study on the optimal electric power development in sumatra ... · japan decided to conduct the...

Study on the Optimal Electric Power Development in Sumatra

Final Report (Summary)

July 2005

Japan International Cooperation Agency Economic Develoment Department

No.

ED

JR

05-063

Study on the Optimal Electric Power Development in Sumatra

Final Report (Summary)

July 2005

Japan International Cooperation Agency Economic Develoment Department

Preface

In response to the request from the Government of the Republic of Indonesia, the Government of Japan decided to conduct the Study on the Optimal Electric Power Development in Sumatra, and entrusted the Study to the Japan International Cooperation Agency (JICA).

JICA sent the Study Team, headed by Mr. Yoshitaka SAITO of Chubu Electric Power Co., Inc. and

organized by Chubu Electric Power Co., Inc. and the Institute of Energy Economics, Japan, to Indonesia five times from February 2004 to June 2005.

The Study Team had a series of discussions with the officials concerned of the Government of the

Republic of Indonesia and the provincial governments in Sumatra, and conducted related field surveys. After returning to Japan, the Study Team conducted further studies and compiled the final results in this report.

I hope that this report will contribute to the promotion of the plan and to the enhancement of amity

between our two countries. I wish to express my sincere appreciation to the officials concerned of the Government of Republic

of the Indonesia, PT. PLN (Persero) and the provincial governments in Sumatra for their close cooperation throughout the Study.

July 2005

Tadashi IZAWA Vice President Japan International Cooperation Agency

July 2005

Mr. Tadashi IZAWA Vice President Japan International Cooperation Agency Tokyo, Japan

Letter of Transmittal

We are pleased to submit to you the report of “the Study on the Optimal Electric Power Development in Sumatra”. This study was implemented by Chubu Electric Power Co., Inc. and the Institute of Energy Economics, Japan from February 2004 to July 2005 based on the contract with your Agency.

This report presents the comprehensive proposal, such as the optimal power development plan considering the characteristics of potential primary energy in Sumatra, and the transmission development plan including an interconnection between the North and South Sumatra systems to secure a stable power supply. In addition, macroeconomic & financial and environmental measures, and also investment promotion schemes for the power sector are proposed in order to realize the plans.

We trust that the realization of our proposal will much contribute to sustainable development in the

electric power sector, which will contribute to the improvement of the public welfare in Sumatra as well, and recommend that the Government of Republic of the Indonesia priotize the implementation of our proposal by applying results of technology transfer in the Study.

We wish to take this opportunity to express our sincere gratitude to your Agency, the Ministry of Foreign Affairs and the Ministry of Economy, Trade and Industry. We also wish to express our deep gratitude to Ministry of Energy and Mineral Resources (MEMR), PT. PLN (Persero), the provincial governments in Sumatra and other authorities concerned for the close cooperation and assistance extended to us throughout the Study.

Very truly yours, Yoshitaka SAITO Team Leader The Study on the Optimal Electric Power Development in Sumatra

Table of Contents

Chapter 1 Background and Objective .................................................................................................... 1-1

1.1 Background ................................................................................................................................. 1-1

1.2 Objective ...................................................................................................................................... 1-1

1.3 Work Flow ................................................................................................................................... 1-1

Chapter 2 Power Demand Forecast in Sumatra ...................................................................................... 2-1

2.1 Power Demand Forecasting Model .............................................................................................. 2-1

2.2 Data Source and Scenario ............................................................................................................. 2-3

2.3 Power Demand by North and South-West Sumatra System .................................................... 2-5

Chapter 3 Power Deficits Possibility and Short-Term Countermeasures ............................................... 3-1

3.1 Identification of Power Deficits in Sumatra System ................................................................ 3-1

3.2 Short-Term Countermeasures ....................................................................................................... 3-4

Chapter 4 Generation Development Plan ............................................................................................... 4-1

4.1 Reviewing Historical Demand ..................................................................................................... 4-1

4.2 Generation Development Plan for the North and the South-West Sumatra System

(Least-cost Case) ......................................................................................................................... 4-2

4.3 Generation Development Plan for the Whole Sumatra System (Least-cost Case) ....................... 4-5

4.4 Examination on Interconnection Transmission Line .................................................................... 4-7

4.5 Case Studies and Sensitivity Analysis ........................................................................................ 4-10

4.6 Proposed Generation Development Plan in the Study ................................................................ 4-12

4.7 Preparation of Detailed Generation Development Plan for Transmission Planning .................. 4-16

4.8 Issues and Recommendations ..................................................................................................... 4-18

