1500 4 160 500 200 70% 11 10 23.7 36.0 60 788

1500 4 160 1000 200 70% 11 10 29.2 36.0 65 972

2000 10 230 1000 200 80% 22 26 77.0 210.0 287 440

2000 6 190 1000 200 70% 48 45 155.1 240.0 395 776

1500 6 180 1000 200 70% 48 43 126.5 240.0 367 633

1500 4 160 1000 200 70% 136 109 344.3 456.0 800 906

1500 4 160 1000 200 70% 9 7 22.6 30.0 53 902

1500 4 180 1000 200 70% 31 27 80.9 102.0 183 951

1500 4 160 1000 200 70% 72 58 182.6 240.0 423 913

Depth(m) MW Water Flow (t/h) Depth(m) capacity (t/h) Success Rate Production Reinjection

1500 6 180 1000 200 70% 3 3 8.3 12.0 20 825

1500 6 180 500 200 70% 215 193 460.9 1,080.0 1,541 512

2000 10 230 1000 200 70% 25 28 85.8 204.0 290 505

2000 6 190 1000 200 70% 67 64 217.8 336.0 554 778

2000 10 190 1000 200 70% 12 11 38.5 96.0 135 481

2000 6 190 1000 200 70% 167 159 542.3 840.0 1,382 775

1500 6 180 1000 200 70% 60 54 158.4 300.0 458 634

2000 6 190 1000 200 70% 6 6 19.8 30.0 50 792

1500 6 180 500 200 70% 9 8 19.3 42.0 61 550

1500 6 190 500 200 70% 143 136 310.8 720.0 1,031 518

1500 6 180 1000 200 70% 239 215 630.9 1,200.0 1,831 631

1500 4 160 1000 200 70% 143 115 362.5 480.0 842 906

1500 4 180 1000 200 70% 47 43 124.9 156.0 281 960

1500 9 220 1000 200 70% 131 143 373.5 984.0 1,357 455

1500 9 220 1000 200 70% 93 101 264.6 696.0 961 456

1500 9 220 1000 200 70% 147 161 419.7 1,104.0 1,524 456

1500 9 220 1000 200 70% 61 66 173.3 456.0 629 456

1500 6 180 1000 200 70% 41 36 107.3 204.0 311 631

1500 6 180 1000 200 70% 43 39 113.9 216.0 330 633

1500 6 5 1000 200 80% 63 2 106.2 360.0 466 354

2000 10 230 1000 200 80% 75 87 260.7 720.0 981 435

2000 6 5 1000 200 80% 76 2 169.4 434.4 604 468

1500 6 190 1000 200 70% 96 91 258.5 480.0 739 646

1500 6 5 1000 200 80% 87 3 146.9 500.4 647 352

1500 9 220 1000 200 80% 54 60 155.1 462.0 617 403

1500 9 220 1000 200 80% 28 31 80.3 240.0 320 402

1500 9 220 1000 200 70% 32 35 91.3 240.0 331 457

1500 4 160 1000 200 70% 8 6 19.8 24.0 44 990

Single Well Productivity Single Well Injectivity Required Number of Well Drilling Costs(million US$)

Initial CapitalInvestment

(million US$)

Plant Costs(million US$)

Initial CapitalInvestment for

Drilling (US$/kW)

1,200 2,025

1,200 1,712

1,200 1,705

1,200 1,978

1,200 1,681

1,200 1,975

1,200 1,834

1,200 1,992

1,200 1,750

1,200 1,718

1,200 1,831

1,200 2,106

1,200 2,160

1,200 1,655

1,200 1,656

1,200 1,656

1,200 1,656

1,200 1,831

1,200 1,833

1,200 1,554

1,200 1,635

1,200 1,668

1,200 1,846

1,200 1,552

1,200 1,603

1,200 1,602

1,200 1,657

1,200 2,190

Initial CapitalInvestment

Per kW (US$/kW)

Initial CapitalInvestment for

Plant (US$/kW)

1,200 2,102

1,200 1,657

1,200 2,135

1,200 1,843

1,200 1,845

1,200 2,118

1,200 1,848

1,200 2,300

1,200 1,768

1,200 1,585

1,200 1,613

1,200 1,768

1,200 1,988

1,200 2,172

1,200 1,640

1,200 1,976

1,200 1,833

1,200 2,106

1,200 2,102

1,200 2,151

1,200 2,113

4-115

Table 4.8.1-1 Criteria for Area Classification

Stage of Development

RE: Unexplored or regional reconnaissace only

S1:

Local surface exploration done - this may include geology and geochemistry, butstill lack of sub-surface information (underground structure and resistivitydistribution)

S2:

Detailed surface exploration done - this comprises activities of geology,geochemistry, geophysics (gravity, resistivity and/or other survices) and/ortemperature gradient drilling

F1:

Pre-feasibility studies done - it is confirmed or disproved that a commerciallyexploitable reservoir is likely to exist by deep drilling well(s) and/or somereasonable information.

F2:

Feasibility studies done (complete) - this comprises several well drilling and testingwith sufficient outcome to confirm commercially viable development of somespecific MW

OP: Power plant in operation

4-116

Table 4.8.2-1 Geothermal Resource Areas in Sumatra Island

Min. Most Likely Max. Surface Geotherm Measured

Aceh 1 IBOIH - JABOI 3.4 5.1 6.8 100 170-290

Aceh 2 LHO PRIA LAOT 101 170-220

Aceh 3 SEULAWAH AGAM 118 177 236 100 180-300

Aceh 4 G. GEUREUDONG 69

Aceh 5 G. KEMBAR 89 >190

SumUta 6 G. SINABUNG

SumUta 7 LAU DEBUK-DEBUK / SIBAYAK 2 3.975 6.6 116 302

SumUta 8 SARULA 15.1 22.65 30.2 101 310

SumUta 9 SIBUAL BUALI 7.1 10.65 14.2 72 267

SumUta 10 S. MERAPI - SAMPURAGA 89 133.5 178 119 <290

SumUta 11 PUSUK BUKIT - DANAU TOBA 90 <290

SumUta 12 SIMBOLON - SAMOSIR 91 >170

SumUta 71 SIPAHOLON-TARUTUNG 14.2 21.3 28.4 65 >170

SumBar 13 MUARALABUH 80.3 120.45 160.6 106 180-270

SumBar 14 G. TALANG 3.4 5.1 6.8 98 <290

Jambi 15 LEMPUR / KERINCI 4.5 6.75 9 97 210-290

Jambi 16 SUNGAI TENANG 33.8 77.1 138 96

Jambi 17 SUNGAI PENUH 69 103.5 138 102 200-250

Jambi 18 SUNGAI BETUNG 30

Jambi 19 AIR DIKIT 98

Jambi 20 G. KACA 41

Bengkulu 21 B. GEDUNG HULU LAIS 128 192 256 95 180-290

Bengkulu 22 TAMBANG SAWAH 60.6 90.9 121.2 99 >230

Bengkulu 23 BUKIT DAUN 95

SumSel 24 MARGA BAYUR 21 31.5 42 98 180-250

SumSel 25 LUMUT BALAI 70 105 140 98

SumSel 26 RANTAU DADAP - SEGAMIT 96

Lampung 27 ULUBELU 50 75 100 99

Lampung 28 SUOH ANTATAI 77.6 116.4 155.2 99 230-300

Lampung 29 G. SEKINCAU 37.3 55.95 74.6 98 260-300

Lampung 30 RAJABASA 20.1 30.15 40.2 100 200-280

Lampung 31 WAI RATAI 18.8 28.2 37.6 92 220-290

Names of the 70 fields in thisSurveyNo

Temperature(oC)Region

Sub-Total in Sumatra

Reservoir Volume ( x 10 9 m3)

pH Major Anion Cl max(ppm) Spec. Hypo. Possible Probable Proven

2.4-7.5 SO4, HCO3, Cl-SO4 1353 15 S2

6.5 Cl 5312 S1

6.5-7.0 Cl-SO4 2399 900 S2

RE

7.8 Cl-SO4 828 S1

RE

6.7 HCO3 110 70 131 39 OP

3.1-9.3 SO4, HCO3, Cl-HCO3, Cl-SO4 1310 100 147 133 F2

7.5-7.9 HCO3, Cl-HCO 288 80 F1

1.8-7.7 SO4, HCO3, mixed, Cl-HCO3 933 700 S2

2.8-3.7 SO4, Cl-SO4 394 S1

3.4-8.4 SO4, HCO3 479 S1

6.2-7.2 SO4, HCO3, mixed, Cl-HCO3 277 85 S1

2.0-8.5 SO4, HCO3, C 1532 250 250 S2

2.2-8.6 SO4, HCO3 198 25 S2

2.8-7.2 SO4, HCO3 (Cl: well)9

(1440: well) 20 15 F1

8.0 Cl-SO4 392 S1

7.0-8.9 Cl-HCO3 584 600 S2

S1

2.5 SO4 3 S1

S1

2.1-7.2 SO4, HCO3, Cl-SO4, Cl-HCO3, Cl 3155 1,000 S2

6.1-8.9 SO4, HCO3, Cl 3411 400 S2

2.3 SO4 47 S1

1.7-7.6 SO4, HCO3 16 130 S2

2.5 SO4 80 820 S2

S1

2-neutral 900 580 F1

7.0-7.2 Cl-SO4, Cl 1326 920 S2

7.5-7.6 HCO3, Cl 1370 380 S2

6.0-6.5 HCO3, Cl-HCO3, Cl 6830 170 S2

5.9-7.4 Cl-HCO3, Cl 2589 180 S2

420 7,453 267

Stage ofDeveloment

Potential (MW)Surface Water Type (Hot Spring)

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Table 4.8.2-2 Geothermal Resource Areas in Java-Bali region


JavaBar 32 KAMOJANG 11.2 18.9 28 96 252

JavaBar 33 G. SALAK 22.1 33.15 44.2 280

JavaBar 34 DARAJAT 13.3 19.95 28.6 77 245

JavaBar 35 CISOLOK - CISUKARAME 50.4 75.6 100.8 99 >250

JavaBar 36 G. PATUHA 89 245

JavaBar 37 G. WAYANG - WINDU 25.4 63.675 119 50 270

JavaBar 38 G. KARAHA 79.1 118.65 158.2 95

JavaBar 39 G. TELAGABODAS 92

JavaBar 40 TANGKUBANPERAHU 3.4 5.1 6.8 96 >170

Banten 41 BATUKUWUNG 52

Banten 42 CITAMAN - G. KARANG 4 6 8 94 >180

Banten 43 G. ENDUT 84

JavaTen 44 DIENG 6.5 14.55 25.8 94 368

JavaTen 45 MANGUNAN 46

JavaTen 46 TELOMOYO 15.1 22.65 30.2 37 >190

JavaTen 47 UNGARAN 24.5 36.75 49 86 180-320

JavaTen 48 G. SLAMET 51

JavaTim 49 G. ARJUNO - WELIRANG 70

JavaTim 50 WILIS / NGEBEL 20.8 31.2 41.6 93 190-250

JavaTim 51 IJEN 21.2 31.8 42.4 57

JavaTim 72 Iyang Agropuro 65

Bali 52 BEDUGUL 32 285

Region No Names of the 70 fields in thisSurvey

Reservoir Volume ( x 10 9 m3)

Sub-Total in Java-Bali

Temperature(oC)


2.9-8.2 SO4, HCO3 17 73 227 OP

115 485 OP

3.0-5.0 SO4 14 362 OP

6.8-8.7 SO4, mixed, Cl-SO4, Cl-HCO3 560 400 F1

65 247 170 F2

75 135 250 OP

6.6 SO4 11 50 70 100 30 F2

75 120 80 S2

2.5-7.4 SO4, HCO3, Cl-SO4, Cl-HCO3, Cl 1581 20 S2

S2

(150) 50 25 F1

RE

200 185 115 280 OP

S2

7.6 HCO3 (SO4, mixed: well) 180 90 S2

6.0-8.0 HCO3, Cl-HCO3, Cl 5339 230 S2

7.9 HCO3 26 S2

6.7 HCO3 334 S1

6.6-7.0 Cl (Cl-HCO3: well) 4627 180 S2

6.5-8.3 HCO3 152 130 S2

7.4 HCO3 26 S1

75 245 30 F2

590 2,057 503 1,834

Stage ofDeveloment

Surface Water Type (Hot Spring) Potential (MW)

4-118

Table 4.8.2-3 Geothermal Resource Areas in Sulawesi and East Indonesia


NTB 53 HU'U DAHA 30.4 45.6 60.8 86

NTT 54 WAI SANO 9.1 13.65 18.2 92 >250

NTT 55 ULUMBU 17 25.5 34 96 240

NTT 56 BENA - MATALOKO 3 4.5 6 95 270-300

NTT 57 SOKORIA - MUTUBUSA 16.4 24.6 32.8 97 180-320

NTT 58 OKA - LARANTUKA 23.9 35.85 47.8 90

NTT 59 ILI LABALEKEN

NTT 60 ATADEI 14.9 22.35 29.8 97

SulUta 61 LAHENDONG 9.9 14.85 19.8 99 356

SulUta 62 KOTAMOBAGU 30 45 60 98 <320

SulUta 63 TOMPASO 39.9 59.85 79.8 98 >250

Golontaro 73 SUWAWA-GOLONTALO 33.9 50.85 67.8 94 >130

SulTen 64 BORA 81

SulTen 65 MERANA 63.3 94.95 126.6 90

SulSel 66 BITUANG 98

Sul SE 67 LAINEA 85

MalUta 68 TONGA WAYANA 60

Maluku 69 TULEHU 4.4 6.6 8.8 92 >230

MalUta 70 JAILOLO 44.3 66.45 88.6 97

Region No Names of the 70 fields in thisSurvey

Reservoir Volume ( x 10 9 m3) Temperature(oC)

Sub-Total in Sulawesi and East Indonesia

Grand-Total in Indonesia


2.2-6.7 SO4, HCO3, Cl-SO4 1555 190 S2

5.7-7.1 SO4, HCO3, Cl-HCO3, Cl 20000 70 S2

3.0-4.4 SO4 36 175 F2

2.5-6.4 SO4 18 20 F2

1.9-8.0 SO4, HCO3, Cl-SO4, Cl-HCO3 1560 150 S1

2.6-8.6 SO4, HCO3, Cl-HCO3, Cl-SO4, Cl 4994 145 S1

RE

8.1 HCO3 10 90 F1

8.7 mixed 290 125 95 80 OP

2.0-7.8 SO4, HCO3, mixed, Cl-SO4, Cl-HCO3 869 260 S2

2.2-7.8 SO4, mixed, Cl-SO4 280 400 S2

7.4-7.8 SO4, Cl-SO4 923 210 S2

RE

6.8-8.8 HCO3, mixed, Cl-HCO3, Cl-SO4, Cl 3569 380 S1

RE

RE

S1

6.5-7.7 HCO3, Cl-HCO3, Cl-SO4, Cl 14300 25 S2

7.2-7.8 HCO3, Cl-HCO3, Cl-SO4, Cl 6954 320 S2

445 1,920 95 275

1,455 11,430 598 2,376

Stage ofDeveloment

Surface Water Type (Hot Spring) Potential (MW)

Chapter 5 Electric Power Sector

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Chapter 5 Electric Power Sector

5.1 Outlook of Future Electric Power Supply and Demand for Geothermal Development Plan

5.1.1 Present Situation of Electric Power Supply and Demand

The power demand of Indonesia (sales amount of electric power) in 2004 was 100,097 GWh, and the maximum demand power was 18,896 MW. To meet this demand, the electric power of 120,161GWh was generated by the power plants of 21,882 MW capacities. The breakdown of the power plant capacity is 6,900 MW of steam power plant (31.5%), 6,561 MW of gas combined cycle power plants (30.0%), 3,199 MW of hydro power plants (14.6%), 2,921 MW of diesel power plants (13.4%), 6,900 MW of gas turbine plants (6.8%), and 807 MW1 of geothermal power plants (3.7%) (Fig.5.1.1-1). The electric power sales breaks down as 38,588GWh (38.6%) for households use, 40,324GWh (40.3%) for industrial use, 15,258GWh (15.2%) for commercial use, 1,645GWh (1.6%) for government and municipal offices use, 2,238 GWh (2.2%) for public use, and 2,045 GWh (2.0%) for street light use (Fig. 5.1.1-2).

The national electric power system of Indonesia can be classified into two categories: an interconnected electric power system and isolated electric power system. The Java-Madura-Bali System and Sumatra System have already developed and established an interconnected electric power system through high voltage/super-high voltage power transmission networks. Electric power systems other than these two systems have not developed and are not completely interconnected with each other. These electric power systems consist of sub-systems and individually isolated smaller sub-systems, and there are still many independent/isolated regions. The 15,908MW (72.7%) capacity of power plants concentrate in the Java- Madura -Bali system, and the 3,352MW (15.3%) of capacity concentrates in the Sumatra system. The two systems account for 88% of the whole capacity. (Table 5.1.1-1) In this chapter, the current electric power condition is discussed region by region.

(1) Sumatra Island

(a) Nanggroe Ache Darussalam (NAD) Province

Maximum electric power demand in 2004 was 210 MW, and generated output was 748 GWh. About 50% of this load is supplied by the Kitlur Sumbag Unit through 150 kV power transmission networks, and the rest is supplied from isolated power sources scattered around

1 As of 2007, the capacity of geothermal power plants is 857MW.

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the entire province. Net system energy demand was 708 GWh in 2004, which breaks down as 472 GWh (66.6%) for household use, 83 GWh (11.7%) for commercial use, 49 GWh (6.8%) for industrial use, and 105 GWh (14.7%) for public use. The electrification rate of the province in 2004 reached 56.4%.

(b) North Sumatra Province

Maximum electric power demand in 2004 was 926 MW, and generated output was 4,870 GWh. Almost all (99.1%) of the load is supplied by the Kitlur Sumbag Unit through 150 kV power transmission networks, and the rest is supplied by isolated power sources located in each island, that is, Nias, Tello and Sembilan. Net system energy demand was 4,526 GWh in 2004, which breaks down as 1,951 GWh (43.1%) for household use, 578 GWh (12.7%) for commercial use, 1,652 GWh (36.4%) for industrial use, and 345 GWh (7.6%) for public use. The electrification rate of the province in 2004 reached 67.5%.

(c) West Sumatra Province

Maximum electric power demand in 2004 was 295 MW, and generated output was 1,676 GWh. About 90% of the load is supplied by Kitlur Sumbagsel through 150 kV power transmission networks, and the rest is supplied by isolated power sources located across the entire province. Net system energy demand was 1,467 GWh in 2004, which breaks down as 631 GWh (43.0%) for household use, 132GWh (8.9%) for commercial use, 591GWh (40.2%) for industrial use, and 114 GWh (7.7%) for public use. The electrification rate of the province in 2004 reached 61.1%.

(d) Riau Province

Maximum electric power demand in 2004 was 322 MW, and generated output was 1,654 GWh. About 55% of the load is supplied by the Kitlur Sumbag Unit through 150 kV power transmission networks, and the rest is supplied by isolated power sources located across the entire province. Net system energy demand was 1,428 GWh in 2004, which breaks down as 872 GWh (61.1%) for household use, 313 GWh (21.9%) for commercial use, 139 GWh (9.7%) for industrial use, and 104 GWh (7.3%) for public use. The electrification rate of the province in 2004 reached 38.9%.

(e) Jambi Province

South Sumatra Province, Jambi Province and Bengkulu Province are favorably interconnected through 150 kV power transmission networks. Since these provinces constitute the region of the South Sumatra-Jambi-Bengkulu (S2JB) System, the electric power condition of Jambi Province represents the total electric power condition of S2JB. In 2004, maximum electric power demand in the S2JB district was 472 MW, and generated

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output was 118 GWh, while the electrification rate was 39.8%. About 90% of this load is supplied by the Kitlur Sumbag Unit through 150 kV power transmission networks, and the rest is supplied by isolated power sources located across the entire area of S2JB. Net system energy demand was 471 GWh in 2004, which breaks down as 291 GWh (61.8%) for household use, 77GWh (16.3%) for commercial use, 70 GWh (14.9%) for industrial use, and 33 GWh (7.0%) for public use.

(f) South Sumatra Province

South Sumatra Province, Jambi Province and Bengkulu Province are favorably interconnected through 150 kV power transmission networks and constitute a region of the South Sumatra-Jambi-Bengkulu (S2JB) System. Net system energy demand was 1,448 GWh in 2004, which breaks down as 766 GWh (52.9%) for household use, 192 GWh (13.3%) for commercial use, 381 GWh (26.3%) for industrial use, and 108 GWh (7.5%) for public use.