Chapter 5 Transmission Planning and System Analysis ......................................................................... 5-1

5.1 Conditions ................................................................................................................................... 5-1

5.2 Transmission Plan ........................................................................................................................ 5-3

5.3 Planed Facilities .......................................................................................................................... 5-8

5.4 Construction Cost ........................................................................................................................ 5-9

5.5 Issues and Recommendations .................................................................................................... 5-9

Chapter 6 Environmental and Social Considerations (ESC)

- Initial Environmental Evaluation (IEE) - ............................................................................ 6-1

6.1 ESC Scheme for the Study (Method of IEE) ................................................................................ 6-1

6.2 Scoping ......................................................................................................................................... 6-2

6.3 Inclusion of Environmental Cost into Project Cost in Formulating Power Development Plan .... 6-4

6.4 Initial Study of Mitigation Measures .......................................................................................... 6-21

6.4 Recommendations for ESCs in the Next Planning Process Step ................................................ 6-28

Chapter 7 Investment Promotion in Power Sector ................................................................................. 7-1

7.1 Total Investment Necessary for the Power Sector Development in Sumatra ............................... 7-1

7.2 Recommendations for Investment Promotion in Power Sector ................................................... 7-4

Chapter 8 Future Direction of Assistance for the Realization of the Optimal Electric Power Development in Sumatra ...................................................................... 8-1

8.1 Assistance for the Generation Development Plan .................................................................... 8-1

8.2 Assistance for Formulating a System Operation Plan .............................................................. 8-2

8.3 Support for Human Resource Development ............................................................................. 8-2

8.4 Support for Interconnection of the Sumatra System with other Systems ............................... 8-3

Appendix I Power Demand Forecast by Province

Appendix II Power Plants by System (as of April 2004)

Appendix III WASP Simulation Results

Appendix IV Scoping Format and Criteria for Scoping Items

List of Tables and Figures

<List of Tables>

Chapter 2 Table 2.2.1 Economic Growth Rates Applied for Model Simulation .................................... 2-3 Table 2.2.2 Share of Sectoral GRDP ..................................................................................... 2-4 Table 2.2.3 Household Electrification Scenario .................................................................... 2-4 Table 2.3.1 Power Demand in Northern Sumatra System ..................................................... 2-6 Table 2.3.2 Power Demand in South-West Sumatra System ................................................. 2-7 Chapter 3 Table 3.1.1 Summary of Power Plants in the Sumatra System (as of April 2004) ................ 3-1 Table 3.1.2 LOLP in the North System ................................................................................. 3-2 Table 3.1.3 LOLP in the South-West System ........................................................................ 3-3 Table 3.1.4 Power Development Plan in the North System ................................................... 3-3 Table 3.1.5 Power Development Plan in the South-West System ......................................... 3-3 Table 3.1.6 Additional Capacity Needed in the North System to Secure System Reliability ..... 3-4 Chapter 4 Table 4.2.1 Preconditions for Simulation (common to both systems) ................................... 4-2 Table 4.2.2 Fixed Development Projects for Simulation ....................................................... 4-2 Table 4.2.3 Future Recovered Units for Simulation .............................................................. 4-3 Table 4.2.4 Characteristics of Candidate Generation Units for the North and South-West Sumatra System (Least-cost Case) ..................................................................... 4-3 Table 4.2.5 Output of WASP-IV Simulation for the North and South-West System (Least-cost Case) ................................................................................................ 4-4 Table 4.2.6 System Cost for the North and South-West Sumatra System (Least-cost Case) ... 4-4 Table 4.3.1 Details of Candidate Generation Units for the Whole Sumatra System (Least-cost Case) ................................................................................................ 4-5 Table 4.3.2 Output of WASP-IV Simulation for the Whole Sumatra System (Least-cost Case) ................................................................................................ 4-6 Table 4.3.3 System Cost for the Whole Sumatra System (Least-cost Case) ......................... 4-6 Table 4.4.1 Comparison of Installed Capacity in 2020 .......................................................... 4-7 Table 4.4.2 Comparison of Investment Cost up until 2020 ................................................... 4-8 Table 4.4.3 Comparison of System Cost up until 2020 ......................................................... 4-8 Table 4.5.1 Cases and Preconditions for Case Study and Sensitivity Analysis ................... 4-10 Table 4.5.2 ESC (Environmental and Social Considerations) Factor .................................. 4-10 Table 4.5.3 Output of WASP-IV Simulation (CO2 Emission Prevention Case) .................. 4-11 Table 4.5.4 Output of WASP-IV Simulation (Limited Natural Gas Supply Case) ............... 4-11