(g) Bengkulu Province

South Sumatra Province, Jambi Province and Bengkulu Province are favorably interconnected through 150 kV power transmission networks and constitute a region of the South Sumatra-Jambi-Bengkulu (S2JB) System. For this reason, the electric power condition of Bengkulu Province represents the total electric power condition of S2JB. Net system energy demand was 227 GWh in 2004, which breaks down as 163 GWh (71.8%) for household use, 30 GWh (13.2%) for commercial use, 15 GWh (6.5%) for industrial use, and 20 GWh (8.5%) for public use.

(h) Lampung Province

Maximum electric power demand in 2004 was 306 MW, and generated output was 1,370 GWh. About 99% of the load is supplied by Kitlur Sumbagsel through 150 kV power transmission networks, and the rest is supplied by isolated power sources located across the entire province. Net system energy demand was 1,207 GWh in 2004, which breaks down as 719 GWh (59.5%) for household use, 161 GWh (13.3%) for commercial use, 227 GWh (18.8%) for industrial use, and 100GWh (8.2%) for public use. The electrification rate of the province in 2004 reached 37.1%.

(i) Bangka Belitung Islands

Maximum electric power demand in 2004 was 60 MW, and generated output was 273 GWh. The entire load is supplied by isolated power sources located across the entire province. Net system energy demand was 234 GWh in 2004, which breaks down as 173GWh (73.9%) for household use, 25 GWh (10.6%) for commercial use, 23 GWh (9.7%) for industrial use, and 13 GWh (5.6%) for public use. The electrification rate of the province in 2004 reached

5-4

53.1%.

(j) Batam Island

Maximum electric power demand in 2004 was 31.8 MW, and generated output was 838 GWh. The entire load is supplied from the power source of PT. PLN Batam, and interconnected to some areas through 150 kV power transmission networks. On the other hand, concerning the electricity demand for industrial use in the Muka Kuning Industrial Park district, power is supplied by PT Batamindo, which holds own-use generating facilities of a total capacity of 166 MW. Net system energy demand by PT PLN Batam was 662 GWh in 2004, which breaks down as 199 GWh (30.0%) for household use, 317 GWh (47.9%) for commercial use, 110 GWh (16.6%) for industrial use, and 35 GWh (5.3%) for public use. The electrification rate of the district reached 67%.

(2) Java Island and Bali Island

The systems in Java, Madura and Bali Island are already interconnected, and electricity demand for this system is supplied from the power sources of all power plants in JAMALI (abbreviation for Java, Madura and Bali), which had provided 9,263.4 GWh energy in 2004. Details of power consumption on Java Island and Bali Province are described below.

(a) Bali Province

Maximum electric power demand in 2004 was 389 MW. 40% of the load is supplied by the electric power system on Java Island through 150 kV marine cables, and the rest is supplied by the Pesanggarahan Generating Unit (150 MW) and the Giiimanuk Gas Turbine Generating Plant (100 MW). Net system energy demand was 1,896 GWh in 2004, which breaks down as 838 GWh (44.2%) for household use, 879 GWh (46.3%) for commercial use, 76 GWh (4.0%) for industrial use, and 102 GWh (5.3%) for public use. The electrification rate of the province reached 76.6%.

(b) East Java Province

Maximum electric power demand in 2004 was 3,107 MW. Electricity demand in the province is supplied by electric power from the Java-Madura-Bali (JAMALI) Interconnected System, and the main suppliers supply electric power through super-high voltage power transmission networks (500 kV) and high voltage power transmission networks (150 kV and 70 kV). In addition, there is the small-scale Wonorejo-PJB Hydraulic Power Plant that supplies electric power through medium voltage power transmission networks, privately-owned electric power facilities (mainly, diesel and mini-hydraulic power plants) and power plants on hire. Net system energy demand was 16,421 GWh in 2004, which breaks down as 5,887 GWh (35.8%) for household use, 1,717 GWh (10.4%) for

5-5

commercial use, 7,946 GWh (48.3%) for industrial use, and 872 GWh (5.3%) for public use. The electrification rate of the province in 2004 reached 59.1%.

(c) Mid Java Province and Yogyaka Special Province

Maximum electric power demand in 2004 was 2,220 MW. The electric power in the province is mainly supplied by the Tambakbrok Steam Power Plant, Mrica Hydraulic Power Plant and other electric power plants, electric power of which is supplied through 500 kV and 150 kV of the JAMALI interconnected power transmission networks. Net system energy demand was 10,843 GWh in 2004, which breaks down as 5,384 GWh (49.7%) for household use, 1,056 GWh (9.7%) for commercial use, 3,457 GWh (31.9%) for industrial use, and 946 GWh (8.7%) for public use.

(d) West Java Province and Banten Province

Maximum electric power demand in 2004 was 4,682 MW. Electricity demand in the province is supplied by electric power from the Java-Madura-Bali (JAMALI) Interconnected System, and the main suppliers supply electric power through super-high voltage power transmission networks (500 kV) and high voltage power transmission networks (150 kV and 70 kV). In addition, there are small-scale power sources that supply electric power through medium voltage power transmission networks, privately-owned electric power facilities and power plants for hire. Net system energy demand was 27,279 GWh in 2004, which breaks down as 8,402 GWh (29.7%) for household use, 1,721 GWh (6.3%) for commercial use, 16,762 GWh (61.4%) for industrial use, and 694 GWh (2.5%) for public use. The electrification rate of the province in 2004 reached 57.2%.

(e) Jakarta Special Province and Tangerang Province

Maximum electric power demand in 2004 was 3,912 MW. Electricity demand in the province is supplied by electric power from the Java-Madura-Bali (JAMALI) Interconnected System, and the main suppliers supply electric power through super-high voltage power transmission networks (500 kV) and high voltage power transmission networks (150 kV and 70 kV). Net system energy demand was 23,333 GWh in 2004, which breaks down as 7,767 GWh (33.3%) for household use, 6,436 GWh (27.5%) for commercial use, 7,526 GWh (32.3%) for industrial use, and 1,571 GWh (6.7%) for public use. The electrification rate of the province in 2004 reached 81.3%.

(3) Kalimantan Island

(a) East Kalimantan Province

Maximum electric power demand in 2004 was 245 MW, and generated output was 1,420

5-6

GWh. About 80% of the load is supplied by the Mahakam Electric Power System through 150 kV power transmission networks, and the rest is supplied by isolated power sources located across the province. Net system energy demand was 1,241 GWh in 2004, which breaks down as 658 GWh (54.2%) for household use, 260 GWh (21.4%) for commercial use, 184 GWh (15.1%) for industrial use, and 112 GWh (9.2%) for public use. The electrification rate of the province in 2004 reached 49.6%.

(b) Middle Kalimantan Province and South Kalimantan Province

Middle Kalimantan Province and South Kalimantan Province are interconnected through 150 kV power cables, and PT. PLN (Persero) covers these two provinces as one service area called the South/Middle Kalimantan (Wilayah Kalselteng) region. So, the electric power condition of Middle Kalimantan represents the electric power condition of the Kalseiteng (South/Middle Kalimantan) region. Maximum electric power in 2004 was 289 MW, and generated output was 1,552 GWh, while the electrification rate was 52.9%. 80% of the load is supplied by the Balrito-Banua Lima Electric Power System through 150 kV power cables, and the rest is supplied by isolated power sources. Net system energy demand was 1,251 GWh in 2004, which breaks down as 722 GWh (57.7%) for household use, 165 GWh (13.2%) for commercial use, 255 GWh (20.3%) for industrial use, and 109 GWh (8.7%) for public use.

(c) West Kalimantan Province

Maximum electric power demand in 2004 was 196 MW, and generated output was 989 GWh. About 60% of the load is supplied by the power sources of the Kapuas Electric Power System through 150 kV power transmission cables, and the rest is supplied by isolated power sources. Net system energy demand was 800 GWh in 2004, which breaks down as 479 GWh (59.8%) for household use, 159 GWh (19.8%) for commercial use, 83 GWh (10.3%) for industrial use, and 79 GWh (9.9%) for public use. The electrification rate of the province in 2004 reached 44.5%.

(4) Sulawesi Island

(a) North Sulawesi Province

North Sulawesi Province, Middle Sulawesi Province and Gorontalo Province are integrated into one service area, the North/Middle Sulawesi and Gorontalo (Wilayah Suluttenggo) region, by PT. PLN. Maximum electric power demand in Suluttenggo in 2004 was 242 MW, and generated output was 1,125 GWh, while the electrification rate was 47.1%. About 60% of the load is supplied by the Minahasa Electric Power System through 70 kV and 150 kV power transmission lines, and the rest is supplied by isolated power sources located in the Suluttenggo region. Net system energy demand was 553 GWh in 2004, which breaks down

5-7

as 326 GWh (59.0%) for household use, 108 GWh (19.5%) for commercial use, 63 GWh (11.4%) for industrial use, and 56 GWh (10.1%) for public use.

(b) Middle Sulawesi Province

Net system energy demand was 293 GWh in 2004, which breaks down as 200 GWh (68.3%) for household use, 41 GWh (14.0%) for commercial use, 15 GWh (5.1%) for industrial use, and 36 GWh (12.3%) for public use.

(c) Gorontalo Province

Net system energy demand was 107 GWh in 2004, which breaks down as 68 GWh (63.6%) for household use, 12 GWh (11.2%) for commercial use, 11 GWh (10.3) for industrial use, and 14 GWh (13.1%) for public use.

(d) South Sulawesi Province and Southeast Sulawesi Province

South Sulawesi Province and Southeast Sulawesi Province are interconnected through 150kV power transmission lines, and PT. PLN covers these two regions as one service area called South/Southeast Sulawesi (Wilayah Sulseltra) region. Maximum electric power demand in 2004 was 490 MW, and generated output was 2,485 GWh, while the electrification rate was 53.8%. About 85% of the load is supplied by the Makassar Electric Power System through 150 kV power transmission lines, and the rest is supplied by isolated power sources located in the Sulseltra district. Net system energy demand was 2,066 GWh in 2004, which breaks down as 1,094 GWh (52.7%) for household use, 267 GWh (12.9%) for commercial use, 529 GWh (25.5%) for industrial use, and 183 GWh (8.8%) for public use.

(5) Nusa Tenggara Islands

(a) West Nusa Tenggara Province

Maximum electric power demand in 2004 was 105 MW, and generated output was 423 GWh. The entire load is supplied by isolated power sources. Net system energy demand was 400 GWh in 2004, which breaks down as 293 GWh (73.3%) for household use, 66 GWh (16.4%) for commercial use, 8 GWh (1.8%) for industrial use, and 34 GWh (8.4%) for public use. The electrification rate of the province in 2004 reached 28.1%.

(b) East Nusa Tenggara Province

Maximum electric power in 2004 was 62 MW, and generated output was 263 GWh. The entire load is supplied by isolated power sources. Net system energy demand was 227 GWh

5-8

in 2004, which breaks down as 150 GWh (66.1%) for household use, 40 GWh (17.5%) for commercial use, 3 GWh (1.4%) for industrial use, and 34 GWh (14.8%) for public use. The electrification rate of the province in 2004 reached 22.5%.

(6) Maluku Island

Maluku Island was separated into Maluku Province and North Maluku Province, but the service of PT. PLN (Persero) covers these two provinces as one service area called the Maiuku region. Maximum electric power demand in 2004 was 78 MW, and generated output was 305 GWh. The entire load is supplied by isolated power sources. Net system energy demand was 270 GWh in 2004, which breaks down as 182 GWh (67.3%) for household use, 44 GWh (16.3%) for commercial use, 6 GWh (2.2%) for industrial use, and 38 GWh (14.1%) for public use. The electrification rate of the province in 2004 reached 50.6%.

(7) Papua

Maximum electric power demand in 2004 was 90 MW, and generated output was 465 GWh. The entire load is supplied by isolated power sources in the area. Net system energy demand was 398 GWh in 2004, which breaks down as 250 GWh (62.8%) for household use, 94 GWh (23.3%) for commercial use, 6 GWh (1.5%) for industrial use, and 48 GWh (12.1%) for public use. The electrification rate of the province in 2004 reached 28.3%.

5.1.2 Future Outlook of Electricity Demand

In order to prepare a geothermal development master plan, it is necessary to study the expected amount of geothermal development requested from electric power demand side. This requires a detail power demand forecast study by each system. The Ministry of Energy and Mineral Resources formulates a National Electricity Development Plan (RUKN) annually. In this paper, a study is made on the basis of the estimated electricity demand in the National Electricity Development Plan (RUKN) in 20052.

(1) Condition for Electricity Demand Estimation

The National Electricity Development Plan (RUKN) (2005) estimates the future economic growth rate at an annual average of 6.5% nationwide (Table 5.1.2-1). It also estimates an annual population growth rate of 0.9% for nationwide, 0.8% for Java-Bali Island, and 1.1% for areas outside Java-Bali Island. The future electrification rate by region is estimated as shown in Table 5.1.2-2.

2 The latest National Electricity Development Plans (RUKN) as of June, 2007 is the 2006 version. However, from the following reasons, the study was based on the 2005 version; (a) there is no wide difference between the 2005 version and the 2006 version, (b) the 2005 version contains detail information of power supply composition.

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Assumption for Electricity Demand Estimation Annual GDP Growth Annual Population Growth All Indonesia Java- Bali Out of Java-Bali

6.5%

0.9% 0.8% 1.1%

(2) Estimation of Electricity Demand for the Whole Country

Based on these assumptions, the National Electricity development Plan (RUKN) (2005) estimates that the electricity demand for all Indonesia will reach 322,000 GWh in 2020 (annual average growth rate of 7.3% from 2004) and 450,000 GWh in 2025 (ditto 7.2%). It also estimates that maximum electric power demand will reach 58,100 MW in 2020 (annual average growth rate of 6.9% from 2004) and 79,900 in 2025 (ditto 6.8%) (Fig. 5.1.2-1). In order to meet such increase in power demand, it estimates that the electric power facilities across the country will be required to generate 73,200 MW in 2025 and 99,400 MW in 2025. Since the “Geothermal Development Road Map” sets 2025 as its target year, and sets 2012, 2016 and 2020 as its interim target years, each demand forecast in these interim target years is also shown in Table 5.1.2-3. Also, electricity demand by province is estimated as shown in the following section.

(3) Estimation of Electricity Demand by Province

(a) Nanggroe Ache Darussalam (NAD) Province

It is estimated that electricity demand from 2005 to 2025 will increase at an annual average of 5.2%, and the electrification rate is expected to reach 100% in 2020. Accordingly, electricity demand in 2025 is expected to reach 1,800GWh.

(b) North Sumatra Province

It is estimated that population growth from 2005 to 2025 will average 0.89% annually, and economic growth during the same period is expected to be 8.5% a year. The electrification rate is expected to reach 100% in 2020. Electricity demand from 2005 to 2025 is forecasted to increase at an annual average of 7%, and electricity demand in 2025 is expected to reach 18,000GWh.

(c) West Sumatra Province

It is estimated that population growth from 2005 to 2025 will average 0.89% annually, and economic growth during the same period is expected to be 6.5% a year. The electrification rate is expected to reach 100% in 2020. Electricity demand from 2005 to 2025 is forecasted

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to increase at an annual average of 6%, while electricity demand in 2025 is expected to reach 5,500 GWh.

(d) Riau Province

It is estimated that population growth from 2005 to 2025 will average 0.89% annually, while economic growth during the same period is expected to be 7.6% a year. The electrification rate is expected to reach 100% in 2020. Electricity demand from 2005 to 2025 is forecasted to increase at an annual average of 13%, while electricity demand in 2025 is expected to reach 13,000 GWh.

(e) S2JB Region (South Sumatra, Jambi and Begkulu)

It is estimated that economic growth of S2JB from 2005 to 2025 will be 8% and population growth will be 0.89%. It is expected that the electricity demand will increase at an annual average of 7%, while electricity demand in 2025 will reach 9,500 GWh.

(f) Lampung Province

It is estimated that the economic growth from 2005 to 2025 will be 5% and population growth will average 0.89% annually. It is expected that the electricity demand in the same period will increase at an annual average of 7%, and the electrification rate will reach 100% in 2025.

(g) Sumatra System

Since the Sumatra System will be consolidated in the near future, it is expected that a reserve margin for maximum electric power demand will be 40% from 2005 to 2010, 35% from 2011 to 2015 and 20-30% from 2016 to 2025. Based on these assumptions of electricity demand in each province as mentioned above, it is expected that electric power facilities with a generating capacity of 12,700 MW will be required for this system in 2025.

(h) Bangka Belitung Islands

It is expected that future economic growth rates will average 7.5% annually and electricity demand from 2005 to 2025 will increase at an annual average of 6.4%. Maximum electric power demand is expected to reach 143 MW in 2025.

(i) Batam Island

It is expected that electricity demand from 2005 to 2025 will increase at an annual average of 9.5% and maximum electric power demand in 2025 will reach 770 MW. Given a reserve

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margin of 40% from 2005 to 2010, and 30% from 2011 to 2025, it is estimated that electric power facilities with a generating capacity of 1,000 MW will be required by 2025.

(j) Java-Madura-Bali System

It is expected that population growth rates from 2005 to 2025 will be 0.9%, regional economic growth rate will be 6.2% a year and the electrification rate in 2025 will reach 93%. An increase in electricity demand from 2005 to 2025 will average 7.2% annually, which breaks down as 4% a.n. for household use, 10% a.n. for commercial use, 2.5% a.n. for public use and 8% a.n. for industrial use. Power consumption in the Java-Madura-Bali System is expected to reach 348,000 GWh in 2025. This system will supply electric power to all the provinces of Java, Madura and Bali Island through a 500kV transmission grid. An interconnection from Java Island to Bali Province will be made through 150 kV marine cables. Madura will also be supplied with electric power in the same way. The growth rate of load (maximum electric power demand) up to 2025 is expected as 7.2% annually on average. Given that the load factor of the system will be 74% and the gross loss rate in 2025 will be 13%, maximum electric power demand up to 2025 is expected to reach 59,100 MW. Given that a reserve margin for this system is expected to be 30-35% from 2005 to 2015 and 15-25% from 2016-2025, it is expected that electric power facilities with a generating capacity of 72,700 MW will be required to meet this electricity demand in 2025. Currently a plan is under consideration to connect the systems of Java Island and Sumatra Island through marine cables (with the capacity of 2,100MW) to improve the reliability of both systems.

(k) West Kalimantan Province

It is estimated that population growth rates up to 2025 will be 0.89% annually and that economic growth will be 7.4%. The electrification rate is expected to reach 99% by 2025. It is expected that an increase in electricity demand will be 4.3% a year and maximum electric power demand will reach 402 MW in 2025. Given that a reserve margin will be 40-45% up to 2025, it is expected that power sources with a capacity of 603 MW will be required in 2025.

(l) East Kalimantan Province

It is expected that future population growth will average 0.89% annually and the economic growth will be 7.6%. Based on this assumption, it is expected that an increase in electricity demand from 2005 to 2025 will average 10% annually. Maximum electric power in 2025 is expected to reach 1,928 MW. Given that a reserve margin will be 30-40%, electric power sources with a capacity of 2,700 MW will be required in 2025.

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(m) Kalselteng System (Middle Kalimantan Province and South Kalimantan Province)

It is estimated that this system will rapidly develop up to 2025. It is expected that demand will increase 7% a year and maximum electric power in 2025 will reach 2,045 MW. Given that a reserve margin is 25-45%, it is expected that total capacity of this system will reach 2,760 MW to meet electricity demand in 2025.

(n) Sulutenggo System (North Sulawesi Province, Middle Sulawesi Province and Gorontalo Province)

If the electric power of these three provinces is consolidated, it is estimated that an increase in electricity demand will be 9% a year and maximum electric power will reach 787 MW in 2025 and 1,336 MW in 2025. Given that a reserve margin will be 23-40%, it is expected that electric power facilities required in 2025 will reach 1,938 MW.

(o) Sulsetra System (South Sulawesi Province and Southeast Sulawesi Province)

It is estimated that an increase in electricity demand in these two provinces will average 6.7% annually and maximum electric power will reach 2,031 MW in 2025. Given that a reserve margin is expected to be 20-45%, it is expected that the capacity of electric power facilities will reach 2,743 MW in 2025.

(p) West Nusa Tenggara Province

It is expected that population growth up to 2025 will average 0.8% annually and regional economic growth is 7% a year. It is expected that maximum electric power will reach 568 MW by 2025. Given that a reserve margin is expected to be 20-45%, electricity demand in this region is expected to be 795 MW.