Table 4.5.5 Output of WASP-IV Simulation (ESC Weighted Case) .................................... 4-12 Table 4.6.1 Transition of Installed Capacity (Proposed Case) ............................................. 4-13 Table 4.6.2 Necessary Investment Cost (Proposed Case) .................................................... 4-13 Table 4.6.3 System Cost (Proposed Case) ........................................................................... 4-13 Table 4.6.4 Generation Development Plan for the Whole Sumatra System (Proposed Case, Low Demand Case) ............................................................... 4-14 Table 4.6.5 Generation Development Plan for the Whole Sumatra System (Proposed Case, High Demand Case) ............................................................... 4-15 Table 4.7.1 List of Candidate Sites for Development .......................................................... 4-16 Table 4.7.2 Generation Development Plan for Transmission Planning (Proposed Case, High Demand Case) ............................................................... 4-17 Chapter 5 Table 5.1.1 Study Cases for Transmission Planning .............................................................. 5-1 Table 5.1.2 Differences between Power Development Candidates ....................................... 5-1 Table 5.1.3 Demand Forecast and Installed Capacity by System .............................................. 5-2 Table 5.3.1 Length of Transmission Lines ............................................................................. 5-8 Table 5.3.2 Capacities of Transformers ................................................................................. 5-8 Table 5.4.1 Estimated Construction Cost [Main System] ...................................................... 5-9 Chapter 6 Table 6.2.1 Types of Power Facilities .................................................................................... 6-2 Table 6.2.2 Results of Scoping by Power Facility Type ........................................................ 6-3 Table 6.3.1 Environmental Impact Level (ESC Factor) by Facility Type .................................. 6-6 Table 6.3.2 Development Plan of Fixed Projects .................................................................. 6-8 Table 6.3.3 Capacity Transition Plan of Existing Power Plants by Type ............................... 6-8 Table 6.3.4 Least-cost Case (Low Demand Case: 2020) ....................................................... 6-8 Table 6.3.5 Least-cost Case (High Demand Case: 2020) ...................................................... 6-9 Table 6.3.6 Comparison in Total Capacity of Candidate Projects up to 2020 (Low Demand Case) ......................................................................................... 6-15 Table 6.3.7 Comparison in Total Capacity of Candidate Projects up to 2020 (High Demand Case) ........................................................................................ 6-16 Table 6.3.8 Comparison in Investment Cost (total investment cost up to 2020) ................. 6-16 Table 6.3.9 Comparison in System Cost (total system cost up to 2020) ............................. 6-16 Chapter 7 Table 7.1.1 Total Investment Necessary for Development of Power Generation and Transmission Facilities in Sumatra during 2006-2020 ................................. 7-1

<List of Figures> Chapter 1 Figure 1.3.1 Work Flow of the Study ...................................................................................... 1-2 Chapter 2 Figure 2.1.1 Schematic Flow Diagram for Power Demand Forecasting ................................. 2-1 Figure 2.3.1 Power Demand in Northern Sumatra System ..................................................... 2-6 Figure 2.3.2 Power Demand in South-West Sumatra System ................................................. 2-7 Chapter 3 Figure 3.1.1 Installed Capacity in the Sumatra System (as of April 2004) ............................... 3-2 Figure 3.1.2 Power Mix by System in Sumatra (as of April 2004) ......................................... 3-2 Chapter 4 Figure 4.1.1 Target Power Systems for Generation Development Planning ........................... 4-1 Figure 4.4.1 Correlation between Interconnection Year and Benefit of Interconnection ........ 4-9 Chapter 5 Figure 5.2.1 Proposed Case (2010) ......................................................................................... 5-4 Figure 5.2.2 Proposed Case (2020) ......................................................................................... 5-5 Figure 5.2.3 South Case (2010) ............................................................................................... 5-6 Figure 5.2.4 South Case (2020) ............................................................................................... 5-7 Chapter 6 Figure 6.3.1 Protected Areas in Sumatra and Locations of Newly Developing Power Plants ... 6-10 Chapter 7 Figure 7.1.1 PLN Operational Income vs. Operational Cost .................................................. 7-2 Figure 7.1.2 Reliance on Liability ........................................................................................... 7-3 Figure 7.2.1 Institutional Arrangement for Investment Coordination and Promotion in the Indonesian Power Sector (Proposal) ......................................................... 7-7