(q) East Nusa Tenggara Province

It is expected that maximum electric power will increase in incremental steps and reach 313 MW in 2025. Given that a reserve margin is expected to be 20-50%, it is expected that the amount of electric power facilities required in 2025 will reach 439 MW.

(r) Maluku Province and North Maluku Province

It is estimated that the electricity demand in these two provinces will increase at an annual average of 6% and maximum electric power will reach 184 MW in 2025. Given that a reserve margin is expected to be 30-40%, it is expected that the capacity of electric power facilities will reach 257 MW in 2025.

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(s) Papua

It is estimated that the electricity demand will increase at an annual average of 8% and maximum electric power will reach 376 MW in 2025. Given that a reserve margin is expected to be 25-55%, it is expected that the capacity of electric power facilities will reach 582 MW in 2025.

The above estimation of electricity demand in systems with affluent geothermal resources are shown in Table 5.1.1-5.

(4) Restriction of Geothermal Resource Development

Geothermal power plants use steam extracted from underground. Therefore, it is difficult to control the volume of the steam artificially which is always done in thermal power plants. Therefore, geothermal power plants are operated with the constant output and are used as base load suppliers. For this reason, it is not appropriate to develop geothermal resources more than the minimum electric power demand in the system. The minimum electric power demand remains roughly at about 40% level of the maximum electric power demand according to the electric power demand statistics in Indonesia. Based on the assumption that this tendency will continue in the future, the geothermal resource development is restricted under the ceiling of minimum electric power demand forecast, which is about 40% of the peak demand forecast in each system in this study (Table 5.1.1-5).

5.2 Required Transmission Line and Substation Facility on Construction of Geothermal Power Plants

5.2.1 Present State and Construction Plan of Each Power System

Power sy Power system developing level depends on the each island in Indonesia. The service voltages of transmission line are 500kV, 275kV (design but 150kV operation), 150kV and 70kV, then 20kV for distribution line. Java is the island of the nation's largest concentrations of population and has the most developing power system. The next one is Sumatra, and others including Sulawesi and Kalimantan have power systems separated with each urban area, and these power systems are still expanding gradually.

The 73 prominent geothermal power development sites are concentrated in Sumatra and Java more than half, except for Kalimantan and Papua. The power systems are classified into power grids and isolated power systems. The power grids are in Sumatra, Java-Bali and Sulawesi (north-east Minahasa power system and south-west power system), and other islands like Nusatenggara islands and Maluku islands have isolated power systems using 20kV distribution lines mainly. The each power grid has different voltage ranks, and the each construction plan of transmission line has its own characteristics. RUPTL (the National

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Electricity General Plan: Year 2006-2015), which is based on RUKN (the Electrical Power Supply Business Plan) of MEMR, by PT PLN is used as the power system plan in Indonesia in this report (Table 5.2.1-1, Table 5.2.1-2). stem developing level depends on the each island in Indonesia. The service voltages of transmission line are 500kV, 275kV (design but 150kV operation), 150kV and 70kV, then 20kV for distribution line. Java is the island of the nation's largest concentrations of population and has the most developing power system. The next one is Sumatra, and others including Sulawesi and Kalimantan have power systems separated with each urban area, and these power systems are still expanding gradually.

The 73 prominent geothermal power development sites are concentrated in Sumatra and Java more than half, except for Kalimantan and Papua. The power systems are classified into power grids and isolated power systems. The power grids are in Sumatra, Java-Bali and Sulawesi (north-east Minahasa power system and south-west power system), and other islands like Nusatenggara islands and Maluku islands have isolated power systems using 20kV distribution lines mainly. The each power grid has different voltage ranks, and the each construction plan of transmission line has its own characteristics. RUPTL (the National Electricity General Plan: Year 2006-2015), which is based on RUKN (the Electrical Power Supply Business Plan) of MEMR, by PT PLN is used as the power system plan in Indonesia in this report (Table 5.2.1-1, Table 5.2.1-2).

(1) Sumatra Power System

Sumatra has developed power system, and the service voltages of transmission line are 500kV, 275kV (design but 150kV operation) and 150kV, then there are few 70kV transmission lines partially. Sumatra has a problem of power supply shortage in the northern part because of power demand increasing recently. The connection between north and south by 275kV transmission trunk line is the big issue in Sumatra (Fig. 5.2.1-1).

(2) Java-Bali Power System

Java-Bali system is the most developed power system in Indonesia, and the existing transmission lines are 500kV, 150kV and 70kV without 275kV like Sumatra. The power system stability of Java-Bali system has greatly increased, because 500kV southern route of east-west transmission trunk line has operated in 2006 in addition to the northern route (Fig. 5.2.1-2).

(3) Power Systems in Sulawesi

Power systems in Sulawesi are not good enough yet. There are Minahasa power system in north-east and the south-west power system with a central focus on Makassar. The existing transmission lines are 150kV and 70kV (Fig. 5.2.1-3).

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(4) Other Isolated Islands

(a) Nusatenggara

There are diesel power stations mainly, and the electricity is delivered to some partial area by 20kV distribution line.

(b) Maluku

There are diesel power stations mainly, and the electricity is delivered to some partial area by 20kV distribution line.

5.2.2 Required Transmission Line and Substation Facility on Construction of Geothermal Power Plants

The generated power by the 73 prominent geothermal power development sites will be able to be transmitted to Indonesian power systems (transmission lines or distribution lines) directly. The connections are by transmission lines in the power systems of Sumatra, Java-Bali and Sulawesi (Minahasa power system and South-west power system), and by distribution lines in other isolated islands mainly. The each connection of the power systems has reviewed the exact point to connect and the method of the connection in consideration of the each generation capacity, the transmission line construction cost and the convenience of system operation. The characteristic of each power system is as follows and the each case of the connection of the 73 prominent geothermal sites is showed by a table (Table 5.2.2). The further detailed data are showed by the transmission line data-base of this master plan.

(1) Sumatra Power System

Sumatra has the developed power system. The 32 prominent geothermal power development sites will be connected to the nearest substations (power stations) or the nearest transmission line by P connection using 150kV except for two cases of Sabang island at the north-end in Sumatra, but the four prominent sites will be connected to 275kV proposed transmission lines (Figs. 5.2.2-1 to 8).

(2) Java-Bali Power System

Java-Bali power system uses 500kV, 150kV and 70kV, but the 22 prominent geothermal power development sites will be connected to the nearest substations (power stations) or the nearest transmission line by P connection using 150kV except for one case of 70kV (Figs. 5.2.2-9 to13).

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(3) Power Systems in Sulawesi

Power systems in Sulawesi work by 150kV and 70kV, and the 8 prominent geothermal power development sites will be connected to the nearest substations (power stations) in the north-east Minahasa power system or the south-west power system (Figs. 5.2.2-14 to 15).

(4) Other Isolated Islands

(a) Nusatenggara

The 8 prominent geothermal power development sites will be connected to 20kV distribution lines for the base-load basically, because the power demands are small. Some 150kV and 70kV transmission lines will be constructed in Nusatenggara after 2008.

(b) Maluku The 3 prominent geothermal power development sites will be connected to 20kV

distribution lines for the base-load basically, because the power demands are small.

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Installed Capacity (2004)

Gas Oil, 12 MW

Diesel, 2,921 MW

Geothermal, 807MW

Combined C,6,561 MW

Gas Turbine,1,482 MW

Steam, 6,900 MW

Hydro, 3,199 MW

21,882 MW

Energy Demand by Type of Customers (2004)

Social, 2,238 GWh

Gov. Office, 1,645 GWh

Street Light, 2,045 GWh

Business, 15,258 GWh

Industrial, 40,324 GWh

Residentia ,38,588 GWh

100,097 GWh

（Source）PLN Statistics (2004) Fig. 5.1.1-1 Installed Power Plant Capacity (2004)

Fig. 5.1.1-2 Energy Demand by Type of Customers (2004)

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(MW)

Region Hydro Steam Gas Turbine CombinedCycle Geothermal Diesel Gas Oil

Sumetra 566 745 377 818 2 844 0 3,352 15.3%Jawa-Bali 2,409 6,000 927 5,683 785 103 0 15,908 72.7%Sulawesi & Golontaro 61 0 0 0 20 263 0 344 1.6%S Sulawesi 129 25 123 0 0 187 0 464 2.1%NTB 0 0 0 0 0 147 0 148 0.7%NTT 0 0 0 0 0 128 0 128 0.6%Maruku 0 0 0 0 0 170 0 170 0.8% sub total 3,166 6,770 1,427 6,501 807 1,841 0 20,512 93.7%Banka 0 0 0 0 0 85 0 85 0.4%Batam 0 0 0 0 0 157 12 169 0.8%W Kalimantan 0 0 34 0 0 206 0 240 1.1%E Kalimantan 0 0 0 60 0 276 0 336 1.5%S Kalimantan 30 130 21 0 0 215 0 396 1.8%Papua 3 0 0 0 0 141 0 144 0.7% sub Total 33 130 55 60 0 1,080 12 1,370 6.3%TOTAL 3,199 6,900 1,482 6,561 807 2,921 12 21,882 100.0%

14.6% 31.5% 6.8% 30.0% 3.7% 13.4% 0.1% 100.0%(Source: PLN Statistics 2004, Pertamina Materials)

Total

No. Area 2010 2015 2020 20251 NAD 76 85 100 1002 North Sumatra 84 96 100 1003 West Sumatra 81 95 100 1004 Riau 52 60 75 1005 South Sumatra, Jambi, Bengkulu 56 70 80 956 Lampung 60 80 91 1007 Bangka Belitung 78 90 100 1008 Batam 100 100 100 1009 Jawa-Madura-Bali 71 85 100 10010 East Kalimantan 75 94 100 10011 South & Central Kalimantan 66 79 96 10012 West Kalimantan 65 81 93 9913 North & Central Sulawesi, Gorontalo 57 68 88 9514 South & South East Sulawesi 57 61 80 9615 West Nusa Tenggara 36 45 70 8516 East Nusa Tenggara 32 42 69 8417 Maluku & North Maluku 73 91 100 10018 Papua 37 48 75 90 All Indonesia Total 69 76 90 93

Table 5.1.1-1 Installed Power Plant Capacity (2004)

Table 5.1.2-1 Premise of Electric Power Demand Projection

Table 5.1.2-2 Assumption of Electrification

(Source) RUKN (2005)

Annual GDP Growth Annual Population Growth All Indonesia Java- Bali Out of Java-Bali

6.5%

0.9% 0.8% 1.1%

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Electric Power Demand Projection by RUKN (2005)

0

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Energy Demand Peak Power Demand

Year Unit 2004（Actual) 2012 2016 2020 2025

Energy Demand GWh 100,097 164,609 243,460 322,278 450,101　　Average Annual Growth (from 2004）－ 5.9% 7.4% 7.3% 7.2%Energy Production GWh 120,161 202,510 274,724 364,385 510,142Peak Power Demand MW 18,896 32,991 44,143 58,118 79,920　　Average Annual Growth (from 2004）－ 6.5% 6.8% 6.9% 6.8%Required Installed Capacity MW 21,470 43,282 55,539 73,233 99,438

(Source) RUKN (2005) Fig. 5.1.2-1 Projection of Electric Power Demand (All Indonesia)

Table 5.1.2-3 Projection of Electric Power Demand (All Indonesia)

(Source) RUKN (2005)

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Sumatra System Demand & Supply Balance TableＩｔｅｍ Unit 2004(Act.) 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Energy Demand GWh 12,436 12,222 13,197 14,260 15,421 16,692 18,088 19,474 20,997 22,667 24,502 26,521 28,827 31,045 33,306 35,718 38,333 41,070 43,989 47,099 50415 53,950

Growth － - 8.0% 8.0% 8.1% 8.1% 8.2% 8.1% 8.0% 8.0% 8.0% 8.1% 8.1% 8.1% 8.0% 8.0% 7.9% 7.9% 7.8% 7.8% 7.7% 7.7%Energy Generation GWｈ 10,436 13,713 14,807 16,000 17,303 18,728 20,294 21,849 23,559 25,432 27,492 29,756 32,056 34,522 37,036 39,718 42,627 45,464 48,695 52,138 55,809 59,722Peak Power Demand ＭＷ 2,531 2,485 2,683 2,899 3,086 3,340 3,564 3,837 4,137 4,399 4,755 5,147 5,545 5,971 6,406 6,870 7,263 7,746 8,297 8,883 9,509 10,176 Growth － - 8.0% 8.0% 7.5% 7.7% 7.5% 7.5% 7.6% 7.4% 7.5% 7.6% 7.6% 7.6% 7.6% 7.5% 7.4% 7.4% 7.3% 7.3% 7.3% 7.3%Minimum Demand (*) ＭＷ - 994 1,073 1,160 1,234 1,336 1,426 3,635 3,755 3,860 4,002 4,159 4,318 4,488 4,662 4,848 5,005 5,198 5,419 5,653 5,904 6,170(*) Minimum demand is assumed as 40% of peak power demand.(*) Transmission line between Sumatra and Java is considered after 2011.

Java-Madura-Bali System Demand & Supply Balance TableＩｔｅｍ Unit 2004(Act.) 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Energy Demand GWh 79,772 81,150 87,095 93,779 101,166 109,269 118,418 128,131 138,576 149,861 162,085 175,350 189,013 203,243 218,143 233,814 250,114 267,400 285,756 305,275 326065 348,239

Growth － - 7.3% 7.5% 7.6% 7.7% 7.9% 7.9% 7.9% 8.0% 8.0% 8.0% 8.0% 8.0% 7.9% 7.9% 7.8% 7.7% 7.7% 7.6% 7.6% 7.6%Energy Generation GWｈ 92,634 93,665 100,196 107,274 115,680 124,861 135,264 146,262 158,125 170,889 183,208 198,201 213,585 229,665 246,501 264,210 282,628 302,162 322,904 344,961 368,453 393,511Peak Power Demand ＭＷ 14,310 14,851 15,886 17,008 18,090 19,525 21,152 22,563 24,393 26,362 28,262 30,575 32,509 34,957 37,519 40,215 43,018 45,386 48,502 51,815 55,343 59,107 Growth － - 7.0% 7.0% 6.8% 7.1% 7.3% 7.2% 7.3% 7.4% 7.4% 7.5% 7.4% 7.4% 7.4% 7.4% 7.3% 7.2% 7.2% 7.2% 7.2% 7.2%Minimum Demand (*) ＭＷ - 5,940 6,354 6,803 7,236 7,810 8,461 6,925 7,657 8,445 9,205 10,130 10,904 11,883 12,908 13,986 15,107 16,054 17,301 18,626 20,037 21,543(*) Minimum demand is assumed as 40% of peak power demand.(*) Transmission line between Sumatra and Java is considered after 2011.

North / Central Sulawesi & Gorontalo Demand & Supply Balance TableＩｔｅｍ Unit 2004(Act.) 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Energy Demand GWh 952 914 968 1,035 1,114 1,206 1,313 1,429 1,562 1,711 1,880 2,069 2,271 2,495 2,742 3,017 3,314 3,646 4,015 4,426 4883 5,393

Growth － - 5.9% 6.4% 6.8% 7.2% 7.5% 7.7% 8.0% 8.2% 8.3% 8.5% 8.6% 8.7% 8.8% 8.9% 9.0% 9.0% 9.1% 9.2% 9.2% 9.3%Energy Generation GWｈ 1,125 1,007 1,064 1,132 1,219 1,319 1,436 1,564 1,708 1,872 2,056 2,264 2,507 2,779 3,083 3,421 3,791 4,207 4,673 5,196 5,782 6,439Peak Power Demand ＭＷ 242 225 238 253 268 290 315 337 368 403 435 470 520 577 640 710 787 873 970 1,078 1,200 1,336 Growth － - 5.8% 6.0% 6.0% 6.6% 7.0% 7.0% 7.3% 7.6% 7.6% 7.6% 7.9% 8.2% 8.4% 8.6% 8.7% 8.8% 9.0% 9.1% 9.2% 9.3%Minimum Demand (*) ＭＷ - 90 95 101 107 116 126 135 147 161 174 188 208 231 256 284 315 349 388 431 480 534(*) Minimum demand is assumed as 40% of peak power demand.

South & South East Sulawesi SysDemand & Supply Balance TableＩｔｅｍ Unit 2004(Act.) 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Energy Demand GWh 2,066 2,346 2,544 2,758 2,987 3,233 3,505 3,756 4,023 4,308 4,611 4,934 5,323 5,628 5,950 6,289 6,610 6,966 7,341 7,738 8158 8,603

Growth － - 8.4% 8.4% 8.4% 8.3% 8.4% 8.2% 8.0% 7.9% 7.8% 7.7% 7.7% 7.6% 7.4% 7.3% 7.1% 7.0% 6.9% 6.9% 6.8% 6.7%Energy Generation GWｈ 2,485 2,735 2,829 3,176 3,400 3,683 3,993 4,279 4,583 4,911 5,252 5,621 6,177 6,524 6,956 7,415 7,860 8,353 8,877 9,434 10,027 10,660Peak Power Demand ＭＷ 490 549 585 630 672 724 780 832 887 945 1,006 1,071 1,166 1,243 1,326 1,413 1,498 1,592 1,692 1,798 1,911 2,031 Growth － - 6.6% 7.1% 7.0% 7.2% 7.3% 7.2% 7.1% 7.0% 7.0% 6.9% 7.1% 7.0% 7.0% 7.0% 6.9% 6.9% 6.8% 6.8% 6.8% 6.8%Minimum Demand (*) ＭＷ - 220 234 252 269 290 312 333 355 378 402 428 466 497 530 565 599 637 677 719 764 812(*) Minimum demand is assumed as 40% of peak power demand.

NTB System Demand & Supply Balance TableＩｔｅｍ Unit 2004(Act.) 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Energy Demand GWh 400 438 482 533 590 652 721 791 868 953 1,036 1,126 1,215 1,312 1,416 1,529 1,639 1,753 1,876 2,008 2149 2,300

Growth － - 10.0% 10.3% 10.4% 10.5% 10.5% 10.4% 10.3% 10.2% 10.0% 9.9% 9.7% 9.6% 9.4% 9.3% 9.2% 9.1% 8.9% 8.8% 8.7% 8.6%Energy Generation GWｈ 423 486 535 591 654 724 800 878 964 1,058 1,150 1,250 1,361 1,482 1,615 1,758 1,901 2,051 2,214 2,389 2,579 2,783Peak Power Demand ＭＷ 105 121 132 146 162 179 198 218 239 262 285 310 331 353 376 402 426 451 477 505 535 568 Growth － - 9.1% 9.8% 10.2% 10.3% 10.4% 10.3% 10.2% 10.1% 10.0% 9.9% 9.6% 9.3% 9.1% 9.0% 8.8% 8.6% 8.4% 8.3% 8.1% 8.0%Minimum Demand (*) ＭＷ - 48 53 58 65 72 79 87 96 105 114 124 132 141 150 161 170 180 191 202 214 227(*) Minimum demand is assumed as 40% of peak power demand.

NTT System Ｉｔｅｍ Unit 2004(Act.) 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Energy Demand GWh 227 255 280 309 340 375 414 453 496 543 589 640 678 718 762 808 859 934 1,016 1,107 1207 1,316

Growth － - 9.8% 10.1% 10.1% 10.1% 10.2% 10.1% 10.0% 9.9% 9.7% 9.6% 9.3% 9.0% 8.8% 8.6% 8.4% 8.5% 8.5% 8.5% 8.5% 8.6%Energy Generation GWｈ 263 283 311 343 378 417 460 503 550 602 654 710 759 811 868 929 996 1,092 1,199 1,317 1,448 1,592Peak Power Demand ＭＷ 62 67 74 82 90 99 109 120 131 143 155 169 177 185 194 204 214 231 249 269 290 313 Growth － - 9.6% 10.0% 10.0% 10.1% 10.2% 10.0% 9.9% 9.9% 9.7% 9.6% 9.2% 8.8% 8.5% 8.2% 8.0% 8.0% 8.0% 8.0% 8.0% 8.0%Minimum Demand (*) ＭＷ - 27 30 33 36 40 44 48 52 57 62 68 71 74 78 82 86 92 100 107 116 125(*) Minimum demand is assumed as 40% of peak power demand.

Maluku & N. Muluku System Ｉｔｅｍ Unit 2004(Act.) 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Energy Demand GWh 270 238 252 267 283 300 318 335 353 372 392 413 441 470 502 536 571 610 652 697 745 796

Growth － - 5.9% 5.9% 5.9% 6.0% 6.0% 5.9% 5.8% 5.7% 5.7% 5.7% 5.8% 5.8% 5.9% 6.0% 6.0% 6.1% 6.1% 6.2% 6.2% 6.2%Energy Generation GWｈ 305 270 285 302 319 337 357 375 394 414 435 457 488 520 555 593 633 676 722 771 824 881Peak Power Demand ＭＷ 78 57 60 64 67 71 76 79 83 87 91 95 102 109 116 124 132 141 151 161 172 184 Growth － - 5.3% 6.0% 5.5% 5.6% 5.9% 5.6% 5.5% 5.4% 5.3% 5.2% 5.4% 5.6% 5.6% 5.7% 5.8% 5.8% 5.9% 5.9% 6.0% 6.0%Minimum Demand (*) ＭＷ - 23 24 26 27 28 30 32 33 35 36 38 41 44 46 50 53 56 60 64 69 74(*) Minimum demand is assumed as 40% of peak power demand.

Table 5.1.2-4 Electric Power Demand Outlook by Region (Regions affluent with geothermal resources)

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Fig. 5.2.1-1 Power System in Sumatra

Table 5.2.1-2 Transmission Line Expansion Plan (Year 2006-2014)

Transmission Line(kms)

Transformer(MVA)

Java-Bali500kV 3,578 16,000150kV 11,386 28,18970kV 3,764 2,917

Sumatra275kV150kV 4,361 7,43170kV 310 334

Sulawesi150kV 1,044 85670kV 420 470

Kalimantan150kV 1,120 79070kV 123 82

Total 26,106 57,069Note）Outside Java-Bali data are for 2004.

Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 TotalJava-Bali

500kV 861 178 280 250 110 920 356 2,955150kV 2,020 1,280 207 99 222 355 438 210 316 5,14770kV 702 58 218 64 26 22 172 1,262

Sumatra275kV 1,502 482 20 2,004150kV 399 1,549 1,019 1,367 1,127 233 841 45 6,580

Sulawesi150kV 778 92 704 320 270 1,186 3,35070kV 106 76 77 98 40 397

Kalimantan275kV 396 396150kV 479 952 16 348 130 172 2,09770kV 40 40

IBT150kV 60 42 60 16270kV 50 50

Total 5,385 3,233 3,635 2,270 3,741 2,864 2,315 277 508 24,228

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Fig. 5.2.1-1 Power System in Sumatra

Fig. 5.2.1-2 Java-Bali Power System

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Table 5.2.2-1 Prospective Connection between Geothermal Power Sites and Existing/Planned Power Grid

T/L Distance

kV km S/S S/SAceh 1 IBOIH - JABOI 20 5 D/L Distribution LineAceh 2 LHO PRIA LAOT 20 3 D/L Distribution LineAceh 3 SEULAWAH AGAM 150 4 2P Sigli Banda AcehAceh 4 G. GEUREUDONG 150 11 TakengonAceh 5 G. KEMBAR 150 59 Kuta Cane

SumUta 6 G. SINABUNG 150 38 2P Pematang Siantar Tebing TinggiSumUta 7 LAU DEBUK-DEBUK / SIBAYAK 150 6 BrastagiSumUta 8 SARULA 275 16 Sarulla planned S/SSumUta 9 SIBUAL BUALI =SARULA 275 26 Padang SidempuanSumUta 10 S. MERAPI - SAMPURAGA 275 23 2P Payakumbuh Padang SidempuanSumUta 11 PUSUK BUKIT - DANAU TOBA 150 18 2P Tarutung TeleSumUta 12 SIMBOLON - SAMOSIR 150 3 SimangkokSumBar 13 MUARALABUH 150 7 Kambang planned S/SSumBar 14 G. TALANG 150 7 IndarungJambi 15 LEMPUR / KERINCI 150 32 Sungal Penuh planned S/SJambi 16 SUNGAI TENANG 150 83 BangkoJambi 17 SUNGAI PENUH 150 5 Sungai Penuh planned S/SJambi 18 SUNGAI BETUNG 150 32 Sungai Penuh planned S/SJambi 19 AIR DIKIT 150 35 #15Lempur/KerinciJambi 20 G. KACA 150 29 Sungai Penuh planned S/S

Bengkulu 21 B. GEDUNG HULU LAIS 150 69 Lubuk LinggauBengkulu 22 TAMBANG SAWAH 150 19 #21B. G. Hulu LaisBengkulu 23 BUKIT DAUN 150 14 1P #21 B.G. Hulu Lais Lubuk LinggauSumSel 24 MARGA BAYUR 150 29 #26R. Dadap-SegamitSumSel 25 LUMUT BALAI 150 50 LahatSumSel 26 RANTAU DADAP - SEGAMIT 150 25 #25 Lumut Balai

Lampung 27 ULUBELU 150 19 1P Batutegi Pagelaran planned T/LLampung 28 SUOH ANTATAI 150 18 #29 SekincauLampung 29 G. SEKINCAU 150 19 BesaiLampung 30 RAJABASA 150 8 KaliandaLampung 31 WAI RATAI 150 16 1P Gedong Taan Teluk Betung planned T/LJavaBar 32 KAMOJANG 150 10 Kamojang Existing P/SJavaBar 33 G. SALAK 150 1 G. Salak Existing P/SJavaBar 34 DARAJAT 150 3 Darajat Existing P/SJavaBar 35 CISOLOK - CISUKARAME 150 4 1P Pelabuhan Ratu Saketi planned T/LJavaBar 36 G. PATUHA 150 19 G.Patuha planned T/LJavaBar 37 G. WAYANG - WINDU 150 15 2P Bandung Selatan Kamojang planned T/LJavaBar 38 G. KARAHA 150 8 MalangbongJavaBar 39 G. TELAGABODAS 150 10 #38 G. Karaha

Names of the 73 fields in thisSurveyNoRegion Connected S/S or

T/L (P connection)Transmission line between

Remarks on T/L

JavaBar 40 TANGKUBANPERAHU 150 16 2P Bandung Utara Ujung BerungBanten 41 BATUKUWUNG 70 6 SerangBanten 42 CITAMAN - G. KARANG 150 8 1P Menes Rangkas Bitung planned new 150kV R. BitungS/S

Banten 43 G. ENDUT 150 13 2P Pelabuhan Ratu Saketi planned T/LJavaTen 44 DIENG 150 4 Dieng Existing P/SJavaTen 45 MANGUNAN 150 19 Dieng Existing P/SJavaTen 46 TELOMOYO 150 19 1P Sangrahan BawenJavaTen 47 UNGARAN 150 2 1P Ungaran BawenJavaTen 48 G. SLAMET 150 20 BamiayuJavaTim 49 G. ARJUNO - WELIRANG 150 3 LawangJavaTim 50 WILIS / NGEBEL 150 5 1P Kadiri Baru Manis RajoJavaTim 51 IJEN 150 5 1P Situ Bondo Banyuwangi

Bali 52 BEDUGUL 150 6 Batu RitiNTB 53 HU'U DAHA 20 15 D/L Distribution LineNTT 54 WAI SANO 20 17 D/L Distribution LineNTT 55 ULUMBU 20 14 D/L Distribution LineNTT 56 BENA - MATALOKO 20 8 D/L Distribution LineNTT 57 SOKORIA - MUTUBUSA 20 20 D/L Distribution LineNTT 58 OKA - LARANTUKA 20 10 D/L Distribution LineNTT 59 ILI LABALEKEN 20 15 D/L Distribution LineNTT 60 ATADEI 20 12 D/L Distribution Line

SulUta 61 LAHENDONG 150 4 LahendongSulUta 62 KOTAMOBAGU 150 2 KotamobuguSulUta 63 TOMPASO 150 17 KawangkoanSulTen 64 BORA 70 16 PaluSulTen 65 MERANA 70 40 PaluSulSel 66 BITUANG 150 4 MakaleSul SE 67 LAINEA 150 53 KendariMalUta 68 TONGA WAYANA 20 37 D/L Distribution LineMaluku 69 TULEHU 20 12 D/L Distribution LineMalUta 70 JAILOLO 20 14 D/L Distribution LineSumUta 71 SIPAHOLON-TARUTUNG 275 19 Sarulla planned S/SJavaTim 72 IYANG AGROPURO 150 26 Paiton P/SGolontaro 73 SUWAWA-GORONTALO 70 24 Gorontalo

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Fig. 5.2.2-1 Power System Planning in Nanggroe AcheDarussalam (NAD)

Fig. 5.2.2-2 Power System Planning in North Sumatra

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Fig. 5.2.2-3 Power System Planning in West Sumatra

Fig. 5.2.2-4 Power System Planning in Riau

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Fig. 5.2.2-5 Power System Planning in Jambi

Fig. 5.2.2-6 Power System Planning in South Sumatra

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Fig. 5.2.2-7 Power System Planning in Bengkulu

Fig. 5.2.2-8 Power System Planning in Lampung

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Fig. 5.2.2-9 Power System in Jakarta & Banten（Region-Ⅰ）

Fig. 5.2.2-10 Power System in West Java（Region-Ⅱ）

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Fig. 5.2.2-11 Power System in Central Java & Daerah Istimewa Yogyakarta (DIY) （Region-Ⅲ）

Fig. 5.2.2-12 Power System in West Java（Region-Ⅳ）

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Fig. 5.2.2-13 Power System in Bali

Fig. 5.2.2-14 Minahasa Power System in Northeast Sulawesi

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Fig. 5.2.2-15 Single Line diagram in Southwest Sulawesi

Chapter 6 Natural and Social Environmental Study

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Chapter 6 Natural and Social Environmental Study 6.1 Environmental Assessment System

PPLH, which took part of environmental administration, was established in 1978 in Indonesia. Act of the Republic of Indonesia concerning environmental management (act No. 4, 1982), which was described national environmental administration issues, was promulgated. PPLH transformed into KLH in 1982. For strengthening the function of KLH, BAPEDAL was established as an implementation agency for environmental administration based on Degree of President No.23, 1990. KLH was divided and LH was established in March 1993. BAPEDAL was transformed the structure and strengthened the function by Degree of President No.77, 1994, which brushed up the system on implementation of countermeasures for preservation of the environment and public hazards. According to central government policy, local government has right to act for preservation of the environment based on paragraph 3 article 18 of Act of the Republic of Indonesia concerning environmental management, and BLH of each province enforces the environmental issues. Authority concerned and provinces, which has jurisdiction over project, are capacitated enforcement of environmental impact assessment. They organize the “committee of environmental impact assessment” for prescreening and examinating AMDAL report. ”General committee of environmental impact assessment” is organized for enforcing the environmental impact assessment of the project, which has not only one authority concerned. BEPEDAL administrates coordination of environmental impact assessment study. To reflect the article 16 of Act of the Republic of Indonesia concerning environmental management, the Government Regulation No. 29 of 1986 regarding the Environmental Impact Assessment was promulgated. Considering the results of many developments, “regulation regarding Environmental Impact Assessment” Government Regulation No. 51 of 1993 was enacted. In Indonesia Environmental Impact Assessment is called as Analysis Mengenai Dampak Lingkungan (hereafter AMDAL). AMDAL is categorized three according to the intensity and extent of the proposed development.

AMDAL KegiatanTerpadu/Multisektoral; the significant impacts of a proposed integrated business or activity on the environment, where that business or activity is located in a single ecosystem type and also involves more than one authorized government agency.

AMDAL Kawasa; the significant impacts of a proposed integrated business or activity located in a single ecosystem type, which are under the authority of a single authorized government agency.

AMDAL Regional; the significant impacts of a proposed integrated business or activities located in a single ecosystem type in a development planning area as defined

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by the regional spatial plan, which involves more than one authorized government agency as part of the decision-making process.

The significant impacts are fundamental changes to the environment which result from a proposed business or activity, impact significance is determined by 6 parameters (number of affected people, aerial extent, duration, intensity, number of other affected environmental components, cumulative nature, reversibility / irreversibility) in “decree concerning guidelines for the determination of significant impacts” decree No. Kep-056 of 1994.

Types of business and activity that may cause the significant impacts on the environment are specified 14 kinds sectors. The details of activity and its scale were once announced by “decree concerning types of business or activities required preparing an environmental impact assessment”, decree No. Kep-11/Menlh/3/1994, the kind and scale of the business and activities were revised by “decree of sate minister for environment on types of business or activities required to prepare an environmental impact assessment”, decree No. 17 of 2001. (14 sectors, 84 activities)

Environmental Impact Statements called as Analysis Dampak Lingkungan (hereafter ANDAL) and it is a detailed and in-depth research study on the significant impacts of a proposed business or activity.

And also the management plan and monitoring plan shall be prepared in order to manage and monitor the significant impacts of proposed business and activity.

Environmental Management Plan --- called as RKL (Rencana Pengelolaan Lingkungan Hidup) in Indonesia

Environmental Monitoring Plan --- called as RPL (Rencana Pemantauan Lingkungan Hidup) in Indonesia

In accordance with stipulation under Governmental law No. 27 of 1999 regarding EIA, to which any business or activity which not obligated to prepare the EIA, then to those business or activity should prepare but Environmental Management Effort (UKL: Upaya Pengelolaan Lingkungan) and Environmental Monitoring Effort (UPL: Upaya Pemantauan Lingkungan), “decree of minister of environment regarding General Guidance to implement the UKL and the UPL” decree No. 86 of 2002 was announced.

6.2 Legislation, Standards and Regulations Relating to the Environment (Geothermal Development Related)

6.2.1 Air

The environmental quality standard for hydrogen sulfide in air is as shown in Table 6.2.1-1.

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Standards for the discharge of hydrogen sulfide from stationary sources were revised in 1995, and the new geothermal power plant (January 1, 2000 onwards) will be regulated in the manner shown in Table 6.2.1-2.

Table 6.2.1-1 Environment Quality Standards for Air Pollution

Item Measuring condition Standard value (ppm)

Hydrogen sulfide (H2S) Value of 30 min. 0.03

(= 42μg/m3) Source: Enclosure III, Decree of State Minister of Population and Environment Number: KEP – 02 / MENKLH / I / 1988 Date: January 19, 1988

Table 6.2.1-2 Gas Exhaust Standard (Stationary Source)

Item Unit Standard value Hydrogen sulfide (H2S) (Total Reduced Sulfur)

mg/ m3 35

(approx. 25ppm) Source: KEPUTUSAN, MENTERI NEGARA LINGKUNGAN HIDUP Number: KEP. 13 / MENLH/ 3 / 1995 TENTANG, BAKU MUTU EMISI SUMBER TIDAK BERGERAK

6.2.2 Water

The environmental quality standards for water, which should be related to geothermal development, are as indicated in Table 6.2.2-1.

Table 6.2.2-1 Environmental Quality Standard for Water (Drinking Water Usage)

No. Item Unit Maximum concentration Remark

1. Odor - - No odor 2. Total Dissolved Solid

Substances (TDS) mg/l 1,000

3. Turbidity NTU Scale 5 4. Taste - No taste 5. Temperature degree Atmosphere temp. ±3 6. Color TCU Scale 15 7. Arsenic mg/l 0.05 8. Chloride mg/l 250 9. PH 6.5 – 8.5 Mini－Max 10.

Sulfide as H2S mg/l 0.05

Source: PERATURAN PEMERINTAHREPUBLIK INDONESIA Number: 20, 1990

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The quality standards of liquid waste from geothermal activity was not clear in Government Regulation No. 20/1990, it was revised by decree of state minister of Environment “Quality standards of liquid waste of natural and gas as well as Geothermal activities” decree No. Kep-42/MENLH/10/1996. The quality standards of liquid waste for geothermal exploration and production activities are in Table 6.2.2-2.

Table 6.2.2-2 Quality Standards of Liquid Waste

Item Unit maximum Dissolved sulphide acid (as H2S) mg/l 1

Dissolved ammonia (as NH3) mg/l 10 Mercury mg/l 0.005 Arsenic mg/l 0.5

Temperature degree 45 PH － 5.0－9.0

Source: Attachment III, KEP – 42 / MENLH / 10 / 1996 Date: October 9, 1996

6.2.3 Noise

Standards for noise according to type of land use and activity area are shown in Table 6.2.3-1.

Table 6.2.3-1 Standards of Noise Level

Items dB (A) a. Area Usage 1. Residential 55 2. Commercial 70 3. Office and Trade 65 4. Open Green Area 50 5. Industry 70 6. Government and Public facility 60 7. Recreation (Resort) 70 8. Special - Airport - Train station - Shipyard 70 - National Port 60 b. Activity Area 1. Hospital 55 2. School 55 3. Place for pray / Church / Temple / Mosque 55

Source : LAMPIRAN I; DEPUTUSAN MENTERI

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NEGARALINGKUNGAN HIDUP Number : KEP – 48 / MENLH / 11 /1996 Date : 25 NOVEMBER 1996

Noise abatement measures should achieve either the levels given in Table 6.2.3-2 below or a maximum increase in background levels of 3 decibels (measured on the A scale) [dB (A)]. Measurements are to be taken at nose receptors located outside the Project property boundary.

Table 6.2.3-2 Standards of Noise Level at Source

Maximum allowable log Equivalent (hourly measurements), in dB (A) Receptor

Day (07:00 – 22:00)

Night (22:00 – 07:00)

Residential, Institutional, 55 45 Educational Industrial, Commercial 70 70

6.2.4 Subject for Environmental Impact Assessment

Environmental conditions and impacts in the objected area of the geothermal power project, whose capacity is more than 55MW, should be checked by application of AMDAL. In geothermal power projects in and around the following legally protected areas, it lies under an obligation to prepare AMDAL, even if its capacity is less than 55MW. This master plan study is not an object of ANDAL.

Forest protection areas

Peat areas

Water catchment’s areas

Coastal edges

River edges

Areas surrounding lakes and reservoirs

Areas surrounding springs

Nature conservation areas (including nature reserves, wildlife reserves, tourism forests, genetic protection areas, and wildlife refuges)

Marine and freshwater conservation areas (including marine waters, fresh water bodies, coastal areas, estuaries, coral reefs and atolls which have

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special features such as high diversity or a unique ecosystem)

Coastal mangrove areas

National parks

Recreation parks

Nature parks

Cultural reserve and scientific research areas (including karsts areas, areas with special cultural features, archaeological sites or sites with high historical value)

Areas susceptible to natural hazards

In accordance to the Act on Forestry No. 41/1999, forest area is categorized as Conservation Forest, Protection Forest and Production Forest, for which is defined as in Table 6.2.4-1.

Conservation Forest is a forest area having specific characteristic established for the purposes of conservation of animal and plant species and their ecosystem.

Protection Forest is a forest area designated to serve life support system, maintain hydrological system, prevent of flood, erosion control, seawater intrusion, and maintain soil fertility.

Production forest is a forest area designated mainly to promote sustainable forest production. Production forest is classified as permanent production forest, limited production forest, and convertible production forest.

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Table 6.2.4-1 Classification of Forest Area

6.3 Expected Environmental Impact on Project Implementation

6.3.1 Prediction Environmental Impact

The environmental impacts were studied on projects proposed under this master plan study. The conceivable environmental impacts are categorized into three (3) grades of magnitude; serious impact, some impact and unknown impact and each impact is evaluated to be either positive or negative one. The scoping of conceivable impacts is evaluated at each project stage; a planning -F/S stage, a construction stage and a operation stage. The study results are shown in Table 6.3.1-1.

Some negative impacts on the natural environment, such as surface survey and test well drilling, are considered at the planning-F/S stage. Serious impacts of pollution, impacts on the natural environment and geographical features, and involuntary resettlement are expected at the construction stage, arising from geothermal well drilling, construction of power facilities and the geothermal fluid transportation system. Serious impacts of pollution and on the natural environment are expected at the operation stage due to geothermal brine and non-condensable gas emissions. On the other hand, positive impacts are expected to enhance the local economy by increasing employment opportunities, improving livelihoods, etc. Because the GHG emissions from geothermal plants are less than those from other thermal power plants, reduction of GHG emissions is expected to be another positive impact. The impact on social institutions, the poor, misdistribution of benefit and damage and local

Forest Area (Kawasan Hutan) Conservation Forest (Hutan Consavasi) Sanctuary Reserve area (Kawasan suaka alam) Strict Nature Reserve (CA: Cagar Alam) Wildlife Sanctuary (SM: Suaka Margasatwa) Nature conservation area (Kawasan pelestarian alam) National Park (TN: Taman Nasional) Grand Forest Park (THR: Taman Hutan Raya) Nature Recreation Park (TWA: Taman Wisata Alam) Game Hunting Park (TB: Taman Buru) Protection Forest (Hutan Lindung) Production forest (Hutan produksi) Permanent production forest (HP: Hutan Produksi Tetap) Limited production forest (HPT: Hutan Produksi Terbatas)

Convertible production forest (Hutan Produksi yang dapat dikonversi)

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conflict of interests are unknown now. When the project will proceed the planning-F/S stage and the project scale, boundary and so on are determined, these impacts will assess clearly before construction stage by the environmental impact assessment under the Law of Indonesia.