List of Abbreviations AC Alternating Current ACSR Aluminum Conductor Steel Reinforced ADB Asian Development Bank AMDAL Analisis Mengenai Dampak Lingkungan APS American Phisical Society ATA Automatic Tariff Adjustment BAPEDAL Badan Pembangunan Dampak Lingkungan BAPEDALDA Badan Pembangunan Dampak Lingkungan Daerah BAPEPTAL Badan Pengatur Pasar Tenaga Listrik BAPPEDA Badan Perencannan Pembangunan Daerah Bbl Barrel BPS Badan Pusat Statistic CC Combined Cycle CCT Clean Coal Technology CDM Clean Development Mechanism CEPCO Chubu Electric Power Co., Inc. CER Certificated Emission Reduction CFBC Circulating Fluidized Bed Combustion Boiler CP Captive Power CPI Consumer Price Index DF/R Draft Final Report DGEEU Directorate General of Electricity and Energy Utilization Dinas PE Dinas Pertambangan dan Energi EIA Environmental Impact Assessment EIRR Economic Internal Rate of Return EMF Electric Magnetic Fields EMP Environmental Management and Monitering Plan EMPT Environmental Mitigation Plan ENS Energy Not Served EP Elrctrostatic Precipitator ESC Environmental Social Consideration FGD Flue Gas Desulfurizer FIRR Financial Internal Rate of Return F/R Final Report F/S Fiesibility Study FY Fiscal Year G&T Generation and Transmission GDP Gross Domestic Product

GHG Green House Gas GRDP Gross Regional Domestic Product GT Gas Turbine GWh Gigawatt-hour HPP Hydropower Plant HSD High Speed Diesel Oil HVDC High Voltage Direct Current IC Interconnection ICNIRP International Commission on Non-Ionizing Radiation Protection Ic/R Inception Report IEA International Energy Agency IEE Initial Environmental Examination and Initial Environmental Evaluation IEEJ Institute of Energy Economics, Japan IMF International Monetary Fund IPP Independent Power Producer IRPA International Radiation Protection Association It/R Interim Report JAMALI Jawa-Madura-Bali JBIC Japan Bank for International Cooperaqtion JICA Japan International Cooperation Agency kW kilowatt kWh kilowatt-hour L/G Letter of Guarantees LOLP Loss-of-Load Probability MEMR Ministry of Energy and Mineral Resources METI Ministry of Economic, Trade and Industry MFO Marine Fuel Oil MIGAS Directorate General of Oil and Gas M/M Minutes of Meeting MMBTU Million British Thermal Unit MOE Ministry of Environment MOF Ministry of Forestry MP Master Plan MW Mega Watt NAD Nanggroe Aceh Darussalam NAS National Academy of Science NGO Non-Govermental Organization NEXI Nippon Expert and Investment Insurance NIEHS National Institute of Environmental Health Science NRPB National Radiological Protection Board

ODA Official Development Assistance OHL Overhead Line O&M Operation and Maintenance OPGW Optical Ground Wire PCM Pulse Code Modulation PEMU Project Environmental Mnagement Unit PICOM Power-sector Investment Coordination Meeting PLC Power Line Carrier PLN PT. PLN (PERSERO) PLTA Pusat Listrik Tenaga Air PLTD Pusat Listrik Tenaga Diesel PLTG Pusat Listrik Tenaga Gas PLTGU Pusat Listrik Tenaga Gas & Uap PLTP Pusat Listrik Tenaga Panas Bumi PLTU Pusat Listrik Tenaga Uap PPA Power Purchase Agreement PPP Public-Private Partnership Pr/R Progress Report P/S, PS Power Station PSS Power System Stabilizer PSS/E Power System Simulator for engineering PSP Private Sector Participation PTI Power Technologies Inc. RKL Rencana Pengelolaan Lingkungan Rp Rupiah RPL Rencana Pemantauan Lingkungan RPTL Rencana Penyediaan Tenaga Listrik RUKD Rencana Umum Ketenagalistrikan Daerah RUKN Rencana Umum Ketenagalistrikan Nasional RUNW Rencana Umum Ketenagalistrikan Wilayah SAIDI System Average Interruption Duration Index SAIFI System Average Interruption Frequency Index SCADA Supervisory Control And Data Acquisition SCM Stakeholder Consultation Meeting SEA Strategic Environmental Assessment SOP Standard Operating Statement SPC Special Purpose Cpmpany S/S, SS Substation ST Steam Turbine Sumbagsel Sumatra Bagian Selatan