Table. 6.3.1-1 Scoping of Environmental and Social Considerrations

Items

Ove

rall

Rat

ing

Plan

ning

, F/S

Con

stru

ctio

n

Ope

ratio

n

Air Pollution -A -B -B -A Water Pollution -A -B -B -A Soil Pollution -B -B -B Waste -B -B -B -B Noise and Vibration -B -B -B -A Ground Subsidence -A -A Offensive Odors -B -B -B -B

Geographycal Features -A -B -A -B Bottom Sediment

Biota and Ecosystem -A -B -A -A Water Usage -B -B -B -B Accidents -B -B -B -B Global Warming +AInvoluntary resettlement -A -B -A Local economy such as employment and livelihood etc. +A +B +A +ALand use and utilization of local resources +B +B +B +BSocial institutions such as social infrastructure and localdecision-making institutions

C C

Existing social infrastructures and services ＋B +B +B

The poor, indigenous of ethnic people C C

Misdistribution of benefit and damage C C

Local conflict of interests C C

Gender

Children's rights

Cultural heritage -B -B Infectious diseases such as HIV/AIDS etc.

+ : positive impact -: negative impact A : Serious impact is expected B : Some impact is expected C : Extent of impact is unknown No Mark : No impact is expected

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The predicted negative impact and its counter measure are described as follows.

(1) Air

The hydrogen sulfide (H2S) may be included in the steam produced from the geothermal well. Where the concentration of H2S should be higher during the well production test at planning-F/S and construction stage, the negative impact to surrounding areas would be serious. The production tests usually does not take a long duration and the amount of produced steam volume is smaller than that at operation stage, and the impact could be prevented with certain technical measures.. The amount of H2S emission increases at the operating stage comparing with that at planning-F/S and construction stage because much steam produces at this stage. The geothermal power plant is duly engineered in consideration of steam characteristics including the concentration of the H2S. The H2S is extracted from the condensers using the gas extractor and sent to the cooling tower and discharged into the atmosphere from the top where it is diluted and dispersed less than the environmental standard. This method is a standard practice employed in geothermal power plants in the world, and in most cases can sufficiently reduce the H2S concentration at the ground level.

(2) Water

The geothermal hot water may often contain arsenic. All the geothermal hot water taken for blow tests, construction and operation is to be reinjected totally to the deep underground through reinjection wells. Accordingly, there will be no impact in terms of pollution to surface water (rivers, lakes and marshes) and shallow well water. The polluted sludge by drilling is transferred to the solid waste pit by a heavy liquid pump, and then transformed to a solid cake by natural drying. These solid cakes are to be buried into the ground, completely separated from the surrounding soil, where protective measures for sludge seepage and pollution to the potable water should be taken.

During the operating stage, the waste water from the areas using oils, e.g. turbine oil transformer oil, etc, will be returned to the reinjection well lines after oil and grease are removed at oil separator pond. Sanitary waste water from the service buildings and powerhouse is purified in a septic tank and discharged to the rivers.

(3) Soil

At the planning-F/S and construction stages when the reinjection system would not have been completed, the soil pollution is feared as the geothermal fluid would leak to the surrounding. To prevent such leakage, the pit (pond) covered with water proof material should be prepared for the temporally geothermal fluid production test.

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A pit (pond) having enough capacity for outflow of generator lubricant and transformer oil will also be prepared. The tank for chemical is sealed with banking wall.

(4) Waste

The polluted sludge by drilling is transferred to the solid waste pit by a heavy liquid pump, and then transformed to a solid cake by natural drying. These solid cakes are to be buried into the ground, completely separated from the surrounding soil, where protective measures for sludge seepage and pollution to the potable water should be taken. Sludge in the cooling tower is disposed of without adversely affecting environment condition. A pit (pond) having enough capacity for outflow of generator lubricant and transformer oil should be prepared. The tank for chemical should be sealed with banking wall.

(5) Noise and Vibration

The noise is generated when the geothermal well is drilling. If the drilling site should be located near residence area, the drilling rig is covered with soundproof sheet. The cooling tower is also a source of noise during operation. It should be selected to be designed as low noise emission model.

(6) Ground Subsidence

The ground subsidence may happen, if the large amount of geothermal fluid should be taken from subsurface for a long term. At the most of geothermal power plant, geothermal hot water is reinjected to deep underground through reinjection wells to prevent such ground subsidence.

(7) Odor

The predicted odor by geothermal development is due to H2S. The counter measures are as same as the air pollution.

(8) Geographical Feature

Some impact of geographical feature is expected at planning-F/S stage, caused by the construction of well pad preparation and access road construction. Serious impact of geographical feature is expected at construction stage, caused by the large-scale construction such as production/reinjection wells, geothermal fluid pipeline, power plant, etc.. Compact plant layout and shorter pipe line are engineered to minimize the changing of geographical feature. To avoid erosion with rain water, planting is recommended after construction.

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(9) Biota and Ecosystem

Some impact to fauna and flora is expected at planning-F/S stage but serious impact at construct and operation stage. If rare and precious species are recorded or expected to exist in the project area, the existence is identified and investigation and monitoring should be conducted. Before construction stage where the geothermal power plant is bigger than 55MW, the impact assessment to fauna and flora as well as the relevant ecosystem should be done and predict the results of environment impact by power plant construction. If it is necessary, it should be review the geothermal development plan. Geothermal hot water is reinjected to deep underground through reinjection wells, which contribute to prevent the surface, ground water and ecosystem.

(10) Water Usage

The circulate water of the condenser and the cooling tower is taken from the river at the operation stage, and drilling water is taken also from the river at planning-F/S and construction stage. The impact of water usage may be serious, if the river flow rate is few and used as life water at the surrounding resident. It is necessary to investigate the accurate river flow rate to grasp the amount of possible water usage before construction. If required, the water should be taken as planned amount after getting permission from relevant stakeholders.

(11) Accidents

The accident caused by increasing in traffic is expected during planning-F/S, construction and operating stages. The efforts to prevent the accident are necessary by letting the staff strictly abide by a traffic law and improve the knowledge of the road safety.

(12) Involuntary Resettlement

During planning-F/S stage, the construction of access road and drilling pad for exploratory well drilling becomes necessary. The resettlement at the planning-F/S stage can be avoided by adoption of directional drilling. The directional drilling can allow one drilling pad to drill multiple wells with different targets. This is minimizing the civil engineering for access road and well pad construction. The large-scale resettlement is expected at construction stage because large area is necessary for drilling pad of production/reinjection wells, roads, pipelines for transporting geothermal fluid, power plant drilling, and transmission lines. Application of compact layout of power plant design and directional wells may minimize the impact.. In case that the resettlement should be inevitable, the consensus of residence by sufficient consultation should be obtained.

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6.4 Natural and Social Environmental Study

The objectives of natural and social environmental study are to conduct IEE study at master plan study stage, and to predict and to assess the environmental and social impact caused by geothermal exploration and geothermal power development.

6.4.1 Initial Environmental Study

The natural and social environment study, which includes investigation of legal framework of the environmental preservation and disincentive effects of geothermal power development by environmental regulation in the 73 prospective fields, was conducted.

The information of following items is collected in this study. These collected data are used as fundamental data for the geothermal developer to collecting the data and to prepare the development plan of promising fields.

＜Social Environment＞

- Population, number of residences, and state of their distribution (distribution map)

- Any necessity for resettlement of residents due to this development project. If “YES”, The number of residents to be resettled, and resettlement plan or compensation system and Past resettlement of residents implemented in the province

- The number of schools, hospitals and religious facilities, and their distribution

- Communities that would be split or divided by this development project

- Any historic ruins, cultural assets, or aborigine or minority communities in the area affected by this project

- Present use of waters in the area (drinking water, irrigation or others)

- Statistical data of the economic activity of the project area

- Present use of the land in the project area Owners of the land

＜Natural Environment＞

- Literature, material and data on flora and fauna of the project area, protected animals and plants within the area

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- Vegetation map

- National park, Protected forest

- Any scenery or scenic spots deemed important in terms of tourism or religion

＜Pollution / Noise / Vibration / Subsidence＞

- Present water quality of effluents (wastewater) from geothermal facility: pH, Cl, As, Hg, B, NH3, BOD, TS, and others, if any

- Current status regarding noise from geothermal facilities

- Current status regarding air quality by operating geothermal facilities

- Current status regarding vibration and subsidence by operating geothermal facilities

＜Others＞

- Any complaints on pollution from the residents

- Any movement against geothermal developments

- Climate conditions (Wind, Rainfall)

The results are shown in App. 6.4.1-1andApp. 6.4.1-2.

6.4.2 Environmental Impact Assessment

Based on the initial environmental examination, environmental impact assessment on 18 fields ( as planed 16 fields), where supplemental geological and geochemical studies were carried out, was conducted following JICA Guidelines for Environmental and Social Considerations with referring JBIC Guidelines for Confirmation of Environmental and Social Considerations as follows.

This investigation was conducted to be a data for prioritize the prospect field at the master plan making stage. Therefore, the simple investigation carried out, which contains the collecting existing data and the confirmation of a geographic relation between prospect field and the residence/protection area by the field reconnaissance of prospect fields etc. The prospect field, where no existing data for assessment, is recommended that the environment data is collected and evaluated has according to the progress of development in the future.

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(1) Permits and Explanation

(a) EIA

- Have EIA reports been officially completed?

(b) Explanation to the Public

- Are contents of the project and the potential impacts adequately explained to the public based on appropriate procedures, including information disclosure? Is understanding obtained from the public?

- Are proper responses made to comments from the public and regulatory authorities?

(2) Pollutions

(a) Air Quality

- Do air pollutants, such as hydrogen sulfide emitted from geothermal power plants comply with the country’s standards? Is there a possibility that emitted hydrogen sulfide will cause impacts on the surrounding areas, including vegetation?

- Do air pollutants emitted from other facilities comply with the country’s emission standards?

(b) Water Quality

- Do effluents (including thermal effluent) from various facilities, such as power generation facilities comply with the country’s effluent standards? Is there a possibility that the effluents from the project will cause areas that do not comply with the country’s ambient water quality standards?

- In the case of geothermal power plants, is there a possibility that geothermal utilization will cause water pollution by pollutants, such as As and Hg contained in geothermal fluids? If water pollution is anticipated, are adequate measures considered?

- Do leachates from the waste disposal sites comply with the country’s effluent standards and ambient water quality standards? Are adequate measures taken to prevent contamination of soil, groundwater, and seawater by leachates?

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(c) Wastes

- Are wastes generated by the plant operations properly treated and disposed of in accordance with the country’s standards (especially biomass energy projects)?

(d) Soil Contamination

- Has the soil in the project site been contaminated in the past, and are adequate measures taken to prevent soil contamination?

(e) Noise and Vibration

- Do noise and vibrations comply with the country’s standards?

(f) Subsidence

- In the case of extraction of a large volume of groundwater or extraction of steam by geothermal power generation, is there a possibility that the extraction of groundwater or steam will cause subsidence?

(g) Odor

- Are there any odor sources? Are adequate odor control measures taken?

(3) Natural Environment

(a) Protected Areas

- Is the project site located in protected areas designated by the country’s laws or international treaties and conventions? Is there a possibility that the project will affect the protected areas?

(b) Ecosystem

- Does the project site encompass primeval forests, tropical rain forests, ecologically valuable habitats (e.g., coral reefs, mangroves, or tidal flats)?

- Does the project site encompass the protected habitats of endangered species designated by the country’s laws or international treaties and conventions?

- If significant ecological impacts are anticipated, are adequate protection measures taken to reduce the impacts on the ecosystem?

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(c) Hydrology

- Is there a possibility that hydrologic changes due to installation of structures, such as weirs will adversely affect the surface and groundwater flows?

(d) Topography and Geology

- Is there a possibility that the project will cause a large-scale alteration of the topographic features and geologic structures in the surrounding areas?

(4) Social Environment

(a) Resettlement

- Is involuntary resettlement caused by project implementation? If involuntary resettlement is caused, are efforts made to minimize the impacts caused by the resettlement?

- Is adequate explanation on relocation and compensation given to affected persons prior to resettlement?

- Is the resettlement plan, including proper compensation, restoration of livelihoods and living standards developed based on socioeconomic studies on resettlement?

- Does the resettlement plan pay particular attention to vulnerable groups or persons, including women, children, the elderly, and people below the poverty line, ethnic minorities, and indigenous peoples?

- Are agreements with the affected persons obtained prior to resettlement?

- Is the organizational framework established to properly implement resettlement? Are the capacity and budget secured to implement the plan?

- Is a plan developed to monitor the impacts of resettlement?

(b) Living and Livelihood

- Is there a possibility that the project will adversely affect the living conditions of inhabitants? Are adequate measures considered to reduce the impacts, if necessary?

- Is there a possibility that the amount of water (e.g., surface water, groundwater)

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used and discharge of effluents by the project will adversely affect the existing water uses and water area uses?

(c) Heritage

- Is there a possibility that the project will damage the local archeological, historical, cultural, and religious heritage sites? Are adequate measures considered to protect these sites in accordance with the country’s laws?

(d) Landscape

- Is there a possibility that the project will adversely affect the local landscape? Are necessary measures taken?

(e) Ethnic Minorities and Indigenous Peoples

- Does the project comply with the country’s laws for rights of ethnic minorities and indigenous peoples?

(5) Others

(a) Impacts during Construction

- Are adequate measures considered to reduce impacts during construction (e.g., noise, vibrations, turbid water, dust, exhaust gases, and wastes)?

- If construction activities adversely affect the natural environment (ecosystem), are adequate measures considered to reduce impacts?

- If construction activities adversely affect the social environment, are adequate measures considered to reduce impacts?

- If necessary, is health and safety education (e.g., traffic safety, public health) provided for project personnel, including workers?

(b) Monitoring

- Does the proponent develop and implement monitoring program for the environmental items that are considered to have potential impacts?

- Are the items, methods and frequencies included in the monitoring program judged to be appropriate?

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- Does the proponent establish an adequate monitoring framework (organization, personnel, equipment, and adequate budget to sustain the monitoring framework)?

- Are any regulatory requirements pertaining to the monitoring report system identified, such as the format and frequency of reports from the proponent to the regulatory authorities?

The results are shown in App. 6.4.2-1.

Chapter 7 Formation of the Master Plan

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Chapter 7 Formation of the Master Plan

Based on the results of research on geothermal resource characteristics, the power sector situation and natural/social conditions of the geothermal prospects in Indonesia, we drew up a Master Plan for geothermal development consisting of 1) a geothermal development database, 2) a determination of development priority for the fields and 3) a development implementation plan.

7.1 Master Plan for Geothermal Development

In this chapter 7.1, the Master Plan for geothermal development constructed from the data and information collected through various kinds of studies will be discussed. The Master Plan comprises mainly the development priority determination and development implementation plans for each field. The geothermal development database constructed through the accumulation of a variety of data and information will be described in the following chapter, 7.2, along with the methodologies for a future opening to the public and management of the database.

7.1.1 Process for Formation of the Master Plan

The process flow in the formation of the Master Plan for geothermal development is shown in Fig. 7.1.1-1. The proposed geothermal power plant projects in each prospect field are evaluated from the results of studies and research on the resource itself, the natural/social environment, power demand and transmission line length described in Chapters 4, 5, and 6, as well as the economics of the project, which will be mentioned in 7.1.6. An outline of each step in the process of formation of the Master Plan is described below. Detailed methodology of the evaluation and the results will be discussed from section 7.1.2 on.

(1) Expansion and Existing Project

The currently planned geothermal development projects, which have been confirmed through interviews todevelopers (mainly to PERTAMINA) who have the plans, are given top priority for development. In addition, even if there is no concrete plan at present, future expansion projects in developed fields are given top priority, because expansion projects are more likely to be low-risk and economically viable compared to development in ‘green’ fields.

(2) Geothermal Resource Evaluation

Based on the various surveys and studies of resource characteristics, the geothermal prospects in Indonesia are ranked according to the likelihood of the presence of an

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exploitable geothermal reservoir in the field, and the rankings are reflected in the development priority for each the field. Moreover, exploitable resource potential in each field is estimated from the results of Stored-Heat method analysis, taking account of the existing estimations of Indonesian organizations.

(3) Natural/Social Environmental Evaluation (National Park Restrictions)

At present, geothermal power development within the area of national parks is prohibited in Indonesia (but directional well drilling from the outside into the national park is permitted). Development of the entire resource existing in a field, therefore, is not possible for geothermal prospects where some part of the area is national park. When this is the case, the exploitable resource potential is reduced according to the ratio of national park area within the inferred geothermal reservoir area.

(4) Power Sector Evaluation (Power Demand Restrictions)

Since geothermal power plants are operated basically for base load and not for peak load, the geothermal power plant capacity that should be developed in a certain field is restricted by the minimum power demand in the power grid where the field is located. In this study, taking account of the future increase in power demand, an upper limit on the geothermal development scale for each field is established in line with the minimum estimated 2025 demand in the local power grid.

(5) Economic Evaluation of Power Plant Projects

Once the appropriate output capacity for geothermal development has been estimated from the resource potential and adjusted, if necessary, due to national park and/or power demand restrictions, a power plant project of the appropriate capacity for each field is economically evaluated. We adopted the Financial Internal Rate of Return (FIRR) as the index of project economy. Economic ranking for development priority of each field is treated as the second in importance after the likelihood of the presence of a geothermal reservoir, so that the development priority according to project economy is ranked within the same rank of reservoir existence possibility.

(6) Transmission Line Length for Power Plant Projects

Because PLN is basically responsible for the construction of transmission lines (T/L) relating to power plants, the cost for T/L construction does not in principle directly impact the economics of the power plant project of a developer. However, when T/L construction is considered to be a part of the whole project, the T/L length could affect the project economics. Consequently, the T/L length is considered as a supplementary factor in economic evaluation. For development projects classified into the same rank of project IRR,

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the development priority of projects that need longer T/L construction is lowered.

(7) Determination of Development Priority and Proposed Plant Capacity

From the results of the evaluation outlined above in (1) to (6), the development priority and the development scale of future projects in each field are determined.

(8) Development Plan for Each Field

Based on the proposed power plant capacity, a development plan for each field is constructed. For the plan, the recommended power unit and number of units to be installed is specified in consideration of the resource characteristics of and power demand on the field. A schedule and projected costs for the development are also presented.

(9) Formation of the Master Plan

Combining the development plans for each field, we construct a Master Plan for geothermal development (development scenario) for the whole of Indonesia, which aims at a total installed capacity of 9,500MW by 2025. The priority and timing of development for each field is established from the likelihood of reservoir presence, the project economics and the future power demand in the grid for each field. Recommendations for policies and activities required for accomplishment of the Master Plan will be described in Chapters 8 and 9.

(10) Electric Power Development Plan Compatible with the Master Plan

Based on the Master Plan for geothermal development, the electric power development plan for Indonesia, including other non-geothermal power sources was studied. This study includes consideration of optimum energy mix and the optimal role of geothermal power sources in light of the characteristics that differentiate them from other power sources.

7.1.2 Expansion and Existing Projects

The current practical plans for geothermal development/expansion projects were confirmed through interviews to developers (PERTAMINA, PLN, etc.) during a mission trip to Indonesia in June 2007 (Table 7.1.2-1). Most of the existing plans for development/expansion are for projects in the existing Working Areas and proposed by PERTAMINA or other private companies. The other projects in two fields (Ulumbu and Mataloko) have been planned by PLN as small-scale developments in remote areas. The installed capacity of the existing plans totals 1,847MW.

The existing plans for development/expansion are for geothermal fields which have already

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been developed with an existing power plant or for which the geothermal resource has been well-assessed. The planned projects, therefore, are expected to be low-risk in resource development and to be highly economical. Consequently, the existing development plans should be implemented with a higher priority than other development plans.

In addition, even if there are no concrete plans at present, future expansion projects in developed fields are also given top priority, because the expansion projects are likely to be low-risk and economical compared to development in ‘green’ fields. Future expansion plans in the G. Salak field are an example of this.

7.1.3 Geothermal Resource Evaluation

(1) Development Priority Based on Likelihood of Reservoir Presence

We assessed geothermal resource characteristics in each of 73 promising fields (70 fields originally planned by JICA plus 3 fields proposed by CGR). However, because of the lack of sufficient geoscientific data, only 50 fields among the 73 fields could be evaluated in terms of resource characteristics and capacity (Only rough estimation of resource capacity was possible for one of the 50 fields; Refer to Chapter 4).

For geothermal resource evaluation relating to development priority, we assessed the likelihood of the presence of a geothermal reservoir accompanied by high enthalpy fluids. The evaluated fields were classified into 4 ranks listed below according to the likelihood of reservoir presence.

1 ：The reservoir is ascertained by well drilling(s). (including already developed fields)

2 ：The existence of a reservoir is inferred mainly from appropriate geothermometry using chemical data concerning hot springs and fumarolic gases; The presence of a reservoir is extremely likely.

3 ：The existence of a reservoir is inferred from a variety of geoscientific information, including geological and geophysical survey data and the occurrence of high temperature manifestations.

Low ：The presence of a reservoir is unlikely; or if there is one, only a low temperature reservoir may exist. (However, the possibility of a power plant project utilizing low enthalpy fluids remains.)

In addition to the 4 ranks given above, geothermal fields where sufficient geoscientific data is not available, were classified as ‘NE’. The results of the classification of geothermal fields are shown in Table 7.1.3-1 with the results of resource capacity estimation that will be described below. The number of fields in each rank for each region is summarized below.

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Classification of likelihood of reservoir presence Region

1 2 3 Low NE

Sumatra 5 8 6 1 12 Java-Bali 9 3 2 2 6 Nusa Tenggara 2 1 4 0 1 Sulawesi 1 2 2 0 3 Maluku 0 0 2 0 1

17 14 16 3 23 Total (number of fields) 50 23

(2) Estimated Resource Potential

The geothermal resource potential for each field was estimated as the resource capacity that is thought to be practically exploitable on technical grounds, based on the calculations using the Stored-heat method. The estimations were based on the results of our calculation (Refer to Chapter 4) and a consideration of values estimated by the Government of Indonesia (CGR, MEMR) and PERTAMINA in the past. The results of estimation for each field are shown in Table 7.1.3-1 together with the data utilized for the estimation. Also, the locations of the fields (50 fields) with their estimated potential are shown in Fig. 7.1.3-1. The estimated potential for each region is tabulated below.

Region Installed Capacity

Existing Plan

Possible New/Additional

Plan

Total Resource Potential

Sumatra 2 913 5,040 5,955 Java-Bali 835 785 2,250 3,870 Nusa Tenggara 0 9 562 570 Sulawesi 20 140 770 930 Maluku 0 0 80 80

Total (MW) 857 1,847 8,702 11,405

There was too little geoscientific data for a detailed estimation of the resource potential of fields other than the 50 fields for which the resource potential was estimated in this study.. Nevertheless, from the rough estimates for these fields made by CGR-MEMR, we estimated the ‘minimum exploitable resource potential’ based on the following equation.

minimum exploitable resource potential (MW) = 1 x ("Identified" resource potential)

+ 0.2 x ("Hypothetical" resource potential) + 0.1 x ("Speculative" resource potential)

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The minimum exploitable resource potential of the 23 fields out of the 73 study fields lacking detailed estimations was calculated to be 1,050 MW in total (Table 7.1.3-2). Moreover, the minimum potential of all geothermal fields in Indonesia excluding the 73 fields was calculated to be 2,853 MW in total (Table 7.1.3-3).

7.1.4 Natural/Social Environmental Evaluation (Restriction by National Park)

Regarding the environmental impacts of projects proposed under this master plan study, some negative impacts on the natural environment, such as surface survey and test well drilling, are considered at the planning-F/S stage. Serious impacts of pollution, impacts on the natural environment and geographical features, and involuntary resettlement are expected at the construction stage, arising from geothermal well drilling, construction of power facilities and the geothermal fluid transportation system. Serious impacts of pollution and on the natural environment are expected at the operation stage due to geothermal brine and non-condensable gas emissions. On the other hand, positive impacts are expected to enhance the local economy by increasing employment opportunities, improving livelihoods, etc. Because the GHG emissions from geothermal plants are less than those from other thermal power plants, reduction of GHG emissions is expected to be another positive impact.

Based on the initial environmental examination, an environmental impact assessment of 18 fields, a geographic relation between the prospect field and the residence/protection area are good indicator for prioritizing prospect fields at the master plan-making stage. As the serious impact on a geographic relation between the prospect field and the residence area is not expect, a geographic relation between the prospect field and the protection area (national park) is used for prioritizing prospect fields.

At present, geothermal power development within the area of national parks is prohibited in Indonesia (but directional well drilling from the outside into the national park is permitted). Development of all the resource existing in the field, therefore, is not possible for geothermal prospects where some part of the area is national park. In these cases, the exploitable resource potential is reduced according to the ratio of national park area within the inferred geothermal reservoir area.

We identified the ratio of national park area within the geothermal reservoir extent, which is inferred from the results of surface surveys and well drillings, and then estimated the exploitable resource potential lying outside of national park among the potentials estimated as mentioned in 7.1.3. The ratio of national park area and the estimated resource potential lying outside of national park for each field are shown in Table 7.1.4-1. In the fields listed below, the exploitable resource potential was significantly reduced from the total existing potential because of the large ratio of national park area within the inferred geothermal reservoir area.

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Sumatra: Seulawah Agam, Lau Debuk-Debuk/Sibayak, S. Merapi - Sampuraga, Lempur/Kerinci, G. Sekincau

Java-Bali: Ijen, Bedugul

7.1.5 Power Sector Evaluation (Restriction by Power Demand)

Since geothermal power plants are operated basically for base load and not for peak load, the geothermal power plant capacity that should be developed in a certain field is restricted by the minimum power demand in the power grid where the field is located. In this study, taking account of the future increases in power demand, an upper limit on the geothermal development scale for each field is established in line with the minimum estimated 2025 demand in the local power grid.

The future power demand in each grid system was based on the “National Electricity Development Plan (RUKN) (2005)” as discussed in Chapter 5. Considering that geothermal power plants are operated basically for base load, the future upper limit on geothermal power demand (minimum demand) in each grid system was assumed to be 40% of the forecasted peak demand forecast in the RUKN. The minimum demand as of 2025 was adopted for estimation of appropriate plant capacity for future geothermal development. The minimum demand as of 2025 and the exploitable resource potential that was restricted by the demand on each field are shown in Table 7.1.5-1. The estimated potential for each region is tabulated below.

Region Installed Capacity

Existing Plan

Possible New/Additional

Plan

Total Resource Potential

Sumatra 2 913 3,605 4,520 Java-Bali 835 785 2,015 3,635 Nusa Tenggara 0 9 138 146 Sulawesi 20 140 575 735 Maluku 0 0 40 40

Total (MW) 857 1,847 6,373 9,076

Since the power demand in Sumatra and Java-Bali is considerable, the possible development capacity is restricted by demand only at the one field of Iboih-Jaboi in a small remote island (Sabang Island) at the north end of Sumatra. Incidentally, in this study, we assumed that power grids of Sumatra and Java Islands would be interconnected by submarine cable in 2012. The possible development capacity for the fields in remote island areas of Nusa Tenggara and Maluku is restricted significantly. The possible development capacity for the fields in North Sulawesi is also restricted a little.

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The geothermal resource potential (possible development capacity) evaluated as outlined above is considered to be the maximum exploitable resource potential in the 50 fields up to 2025. The locations of the 50 fields and their evaluated potential are shown in Fig. 7.1.5-1.

7.1.6 Economic Evaluation of Resources for Geothermal Power Generation

The economic values of resources for geothermal power generation are evaluated based on the estimated development scale and the characteristics of resources in 49 fields where sufficient geoscientific data has been available as presented in Chapter 4. Although the detailed methodology of the economic evaluation using a price model for geothermal power plant projects will be explained in Chapter 8, a rough outline of the evaluation method is as follows.

Firstly, the resource capacity in each field is set as the amount to be developed by 2025 (Refer to 7.1.5). The resource characteristics, such as depth of reservoir, steam production and brine flow per well, and reinjection capacity per well are established using the geothermal conceptual models presented in Chapter 4. The development period is uniformly assumed to be eight (8) years, similar to the model project shown in Chapter 8. The success rate of well-drilling is assumed to be 50% at the resource confirmation stage, 70% at the development stage, and 80% at the construction stage. The necessary number of production wells and reinjection wells is estimated from these assumptions and the resource characteristics (production and reinjection capacity per well). The diameter of production wells is uniformly assumed to be of standard size (8-1/2 inches at the final stage of drilling). The drilling cost of wells is calculated from the depth of the reservoir and a unit cost of drilling per meter (1,500 US$/m). The power plant construction cost is calculated with reference to the model power plant cost (136 M-US$ for 55 MW) and the effect of economies of scale. As for the financial conditions, the necessary costs at the surface survey stage and the resource confirmation stage are covered by the developer's own funds. All the costs at the development stage are covered by equity. At the construction stage, 70% of the construction cost is covered by commercial financing (debt) and the remaining 30% is covered by equity. The interest rate of the commercial financing is assumed to be 8.5% annually, taking international market rates into consideration.

Based on these assumptions, the profitability of the project (a financial internal rate of return: FIRR) is calculated at the electricity purchase price of 5 cents/kWh, which is close to the PLN’s current purchase price. In addition a the sensitivity analysis of purchase price increases has been carried out. These results are as shown in App. 7.1.6-1.

The results of ranking in development priority are shown in Table 7.1.6-1. These priorities are based on such factors as the existence of a development plan, the resource potential, and the economic evaluation of resource. A high priority is given in accordance with the ranking according to the likelihood of reservoir presence, and in accordance with the profitability

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indicated by the economic evaluation when the ranking on the basis of reservoir presence is the same. Profitability is classified into E1, E2, E3, and E4, in decreasing order of profitability. The calculated profitability reflects the resource potential, such as steam production per well, and the scale of reservoir, i.e. the extent economies of scale.

7.1.7 Transmission Line Length for Power Plant Projects

Because PLN is basically responsible for construction of transmission lines (T/L) relating to power plants, the cost for T/L construction does not directly impact the economy of the power plant project for the developer in principle. However, when the T/L construction is considered to be a part of the whole project, the T/L length could affect project economy. Consequently, the T/L length is utilized as a supplementary factor in economic evaluation. When development projects fall into the same rank of project IRR, the development priority of projects that need longer T/L construction is lowered.

The necessary lengths of T/L (or distribution lines) to be constructed relating to future power plant construction in each field are shown in Table 7.1.6-1 with the calculated profitability of the project (Refer to Chapter 5 for details). The necessary T/L length was treated as a supplemental factor in ranking the development priority. For fields where a development/expansion plan is currently in force or where fields are classified into the rank of NE, the necessary T/L length was ignored for evaluation. For the ranking of fields by project economy, priority was given to the classification by profitability. Where the necessary T/L length is less than 20km, the development priority of the field was left unchanged.

The development priorities of two fields, Marga Bayur and Merana, which are classified as rank 3 by resource potential and as rank E2 by profitability, were lowered due to the longer T/L length.

7.1.8 Determination of Development Priority and Proposed Plant Capacity

From the results of evaluation outlined above from 7.1.2 to 7.1.7, the development priority and the development scale of future projects in each field is determined.

The development priority of geothermal fields was determined mainly on the basis of the prior existence of a development plan, the resource potential and project economy. The determined rank is shown in Table 7.1.6-1 as ‘Development Priority’ with other parameters and information. The ranks are A, B, C, L and N in descending order of priority, but fields classified as N could be re-evaluated and possibly ranked higher than rank L as a result of further resource assessment in future. In Table 7.1.6-1, even within the same rank, the fields are placed in order of priority, based on resource probability and project economy. At the right end of the table, regardless of the development priority, some fields were marked as

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fields where small-scale geothermal development is desirable for local electrification on remote islands and/or for alternative energy development in place of diesel or other sources of power.

the development scale (power plant capacity) for each field was determined based on resource potential, ratio of National Park area and power demand in the grid (Refer to 7.1.5). The total exploitable resource potential of the fields classified into ranks A, B, C and L is 9,076MW. In addition, the total of the minimum exploitable resource potential is estimated to be 1,050MW for the fields classified into rank N, and 2,853MW for the rest of fields in the whole of Indonesia (Refer to 7.1.3).

7.1.9 Development Plan for Each Field

In accordance with the determined development scale (power plant capacity), a geothermal development plan for each field was created for the 50 fields. For the fields classified into ranks B, C and L, where no development plan exists at present, we drew up a development plan including recommended power unit and number of units in consideration of resource characteristics and power demand on the field. Additionally, we drew up a development schedule corresponding to the plan and estimated the development costs for the fields, including ones classified into rank A. The development plan sheets containing the results of various kind of evaluations are shown in Table 7.1.9-1 for the fields of rank B, C and L, and in Table 7.1.9-2 for the fields of rank A.

(1) Development Plan (for the fields of Rank B, C and L)

Considering the resource characteristics of and power demand on the field, we drew up a development plan including recommended power unit and number of units. Ordinary condensing type power units are recommended for most of the fields, while back-pressure type units are also thought to be suitable for small-scale development or development in fields where variable load operation is expected. Binary type units are recommended for fields where only low enthalpy fluids are expected.

The number of power units was set such that the system trip of a single unit would not significantly impact the power grid in consideration of grid capacity.

The number of wells required for development was estimated based on the production and reinjection capacity per well that is determined from the resource characteristics of the field. The diameter of production wells is uniformly assumed to be of standard size (8-1/2 inches at the final stage drilling: “Standard Hole”).

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(2) Development Process and Schedule

The development process consists of four stages, namely the preliminary survey, exploration, exploitation and operation stages.

At the preliminary survey stage, in order to estimate the resource potential and determine the target for well drilling, several surface surveys, including geological, geochemical and geophysical (electro-magnetic) surveys, are carried out by governmental organizations or private developers. The results of these surveys provide minimum necessary information on the geothermal resource to allow for tendering for development rights in the geothermal field (Working Area) and deciding the project developer. The results of these surveys also provide the necessary information for selecting the well-drilling location(s).

The exploration stage of development is implemented by the project developer. At the exploration stage, exploratory wells are drilled after construction of access roads and well site preparation. Several well tests are conducted at the drilled wells. The collected test data are utilized for geothermal reservoir assessment, and the exploitable resource potential is estimated.

At the exploitation stage, an environmental impact evaluation is carried out in accordance with the development scale. After the environmental monitoring plan, environmental management plan and environmental impact assessment statement (only for geothermal power plants larger than 55MW) are accepted, the developer executes full-scale field development, drilling and testing of production and reinjection wells, construction of a fluid collection/reinjection system (FCRS) and power plant. Basically, PLN is responsible for construction of transmission lines (T/L) relating to power plants. The exploitation proceeds up to the development of all the exploitable resource potential.

Operation and maintenance of the constructed geothermal power plant is performed at the operation stage.

We assumed a basic implementation period for each stage, as shown in Table 7.1.9-3. We assumed one (1) year for surface surveys at the preliminary survey stage, one (1) year for tendering for the Working Area, and two and a half (2.5) years for well drilling and testing at the exploration stage. Also, one (1) year was assumed for the environmental impact assessment and one (1) year for field development at the exploitation stage. We estimated the drilling period per well to require from one and a half (1.5) to three (3) months according to the drilling depth, and allowed a period of three (3) months for testing each production well. The period for FCRS and power plant construction depends on the plant capacity, so we assumed from 18 to 24 months for the FCRS, and from 24 to 30 months for power plants with a capacity of 10-110MW.

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In the planned development schedule, the preliminary survey stage and exploration stage are omitted for some fields (mainly the fields of rank A) where a power plant has already been built or surface surveys and exploratory well drillings have been conducted. We planned schedules with the minimum period necessary to develop all the exploitable resource potential in each field.

(3) Development Costs

The estimated development costs, including costs from preliminary survey to power plant construction for the assumed geothermal power plant projects in each field, are shown in App. 7.1.9-1. The estimated development costs are used for economic evaluation in 7.1.6.

7.1.10 Formation of the Master Plan

Based on the results of various studies and considerations mentioned in sections 7.1.2 to 7.1.9, we constructed a Master Plan for geothermal development (development scenario) for the whole of Indonesia up to 2025. The Master Plan is a feasible development plan from the resource, technical and social perspectives, and should be treated as a target for future development. Note that the Master Plan does not take account of the actual participation of developers necessary for realizing the plan.

We constructed a geothermal development plan for the whole of Indonesia up to 2025, based on the development priority and exploitable resource capacity of each field. These were evaluated on the basis of the existence of a development plan, the resource potential, National Park area involved, power demand and project economy (Refer to Table 7.1.6-1). Individual development plans for each field were combined to produce the Master Plan (Refer to Tables 7.1.9-2 and 7.1.9-3). The final goal of the Master Plan is to develop 9,500MW of capacity in total by 2025, as indicated in the Geothermal Development Roadmap. In the formation of the Master Plan, we placed the timing of commencement of development and power plant operation in consideration of the forecasted power demand in each grid (Refer to Chapter 5) as well as the development schedules for each field described in the previous section.

The ‘fastest case’ Master Plan is shown in Table 7.1.10-1. For the fields of rank A, we assumed continuous expansion plans up to 2025 following the existing plans for each field. The development rights for the Working Area of most of the fields of rank B or C are assumed to be put out to tender in 2009, allowing one year for the preliminary survey and preparation of the tender. Earlier tendering would be possible for the Lempur/Kerinci field because the existence of the geothermal reservoir in the field has been already ascertained by well drillings. The tendering for the Suwawa-Gorontalo field has been postponed because of the restriction on development capacity by the power demand in the Minahasa grid. The timing of development in fields of rank L has also been postponed to set the

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completion of development at 2025, because development in these fields involves a high risk connected with the resource potential and is unlikely to expand to large-scale development. We assumed that the development capacity in the fields of rank N would reach 424MW (or greater), which makes up for 9,500MW if all the exploitable resource in the fields of ranks A, B, C, and L is developed. For the fields of rank N, the exploitable resource capacity in each field cannot be estimated at present, but a total capacity larger than 1,050MW is expected (Refer to 7.1.3). Since the resource risk is still high and further resource assessment is necessary for development in these fields of rank N, the timing of development in the fields has also been postponed to set the completion of development at 2025.

The ‘fastest case’ Master Plan , as described above, is able to achieve the development of 9,500MW by 2025, with some time to spare. On the other hand, in this ‘fastest case’, the tendering for Working Areas for the 23 fields has to be carried out at the same time within a single year, meaning that the time for preliminary surveys and tender preparation does not seem to be sufficient. Accordingly, we also constructed a ‘practical case’ Master Plan, in which the timing of commencement of development (the tender) is postponed one or two year(s) for some fields of rank B and C (Table 7.1.10-2). In this case, the development of the fields of rank B and C is launched from fields having a higher development priority, and the tenders for 23 fields are carried out over three years at a rate of seven or eight fields per year. The ‘practical case’ Master Plan can also achieve the development of 9,500MW by 2025. The rate of development for the ‘practical case’ is not delayed significantly compared with the ‘fastest case’, as shown in Fig. 7.1.10-1. The faster commencement of development at a larger number of fields is, of course, preferable when aiming for larger capacity development, but it is also important that reliable development be steadily implemented to realize practical targets.

The ‘practical case’ Master Plan for each region (power grid) is shown in Tables 7.1.10-3 and 7.1.10-4. Regarding development in fields of rank N, since the development capacity in each field cannot be determined at present, the development capacity is arbitrarily assumed to be 200MW in Sumatra, 200MW in Java-Bali and 24MW in Central and South Sulawesi. The annual cumulative capacity achievable through future development up to 2025 is shown in Fig. 7.1.10-2 for the whole of Indonesia and in Fig. 7.1.10-3 for each region. Although the developed fields are concentrated in Java-Bali at present, development in the future would be centered on the fields in Sumatra in order to achieve large capacity development. The development capacity in other remote island regions would be relatively small because of the small power demand in these regions.

It should be re-emphasized that the Master Plan is a realistic development plan from the resource, technical and social perspectives, but does not take account of the actual participation of developers necessary for realizing the plan. Necessary future actions and policies of the government of Indonesia to realize the plan will be discussed in Chapters 8

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and 9.

7.1.11 Electric Power Development Plan Compatible with Geothermal Development Master Plan

(1) Considerations for Electric Power Development Plan compatible with Energy Mix

The “National Electricity Development Plan (RUKN) (2005)” shows a necessary electric power development plan based on the forecast of electricity demand mentioned in the previous chapter (Chapter 5, Section 5.1.2). This plan is formulated based on a philosophy of the “Least Cost Policy on the supply side.” This could be one of the policies in formulating such a plan. However, as a result of this policy, steam power plants (coal fired plants) play a central role as future electric power sources, and it is envisaged that geothermal energy will account for only 3.7% of electric power and 1.2% of primary energy (Note: on the assumption that the electrification rate in 2025 is 34%). Accordingly, in this case, the accomplishment of an energy mix based on the “Presidential Decree on National Energy Policy (No. 5, 2006)” will be very difficult (Tables 7.1.11-1 and 7.1.11-2, Figs. 7.1.11-1 to 7.1.11-3).

To avoid such a failure, it is necessary to formulate an alternative electric power development plan which is compatible with the Master Plan for geothermal development and which is also based on the same electricity demand forecast shown in Chapter 5. In this process, the “Energy Mix Policy” declared in the “Presidential Decree on National Energy Policy (No. 5, 2006)“ replaces the “Least Cost Policy” as the basic guiding philosophy for plan formulation.

(2) Economy and Role of Electric Power Plants by Type

Prior to formulating an alternative power development plan, the economy and the role of each type of electric power plant should be studied. Such study needs to be done for large-scale systems and for small-scale systems separately, because the scale of the power plants is different. In this section, the necessary selling prices of electricity from each power plant are calculated based on the specification shown in Table 7.1.11-3, and the results are shown in Table 7.1.11-4 and Fig. 7.1.11-4. These selling prices are calculated to ensure an investment return of 15%. These selling prices can be divided into fixed prices and variable prices. The variable price is a price designed to recover fuel costs and the fixed price is to recover other costs such as the initial investment costs, additional investment costs, the administrative and maintenance costs, the interest on borrowed funds, and the return on investment. Therefore, the selling price of electricity from each power plant changes according to the utilization of the power plant.

As it happens, the Java-Bali system is an extremely large-scale system which had a peak

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demand of 14,310 MW in 2004. The Sumatra system, which has a peak demand of 2,530 MW, is the second biggest large-scale system. The remaining systems are small-scale systems with peak demand of 500 MW or less. In large-scale systems such as the Java-Bali or Sumatra system, sophisticated large-scale thermal power plants in the 600 MW class will be built. In small-scale systems, small-scale power plants in the 50 MW class will be built. Therefore, the economy of power plants in these two classes has been calculated. Figure 7.1.11-5 shows the economy of power plants by types and the nominal load duration curve in the Java-Bali system, and Fig. 7.1.11-6 shows the economy of power plants by types and the nominal load duration curve in the Minahasa system of north Sulawesi, as an example of a small-scale system.

In the Java-Bali system, highly efficient coal thermal power plants of 600 MW can be built with great economies of scale. Therefore, they are economically superior to other types of power plants in the range of 40% availability or more. In a range of availability lower than 40%, the economy of gas combined cycle plants is superior. Therefore, it is appropriate that gas combined cycle plants be used as peak load suppliers, supplying the need for electricity with an availability of 40% or less. It is also reasonable that coal power plants be used as middle load suppliers and/or base load suppliers, supplying the need for electricity with an availability of 40% or more. Moreover, from the technical view point, it is also appropriate to use gas combined cycle plants as peak load suppliers because the start-up speed of the plants is excellent, as is their responsiveness in tracking power demand through output adjustment. The graph shows that the system needs about 30% of peak load suppliers, about 30% of middle load suppliers, and about 40% of base load suppliers in a large-scale system. In such a large-scale system, to our regret, the economy of geothermal power plants is less than that of large-scale coal power plants. However, in consideration of the “Energy Mix Policy”, geothermal power plants will be used as a base load suppliers as well as coal power plants.

In small-scale systems, the economy of coal power plants diminishes because the advantages of economies of scale in construction cost disappear. Therefore, the economy of geothermal power plants surpasses that of coal power plants in the range of 95% or greater availability. In such a case, it is recommended that geothermal power plants be used as base load suppliers, satisfying not only the “Energy Mix Policy” but also the “Least Cost Policy”. In such systems, coal power plants will be used as middle load suppliers, and the composition of the power supply will be about 40% peak load suppliers, about 40% middle load suppliers, and about 20% base load suppliers.

(3) Electric Power Development Plan Compatible with Geothermal Development Master Plan

Based on these studies, the power plant development plan of RUKN (2005) was adjusted to accommodate geothermal development. In many systems, the capacity of coal power plants

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was reduced in light of the ideal ratio among peak load suppliers, middle load suppliers, and base load suppliers. (Table 7.1.11-5)

As a result, a power source composition in 2025 is assumed as shown in Table 7.1.11-6 and Figs. 7.1.11-7 to 7.1.11-9. It is thought that the energy mix of the “Presidential Decree on National Energy Policy (PD No. 5 / 2005), which specifies that 5% or more of primary energy be supplied by geothermal energy, will be achieved by 2025. The electric power development plans for systems that are compatible with the geothermal development master plan are shown in Tables 7.1.11-7 to 7.1.11-13.

7.2 Geothermal Development Database

7.2.1 Outline of the Geothermal Development Database

In order to promote geothermal power development in Indonesia it is indispensable to prepare the database that manages information necessary for geothermal power development such as 1) geothermal resources, 2) Social and Environment, and 3) Transmission line. In other words, we should construct the database that can manage the information not only geothermal resources, but also social and environment conditions surrounding the prospective area (including environmental constraints such as protected forests), and also transmission line conditions close to the prospective area. The geothermal development database was, therefore, constructed to integrate the information of the above three kind of categories, and then installed into the server at the Center for Geological Resources (CGR) in Bandung.

In this database the check boxes for defining “open information” or “close information” were made so that the database can be easily used as an “open database” in the future, which should open information to public. In addition, another function for editing the contents of information open to public was also made so that quality and quantity of the information can be arranged before opening.

7.2.2 Contents of Geothermal Development Database

Examples of data input windows of geothermal development database are shown in Fig.7.2.2-1 to 7.2.2-12. When logging in the database you can see a whole Indonesia map and the purpose with outline of the database on the left column of the map. The switch columns for selecting 1) geothermal resources, 2) policy, social and environment, 3) transmission line are lower part of the window, in which the respective information relating to geothermal development in Indonesia is described. Four detailed maps of Sumatera Island, Java Island, Sulawesi Island and Nusa Tenggara Islands are selected from the whole Indonesia map. On the four island maps there are red circles representing geothermal prospective fields. Menu-window of individual field, which has three switch columns on the

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lower part of the window for selecting 1) geothermal resources, 2) social and environment, and 3) transmission line at individual field, is displayed by clicking the red circle. Furthermore, the sub-window of 1) geothermal resources has four kinds of detailed information a) geothermal structural model, b) chemical conditions, c) well productivity, d) resource potentials, and figure of geothermal conceptual model. That of 2) social and environment has four kinds of detailed information of a) social and economic conditions, b) residence precipitation of geothermal development plan, c) flora and fauna, d) climate condition, and map of land use. That of 3) transmission line has three kinds of detailed information of a) line voltage, b) line length, c) line connection, d) others, and map of transmission line. Items of information that can be managed by this database are shown in Table 7.2.2-1.

The information of 73 geothermal prospective fields, which were collected through the Master Plan Study, were already input into the database. Methods of operation and maintenance of the database were transferred to the staffs of CGR so that they can manage and update the information for the database by themselves. The operation manual of the database is attached as another document.

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7.3 Application of CDM Project

The geothermal power generation is considered that the amount of the CO2 emission at the life cycle is less than that of other power supplies (CRIEPI, 2000). For instance, the coal-fired generation exhausts 65 times CO2 compared with the geothermal power generation (Fig. 7.3-1). The amount of CO2 exhausted from the geothermal power plant of 9500MW, which assumed to be a target until 2025 in Indonesia, is equal to the amount of CO2 exhausted from the coal- fired power plant of 150MW.

Moreover, the geothermal power plant generates an electric power that is high utilization rates, bigger than the other renewable energy. Therefore, a big effect of the CO2 emission reduction can be expected, it is attractive as the CDM project.

In this chapter, the effect of CO2 emission reduction by geothermal power generation in Indonesia was provisionally calculated from the amount of the resource that will be able to be developed by 2025. And, to contribute to the geothermal development promotion in this country by the geothermal power development being implemented as CDM project, model PDD’s (Project Design Document) are prepared.

Source: Modify Denchuken News No.338 (CRIEPI,2000）

Fig. 7.3-1 CO2 Emission by Power Source

0.130

0.088

0.408

0.478

0.704

0.887

0.038

0.053

0.011

0.015

0.022

0.029

0.111

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

Mini Hydro

Geothermal

Nuclear

Wind

Solar

LNG Combined

LNG Thermal

Oil Thermal

Coal Thermal

Pow

er S

ourc

e

CO2 Emission Factor (t-CO2/MWh)

Facility/OperationFuel for Power Generation

0.975

0.608

0.742

0.519

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7.3.1 CDM Project Potential in Indonesia

The emission reduction is estimated as potential of CDM project in Indonesia, which was assumed as oil substitution effort, based on the amount of possible additional geothermal development by 2025 that excluded existing and the planning geothermal power project. CO2 Conversion Volume (emission factor) =

crude oil conversion of energy substitution(ktoe/y) ×42.62×20×0.99×44/12

Where, ① Energy substitution effect (crude oil conversion ktoe/y）

Heating value conversion of crude oil 10,000 kcal/kg Heating value conversion of electricity 2,646 kcal/kWh

② Conversion to unit of energy (heating unit: TJ) Conversion factor 42.62 TJ/kt

③ Conversion to base unit of carbon discharge Base unit factor of carbon discharge 20 tC/TJ

④ Correction of incomplete combustion portion Oxidation rate factor of carbon 0.99

⑤ Conversion to CO2 Molecular weight ratio 44/22

From above formula, CO2 conversion volume (emission factor) is calculated 0.819(t-co2/MWh). The amount of the emission reductions of each field are presumed from the following formula by the annual power generation assuming the utilization rates of the geothermal plant to be 85%. Annual power generation (MWh/year) =

Development resource potential (MW) × 24(h/day) × 365 (day) × utilization rates (%) Annual emiision reduction(kt-co2//year) ＝

Emission factor (t-co2/MWh) × annual power generation (MWh/year)

The calculations are shown in Table 7.3.1-1.

The effect of annual CO2 emission reduction of the 10MW geothermal power plant is 61 (kt-co2/year). If the new geothermal plant will be constructed as CDM project, the effect of the emission reduction of 50,122 (kt-co2//year) is expected.

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The additions of geothermal power plant by 2020 2016 2012 and 2025 become 1117MW, 2077MW, 4994MW and 8219MW respectively, are shown in Table 7.1.10-2. When CER (Certified Emission Reduction) value is 10 (US$/t-CO2), 68, 127, 305 and 501 (Mil.US$/year) of profits are expected respectively (Fig. 7.3.1-1).

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Table 7.3.1-1 CO2 Emission Reduction Effect

Annual Generation Annual CO2 Reduction

(GWh/year) (103 t-CO2/year)Aceh 1 IBOIH - JABOI 10 74 61Aceh 3 SEULAWAH AGAM 275 2,048 1,677

SumUta 7 LAU DEBUK-DEBUK / SIBAYAK 38 283 232SumUta 8 SARULA 330 2,457 2,012SumUta 9 SIBUAL BUALI 300 2,234 1,829SumUta 10 S. MERAPI - SAMPURAGA 100 745 610SumBar 13 MUARALABUH 240 1,787 1,464SumBar 14 G. TALANG 30 223 183Jambi 15 LEMPUR / KERINCI 20 149 122Jambi 17 SUNGAI PENUH 355 2,643 2,165

Bengkulu 21 B. GEDUNG HULU LAIS 455 3,388 2,775Bengkulu 22 TAMBANG SAWAH 455 3,388 2,775SumSel 24 MARGA BAYUR 170 1,266 1,037SumSel 25 LUMUT BALAI 620 4,617 3,781

Lampung 27 ULUBELU 440 3,276 2,683Lampung 28 SUOH ANTATAI 330 2,457 2,012Lampung 29 G. SEKINCAU 60 447 366Lampung 30 RAJABASA 120 894 732Lampung 31 WAI RATAI 120 894 732JavaBar 32 KAMOJANG 180 1,340 1,098JavaBar 33 G. SALAK 120 894 732JavaBar 34 DARAJAT 185 1,378 1,128JavaBar 35 CISOLOK - CISUKARAME 180 1,340 1,098JavaBar 36 G. PATUHA 500 3,723 3,049JavaBar 37 G. WAYANG - WINDU 290 2,159 1,768JavaBar 38 G. KARAHA 200 1,489 1,220JavaBar 39 G. TELAGABODAS 200 1,489 1,220JavaBar 40 TANGKUBANPERAHU 20 149 122Banten 42 CITAMAN - G. KARANG 20 149 122

JavaTen 44 DIENG 340 2,532 2,073JavaTen 46 TELOMOYO 50 372 305JavaTen 47 UNGARAN 180 1,340 1,098JavaTim 50 WILIS / NGEBEL 120 894 732JavaTim 51 IJEN 40 298 244

Bali 52 BEDUGUL 175 1,303 1,067NTB 53 HU'U DAHA 30 223 183NTT 54 WAI SANO 10 74 61NTT 55 ULUMBU 36 268 220NTT 56 BENA - MATALOKO 20 149 122NTT 57 SOKORIA - MUTUBUSA 20 149 122NTT 58 OKA - LARANTUKA 20 149 122NTT 60 ATADEI 10 74 61

SulUta 61 LAHENDONG 200 1,489 1,220SulUta 62 KOTAMOBAGU 140 1,042 854SulUta 63 TOMPASO 120 894 732SulTen 65 MERANA 200 1,489 1,220Maluku 69 TULEHU 20 149 122

N.Maluku 70 JAILOLO 20 149 122SumUta 71 SIPAHOLON-TARUTUNG 50 372 305

Golontaro 73 SUWAWA-GOLONTALO 55 410 335 TOTAL 8219 61,199 50,122

Existing Power Plant Emission Factor (t-CO2/MWh) = 0.819Load Factor = 85%

Existing Project

Additional Power Plant(MW)Region No Names of the 70 fields in this Survey

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Fig. 7.3.1-1 Profit by CER’s Sales

7.3.2 Model PDD for the geothermal power project of Indonesia as CDM

If the value of CER is 10 (US$/t-CO2) under the emission factor 0.819(t-CO2/MWh), earning of about 0.8(cent/kW) is obtained when the geothermal power generation is executed as CDM business in Indonesia (Fig. 7.3.2-1). This is one of the incentives of the geothermal power development.

Fig. 7.3.2-1 CER’s Price

0

100

200

300

400

500

600

700

800

900

1000

1100

0 2 4 6 8 10 12 14 16 18 20 22CER's Unit Price (US$/t-CO2)

Prof

it by

CER

's Sa

les (

Mil.

US$

/yea

r)

Year 2012 (1117MW)Year 2016 (2077MW)Year 2020 (4994MW)Year 2025 (8219MW)

0.16

0.33

0.49

0.66

0.82

0.98

1.15

1.31

1.47

1.64

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

0 2 4 6 8 10 12 14 16 18 20 22CER's Unit Price (US$/t-CO2)

CER

's U

nit P

rice

(cen

t/kW

h (E

miss

ion

Fact

or 0

.819

t-CO

2/kW

h)

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PDD (Project Design Document) of Darajat Ⅲ geothermal power development project in Indonesia is registered in the CDM executive board on December 11, 2006. This is a geothermal power development project of installed capacity 110MW in the central Java island.

The model PDD’s are made for 55MW geothermal power generation of Muaralabuh field in Sumatra and 10MW small-scale geothermal power generation of Sukoria in Flores, which indicate that all of geothermal power development project in Indonesia are possible to be CDM project.

(1) Input Items in PDD

The Project participants who develop a CDM project activity should first prepare PDD and submit it to EB for validation and registration.PDD should be include the description of project activity with application of baseline methodology and monitoring methodology. It is recommended to refer to the latest version for "Guideline for completing the project design document(CDM-PDD), and the proposed new baseline and monitoring methodoligies (CDM-NM)", which describes a detailed explanation concerning the PDD format and the glossary related to CDM. The latest PDD format and the guideline can be downloaded from the following websites:

http://cdm.unfccc.int/Reference/Documents

The items by PDD format version 03 that became effective 28 days July, 2006 after is as follows.

Section A. General description of project activity

A.1. Title of the project activity A.2. Description of the project activity A.3. Project participants A.4. Technical description of the project activity

A.4.1. Location of the project activity A.4.1.1. Host Party(ies) A.4.1.2. Region/State/Province etc. A.4.1.3. City/Town/Community etc. A.4.1.4. Detail of physical location, including information allowing the

unique identification of this project activity: A.4.2. Category(ies) of project activity A.4.3. Technology to be employed by the project activity A.4.4. Estimated amount of emission reductions over the chosen crediting period A.4.5. Public funding of the project activity

Section B. Application of a baseline and monitoring methodology

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B.1. Title and reference of the approved baseline and monitoring methodology applied to the project activity

B.2. Justification of the choice of the methodology and why it is applicable to the project activity

B.3. Description of the sources and gases included in the project boundary B.4. Description of how the baseline scenario is identified and description of the

identified baseline scenario B.5. Description of how the anthropogenic emissions of GHG by sources are reduced

below those that would have occurred in the absence of the registered CDM project activity (assessment and demonstration of additionality)

B.6. Emission reductions B.6.1. Explanation of methodological choices B.6.2. Data and parameters that are available at validation B.6.3. Ex-ante calculation of emission reductions B.6.4. Summary of the ex-ante estimation of emission reductions

B.7. Application of the monitoring methodology and description of the monitoring plan

B.7.1 Data and parameters monitored B.7.2 Description of the monitoring plan

B.8. Date of completion of the application of the baseline study and monitoring methodology and the name of the responsible person(s)/entity(ies)

Section C. Duration of the project activity / Crediting period C.1. Duration of the project activity

C.1.1. Starting date of the project activity C.1.2. Expected operational lifetime of the project activity

C.2. Choice of crediting period and related information C.2.1. Renewable crediting period

C.2.1.1. Starting date of the 1st crediting period C.2.1.2. Length of the 1st crediting period

C.2.2. Fixed crediting period C.2.2.1. Starting date C.2.2.2. Length

Section D. Environmental impacts D.1. Documentation on the analysis of the environmental impacts, including

transboundary impacts D.2. If environmental impacts are considered significant by the project participants

or the host Party, please provide conclusions and all references to support documentation of an environmental impact assessment undertaken in accordance with the procedures as required by the host Party

Section E. Stakeholders’ comments E.1. Brief description of how comments by local stakeholders have been invited and

compiled

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E.2. Summary of the comments received E.3. Report on how due account was taken of any comments received

Annex 1. Contact information on participants in the project activity Annex 2. Information regarding public funding Annex 3. Baseline information Annex 4. Monitoring information

General information of the project activity is described in Section A. This section has a role to show the whole image of the CDM project that include the important information of all items of PDD.

The application of the baseline and the monitoring methodology is described in section B. This section is described regarding most important baseline scenario, additionality, emission reduction, and application/planning of monitoring methodology.

Project additionality, baseline scenario and project boundary are explained using registered baseline methodology or new baseline methodology which is proposed with PDD. It is necessary to confirm there is applicable methodology or not by application condition of methodology, which is approved by EB shown in EB website. It is necessary to propose a new methodology if there is no methodology that can be applied to the project. The amount of the GHG emission reduction is shown by calculation which is conducted by necessary formula for estimating the amount of the GHG emission reduction. The amount of the GHG emission reduction is estimation at the PDD making stage, it is necessary to verify CER using monitoring results. The CER’s issuance will be done after certificating by DOE.

The project participants will decide and consider that what data, and what quality (Accuracy, Comparability, Completeness, Validity) should be collected with referencing the guideline of applied methodology. The monitoring plan is described to Annex4. The monitoring plan should provide detailed information on the collection and saving all the associated data necessary to do the following.

・Estimation and measurement of amount of emission, which generated in project boundary

・Identification of baseline ・Specification of increasing amount of emission outside project boundary

The monitoring plan is described according to the instructions and the step, which is defined by the approved monitoring methodology. The project participant carries out the registered monitor plan, and submits data by the monitoring report. It is important to pay attention to

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the regulation, that is, the monitoring data should be maintained until a late date among two years, at the end after credit period or after issuing the latest CER.

The crediting period and duration of the project activity is described in section C. The crediting period means the period when CER is issuing and the period of verification and the issuance of the emission reduction from the baseline by DOE. After the date when the first amount of the emission reduction is issued by the CDM project activity, the start date of the crediting period is set. Accordingly, the crediting period should be set in the period of the CDM project activity. The crediting period begins after the date when the CDM project activity was registered in principle. The project participant will select the period from the following two approaches in PDD. The crediting period selects in consideration of the project life that is a matter greatly related to the business and the risk of the project.

1. Renewable crediting period A maximum of 7 years which may be renewed at most 2 times For each renewal, a

DOE determines and informs the EB that the original project baseline is still valid or has been updated taking account of new data where applicable.

2. Fixed crediting period A maximum of 10 years with no option of renewal.

The environmental impact analysis in and around the project area concerned is described in section D. If environmental impacts are considered significant by the project participants or host party, it is necessary to provide conclusions and all references to support documentation of an environmental impact assessment undertaken in accordance with the procedures as required by the host Party.

It is described that how comments by local stakeholders have been invited and compiled and how due account was taken of any comments received in section E.

(2) Supplemental Explanation for Preparing PDD

A supplementary explanation for preparing PDD, which is useful for reference of the geothermal power generation project participant in Indonesia, is described as follows.

(a) Project Activity

The project name”Geothermal power development project” should be included in the CDM project title. The types of applicable technologies for geothermal power generation are as follows;

back-pressure turbine generation Flash steam electric power condensing turbine generation（single flash system or double flash system） Binary cycle system generation

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Total flow generation

The description should be used figures and tables for easy understanding. The category of the geothermal project is sectoral scope 1: Energy Industries (renewable/ non-renewable sources)

Immediate cooperation of CDM and ODA granting is prohibited by regulations, but in case of the CDM project selected as ODA project, which ODA granting has negotiated with developing country, in results is excluded. (wind power project in Egypt is approved by EB on June 22th, 2007 that is supporting by JBIC)

(b) Selection of Methodology（PDD SectionB.1, B.2）

The applicable methodologies for geothermal power project are as follows.

＜ACM0002 ver.6＞

Consolidated methodology for grid-connected electricity generation from renewable sources

【Applicability】

This methodology is applicable to grid-connected renewable power generation project activities under the following conditions:

• Applies to electricity capacity additions from: • Run-of-river hydro power plants; hydro power projects with existing reservoirs

where the volume of the reservoir is not increased. • New hydro electric power projects with reservoirs having power densities

(installed power generation capacity divided by the surface area at full reservoir level) greater than 4 W/m2

• Wind sources; • Geothermal sources; • Solar sources; • Wave and tidal sources.

This methodology is not applicable to project activities that involve switching from fossil fuels to renewable energy at the site of the project activity, since in this case the baseline may be the continued use of fossil fuels at the site;

The geographic and system boundaries for the relevant electricity grid can be clearly identified and information on the characteristics of the grid is available; and

Applies to grid connected electricity generation from landfill gas capture to the extent that it

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is combined with the approved "Consolidated baseline methodology for landfill gas project activities" (ACM0001).

＜AM0019 ver.2＞

Renewable energy project activities replacing part of the electricity production of one single fossil-fuel-fired power plant that stands alone or supplies electricity to a grid, excluding biomass projects

【Applicability】

This methodology is applicable to:

Proposed project activities where electricity production from the zero-emission renewable energy sources: wind, geothermal, solar, run-of-river hydro, wave and/or tidal projects that displaces electricity production from an identified, individual, plant;

New hydro electric power projects with reservoirs having power densities (installed power generation capacity divided by the surface area at full reservoir level) greater than 4 W/m2.

Where the identified baseline plant has sufficient capacity to meet the increase of demand expected during the crediting period.

＜AM0026 ver.2＞

Zero-emissions grid-connected electricity generation from renewable sources in Chile or in countries with merit order based dispatch grid

【Applicability】

The methodology is applicable to proposed electricity capacity additions that meet the following conditions:

1) Projects that are renewable electricity generation projects of the following types:

(a) Run-of-river hydro power plants and hydro electric power projects with existing reservoirs where the volume of the reservoir is not increased;

(b) New hydro electric power projects with reservoirs having power densities (installed power generation capacity divided by the surface area at the full reservoir level) greater than 4 W/m2.2

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(c) Wind sources;

(d) Solar sources;

(e) Geothermal sources;

(f) Wave and tidal sources.

2) Projects that are connected to the interconnected grids of the Republic of Chile and Projects that fulfils all the legal obligations under the Chilean Electricity Regulation; or Proposed projects implemented in countries other than Chile provided the country has a regulatory framework for electricity generation and dispatch that meets the following conditions:

(a) An identifiable independent identity is responsible for optimal operation of the system based on the principle of lowest marginal costs.

(b) The data for merit order based on marginal costs is publicly made available by the authority responsible for operation of the system.

(c) The data on specific fuel consumption for each generation source in the system is publicly available.

(d) It is possible with the information available, to ensure that power plants dispatched for other considerations (e.g. safety conditions, grid stability, transmission constraints, and other electrical reasons) are not identified as marginal plants.

The methodology is not applicable to:

1) The proposed CDM project activities that involve switching from fossil fuels to renewable energy at the site of the project activity, and

2) if the baseline is the continued use of fossil fuels at the site.

＜Indicative simplified baseline and monitoring methodologies for SSC project activity＞ Type I: Renewable energy project activities with a maximum output capacity equivalent to up to 15 MW(or an appropriate equivalent), solar lay, solar heat, wind, hubrid system, biogas, hydro, geothermal etc.

AMS I.A (ver10) Electric generation by user

AMS I.D (ver 11) Renewable electricity generation for a grid

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(c) Project Boundary（PDD Section B.3）

The project boundary shall encompass all anthropogenic GHG emissions by sources under the control of the PPs that are significant and reasonably attributable to the CDM project activity.

Geothermal power development in Indonesia is assumed to be done by IPP as CDM project. Transmission line for the geothermal power plant is responsible to PLN. Thus the metering point is the entrance of power to substation which is constructed by PLN. Accordingly, The project boundary is geothermal wells, pipe lines, power station and transmission line until substation.

(d) Identify Baseline Scenarios（PDD Section B.4）

The baseline (scenario and emissions) for a CDM project activity is the scenario that reasonably represents GHG emissions that would occur in the absence of the proposed project activity. The baseline scenario of ACM0002 is “For project activities that do not modify or retrofit an existing electricity generation facility, the baseline scenario is the following: Electricity delivered to the grid by the project would have otherwise been generated by the operation of grid-connected power plants and by the addition of new generation sources”

As base line scenario for small scale CDM has already been fixed, the baseline emission can calculate easily.

(e) Additionality (PDD Section B.5)

Explanation of how and why this project activity is additional and therefore not the baseline scenario in accordance with the selected baseline methodology. Most of the approved methodology refer the”Tool for the demonstration and assessment of additionality” ,which is approved by EB.

Step 1. Identification of alternatives to the project activity consistent with current laws and regulations

Sub-step 1a. Define alternatives to the project activity:

Identify realistic and credible alternative scenario(s) available to the PPs or similar project developers that provide outputs or services comparable with the proposed CDM project activity.

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Sub-step 1b. Enforcement of applicable laws and regulations:

The alternative scenario(s) shall be in compliance with all mandatory applicable legal and regulatory requirements. If an alternative does not comply with all mandatory applicable legislation and regulations, then show that those applicable legal or regulatory requirements are systematically not enforced;

If the proposed project activity is the only alternative amongst the ones considered by the PPs that is in compliance with all mandatory regulations with which there is general compliance, then the proposed CDM project activity is not additional.

Step 2. Investment analysis

Determine whether the proposed project activity is economically or financially less attractive than at least one other alternative, identified in step 1, without the revenue from the sale of CERs.

Sub-step 2a. Determine appropriate analysis method:

If the CDM project activity generates no financial or economic benefits other than CDM related income, then apply the simple cost analysis (Option I). Otherwise, use the investment comparison analysis (Option II) or the benchmark analysis (Option III).

Sub-step 2b

Option I. Apply simple cost analysis

Document the costs associated with the CDM project activity and demonstrate that the activity produces no economic benefits other than CDM related income

Option II. Apply investment comparison analysis

Identify the financial indicator, such as IRR, NPV, cost benefit ratio, or unit cost of service most suitable for the project type and decision-making context.

Option III. Apply benchmark analysis

Identify the financial indicator. Identify the relevant benchmark value. Benchmarks can be derived from government bond rates, estimates of the cost of financing and required return on capital, and a company internal benchmark.

Sub-step 2c. Calculation and comparison of financial indicators (only applicable to

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options II and III):

Present in the CDM-PDD a clear comparison of the financial indicator for the proposed CDM activity (excluding CER revenues) and:

The alternatives if Option II is used, or the financial benchmark if Option III is used. If the CDM project activity has a less favourable indicator, then the CDM project activity cannot be considered as financially attractive.

Sub-step 2d. Sensitivity analysis (only applicable to options II and III):

Include a sensitivity analysis that shows whether the conclusion is robust to reasonable variations in the critical assumptions.

The geothermal power generation can be proven to be not attractive from the comparison of profitabilities with the coal-fired generation in Indonesia by using Option II. It is possible to show the bench mark to fall below the in- house standard of the project profitability for the IPP without CDM.

Step 3. Barrier analysis

Determine whether the proposed project activity faces barriers that prevent the implementation of this type of proposed project activity, and do not prevent the implementation of at least one of the alternatives. Provide transparent and documented evidence, and offer conservative interpretations of this documented evidence, as to how it demonstrates the existence and significance of the identified barriers.

If the CDM does not alleviate the identified barriers that prevent the proposed project activity from occurring, then the project activity is not additional.

Sub-step 3a. Identify barriers that would prevent the implementation of type of the proposed project activity:

Establish that there are realistic and credible barriers that would prevent the implementation of the type of proposed project activity from being carried out if the project activity was not registered as a CDM activity. Such barriers may include, among others, investment barriers other than the economic/financial barriers in Step 2 above, technological barriers, barriers due to prevailing practice and other barriers.

Sub-step 3 b. Show that the identified barriers would not prevent the implementation of at least one of the alternatives (except the proposed project activity):

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If the identified barriers also affect other alternatives, explain how they are affected less strongly than they affect the proposed CDM project activity.

The barriers of the geothermal power generation of Indonesia are described below. <Investment Barrier>

In the past, the development of geothermal energy in Indonesia involved two Indonesian state-owned companies, that is, PT PERTAMINA (the Indonesian state-owned oil and gas company) in the upstream of the geothermal resource management, and PT PLN (the Indonesian state-owned electricity grid operator, retailer and majority generator) in the downstream of the geothermal resource management. A private company which has an interest in geothermal energy business had to make a Joint Operating Contract (JOC) with PERTAMINA and an Energy Sales Contract (ESC) with PLN. This condition caused complexity and bureaucracy to geothermal power development in Indonesia.

As the Geothermal Energy Law (No.27/2003) came into effect in 2003, the separated upstream and downstream regulatory management of the geothermal resource management remains, but PERTAMINA is no longer required as a partner in the development of new geothermal projects. However, up to present, four years after the Geothermal Energy Law came into effect, its implementing regulations such as presidential and ministrial decrees are not issued yet, causing a stagnancy in the geothermal power development.

In the downstream management, PLN is the single sole electricity buyer with no open market competition. With the state power monopoly under political and commercial pressure, the currect electricity purchase price is kept low. The GOI provides a huge amount of subsidy to PLN annually.

<Technological Barrier>

The development is started from the very beginning stage, and the primary technological barrier lies in the significant risk of finding the availability of the fuel source, i.e. steam. A geothermal project is totally reliant on the steam produced from the reservoir deep below the earth. Comparing with conventional fossil fuel based power projects, a geothermal project needs significant capital cost and faces risks associated with drilling wells to both confirm and understand the geological setting of the geothermal system to ensure the steam delivery. In addition, the uncertainty regarding the steam availability still remains during the operation phase of the geothermal power plant, where the determination of the number, location and timing of wells required to maintain the steam supply is critical.

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<Barriers due to Prevailing Practice>

According to the Presidential Decree No.5/2006 on the National Energy Policy, the contribution of coal in the national primary energy mix is targeted to increase from 14% at present to more than 33% in 2025. In addition, as mentioned above, the GOI has a “Crash Program” to develop 10,000 MW of additional coal-fired power generation capacity by 2010. Thus, it is obvious that the national preference for the primary energy source is coal. This impedes the development of renewable energy resources, including geothermal. The fuel pricing approach indicating that coal to be the least cost power option supports this condition.

Step 4. Common practice analysis

The above generic additionality tests shall be complemented with an analysis of the extent to which the proposed project type has already diffused in the relevant sector and region. This test is a credibility check to complement the investment analysis (Step 2) or barrier analysis (Step 3).

Sub-step 4a. Analyze other activities similar to the proposed project activity:

Provide an analysis of any other activities implemented previously or currently underway that are similar to the proposed project activity. Other CDM project activities are not to be included in this analysis.

Sub-step 4b. Discuss any similar options that are occurring:

If similar activities are identified above, then it is necessary to demonstrate why the existence of these activities does not contradict the claim that the proposed project activity is financially unattractive or subject to barriers.

The geothermal plant of 857MW is operating now in Indonesia. All of these geothermal power plants was constructed by state own company using ODA granting or by IPP before 1998 when the electric selling price was higher these days. Accordingly, it is considered that there is no geothermal power plant which is constructed under current condition of economic and regulation.

<Additionality for SSC project activities>

PPs shall provide an explanation to show that the project activity would not have occurred anyway due to at least one of the following barriers: Investment barrier, Technological

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barrier, Barrier due to prevailing practice or Other barriers.

(f) Calculation of Emission Reduction (PDD Section B.6)

<<ACM0002>>

<Emission reduction>

ERy = BEy － PEy － Ly

ERy: The GHG emission reduction achieved by the project activity during a given year “y” [t-CO2/MWh]

BEy: Baseline emissions [t-CO2/MWh]

PEy: Project emissions [t-CO2/MWh]

Ly: Leakage [t-CO2/MWh]

<Baseline emission>

BEy = EFy × EGy

BEy: Base line emission[t-CO2/MWh]

EFy: Base line emission factor in [t-CO2/MWh]

EGy: The electricity supplied by the project activity to the grid in[MWh]

<Base line emission factor>

As the weighted average of Operating Margin emission factor (EFOM,y) and the Build Margin emission factor (EFBM,y).

EFy = wOM × EFOM,y + wBM × EFBM,y

EFy ：Base line emission factor [t-CO2/MWh]

<Combined Margin (CM) emission factor>

EFOM,y：Operating Margin (OM) emission factor [t-CO2/MWh]

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EFBM,y：Build Margin (BM) emission factor [t-CO2/MWh]

Default weights are (wOM = wBM = 0.5). For wind and solar projects, the default weights are (wOM =0.75 and wBM=0.25). Alternative weights can be used, as long as wOM + wBM = 1, and appropriate evidence justifying the alternative weights is presented.

<Build Margin (BM) emission factor>

Project participants should choose between the following 2 options a sample group that has the larger annual generation:

The 5 power plants that have been built most recently, or

The power plants capacity additions in the electricity system that comprise 20% of the system generation [in MWh] and that have been built most recently. (If 20% falls on part capacity of a plant, that plant is fully included in the calculation.)

EFBM,y is calculated by dividing CO2 emissions [t-CO2] of the chosen sample group by the electricity [MWh] delivered to the grid by that group.

Project participants shall choose between one of the following 2 options, and the choice cannot be changed during the crediting period:

Option 1. Calculate EFBM,y ex ante based on the most recent information available on plants already built at the time of PDD submission.

Option 2. For the 1st crediting period, EFBM,y must be updated annually ex post for the year in which actual project generation and associated emissions reductions occur. For subsequent crediting periods, EFBM,y should be calculated ex-ante, as described in option

<Operatong Margin (OM) emission factor>

Calculate the Operating Margin emission factor(s) (EFOM,y) based on one of the four following methods:

(a) Simple OM

(i) Identify the generating sources delivering electricity to the grid,not including

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low-operating cost and must-run power plants, and including imports to the grid.

(ii) The Simple OM emission factor [t-CO2/MWh] is calculated as the generationweighted average emissions per electricity unit of the generating sources above in a year.

(b) Simple Adjusted OM.

(i) Separate the power sources (including imports) delivering electricity to the grid in low-cost/must-run power sources and other power sources.

(ii) Calculate the generation-weighted average emissions per electricity unit [t-CO2/MWh] of the set of power plants in a year for both low-cost/must-run power sources and other power sources.

(iii) Calculate λ.

(iv) The Simple Adjusted OM emission factor [t-CO2/MWh] is calculated as “λ x (emission factor of lowcost/must-run power sources)” + ”(1- λ) x (emission factor of other power sources)”

(c) Dispatch Data Analysis OM

(i) Obtain from a national dispatch center, the grid system dispatch order of operation for each power plant of the system, and the amount of power [MWh] that is dispatched from all plants in the system during each hour that the project activity is operating.

(ii) At each hour in a year, stack each plants generation using the merit order. The set of plants consists of those plants at the top of the stack (i.e., having the least merit), whose combined generation comprises 10% of total generation from all plants during that hour (including imports to the extent they are dispatched).

(iii) Calculate the hourly generation-weighted average emissions per electricity unit [t-CO2/MWh] of the set of power plants in the top 10% of grid system dispatch order during each hour in a year.

(iv) Multiply the hourly emission factor above by the generation of the CDM project [MWh] in each hour, which gives amount of CO2 emissions [t-CO2].

(v) Divide the amount of CO2 emissions above by the generation of the CDM project [MWh] in the year, which gives the Dispatch Data OM emission factor [t-CO2/MWh].

(d) Average OM.

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The average OM emission factor [t-CO2/MWh] is calculated as the generation-weighted average emissions per electricity unit of all generating sources serving the system.

Calculations for this combined margin must be based on data from an official source and made publicly available.

<<AMS I.D>>

・Emission reduction factor, which is different according to the installed capacity and utilization rates, for small scale geothermal power generation bigger than 200kW uses 0.8(t-co2/MWh).

(g) GHG Emission by sources

Geothermal power generation produces low concentration of CO2 and CH4 in NCG (non-condensable gas) with the geothermal vapor. It is necessary to pay attention to the concentration of NCG. Because if the concentration of CO2 and CH4 higher, the GHG emission reduction effect become lower (possible to be zero!). Table 7.3-1 shows the relation between CO2 concentration in steam and CO2 emission. This figure is drawn under the condition of steam-electricity conversion 7 tonne/MWh and emission factor at Sumbagsel grid etc. are imposed on the figure. When the concentration of CO2 goes up to 10w%, the amount of emission reduction goes down to zero. The average CO2 concentration at the existing geothermal power plant shows around 1w%, thus the emission reduction effect is expected sufficiently. The concentration of CH4 should be checked because of which concentration is smaller than 1/100, but the GHG effect is 21 times of CO2.

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Fig. 7.3.2-2 CO2 Emission by Steam Production

(h) Application of Monitoring Methodology

The application of the monitoring methodology and plan is described in section B.7 of PDD. It is very important to make a detailed and realistic monitor plan, because the issuance of CER is conducted by the difference of baseline scenario and actual project emission reduction.

The typical monitoring items in the geothermal power generation list follows. ・Electricity supplied to the grid by project (MW) ・Quantity of steam (generation and testing)（tonne）・Fraction of CO2 and CH4 in stream (t-CO2/t-steam、t-CH4/t-steam) ・Amount of each fossil fuel consumed by each power source/plant

(i) Environmental Impact Assessment and Comments from Stakeholder

The project participants are requested to prepare the document concerning the environmental impact analysis including outside of boundary. The geothermal power generation bigger than 55MW is required to prepare environmental impact assessment, environmental management plan and environmental monitoring plan. The other scale of geothermal power plant should be prepare the environmental management effort and environmental monitoring effort. The items mentioned in these documents are described in this section.

0

0.1

0.2

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0.5

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0.9

1

0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0%CO2 Concentration in Steam (wt%)

CO

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Small Scale Geothermal P/PSumbagsel Grid System

JAMALI Grid System

Emission Factor 0.836Emission Factor 0.8

Emission Factor 0.728