Sumbar Sumatra Barat Sumsel Sumatra Selatan Sumut Sumatra Utara SVC Static Var Compensator S/W Scope of Work T/D Transmission / Distribution TNB Tenaga National Berhad TOR Terms of Reference TSCF Trillion Standard Cubic Feet UFR Underfrequency Relay UNFCCC United Nations Framework Convention on Climate Change UPB Unit Pengatur Beban WASP-IV Wien Automatic System Planning - version IV WB World Bank WHO World Health Organization WTI West Texas Intermediate

Sumatra Region Map

1-1

Chapter 1 Background and Objective 1.1 Background

Electricity demand in Indonesia has increased steadily following the recovery from the economic crisis of 1997. However, the electricity supply, which is indispensable for the public and industry, is still insufficient and it is one of bottlenecks to the full restoration of the economy in Indonesia. The Government of Indonesia has been implementing measures in accordance with the recommendations of the former JICA Development Study on the Optimal Electric Power Development and Operation in Indonesia, which focuses on the Java-Bali power system.

The Government is putting the top priority on both reinforcing the power industry and formulating a power development plan for outer areas of the Java-Bali power system. The government requested this study from the Government of Japan as part of a technical cooperation program.

The Sumatra power system has a severe power shortage due to the lack of interconnecting transmission lines between the northern, central and southern areas of Sumatra. Many cities in the southern area must even contend with daily rotational blackouts. Even if the planned interconnections among these areas are put into practice, it will still be difficult to ensure a stable power supply without an appropriate power development plan in Sumatra. 1.2 Objective

This situation prompted JICA to begin a “Study on the Optimal Electric Power Development in Sumatra” (hereinafter referred to as “the Study”) in February 2004. The scope of the study was limited to the Sumatra power system. The Study has the following three main objectives: ● Formulate the optimal power development plan for the Sumatra power system up until 2020,

including short-term countermeasures against power deficits ● Encourage the development of human resources in the power sector at the provincial level responsible

for formulating RUKD1 ● Study macroeconomic and financial measures and investment promotion policy for the power sector

in Sumatra in order to bring the optimal power development plan to fruition 1.3 Work Flow

The work flow of the Study is shown in Figure 1.3.1.

1 Rencana Umum Ketenagalistrikan Daerah

Preparatory work in Japan 1st Work in Japan(Phase 2) 2nd Work in Japan 3rd Work in Japan 4th Work in Japan

1st Work in Indonesia 2nd Work in Indonesia 3rd Work in Indonesia 4th Work in Indonesia 5th Work in Indonesia

YearMonth

Study Stage

　　

Work in Japan　　　　　　　　　　　　

Work in Indonesia　　　　　　　　　　　　

Study Step　　

MonthWorkshopReporting

2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7

2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7

2004 2005

　The 1st W/S 　The 2nd W/S 　The 3rd W/S　Prior consultation　Interim Report 　Progress Report Draft Final Report　　Inception Report Final Report　



The BasicStudy Stage

The Detailed Study Stage

The Scenario (Study Case)Preparation Stage

The Optimal Power Development Plan Study Stage

Preparatory work in Japan

Detailed planning of theStudyPreparat ion for theDraft Inception ReportPreparat ion for question-naires and requestdocuments for collect ionof data and informat ion



1st Work in Indonesia

Explanation and discussionof the Study planConsultation on the WorkPlan for site surveysConsultation on basicmatters for holding theWorkshopsOrganizing implementationstructures of the StudyCollection of necessarydata and informationPreparation fo r procure-ment of equipment


Exp lanation and discussionof the Study planConsultation on the WorkPlan fo r site surveysConsultation on basicmatters for holding theWorkshopsOrganizing imp lementationstructures of the StudyCollection of necessarydata and informationPreparation for procure-ment of equipment

2nd Work in Indonesia

Collection of necessary data and informat ionSite SurveysPreparation fo r and holding the 1st WorkshopProcurement of equipment



1st Work in Japan(Phase 2)

Review of necessarydata and information



3rd Work in Indonesia

Study on macroeconomic and financial measuresStudy on investment promotion policy for thepower sectorStudy on environmental and social impactassessment (ESIA)Determination of scenarios(study cases)Study on the short-term countermeasures againstpower deficitPreparation for the Interim ReportExp lanation and discussion of the Interim ReportPreparation for and holding the 2nd WorkshopSupport for preparation for Counterpart Train ing


Study on macroeconomic and financial measuresStudy on investment promotion policy for thepower sectorStudy on environmental and social impactassessment (ESIA)Determination of scenarios(study cases)Study on the short-term countermeasures againstpower deficitPreparation fo r the Interim ReportExp lanation and discussion of the Interim ReportPreparation fo r and holding the 2nd WorkshopSupport for preparation for Counterpart Train ing

2nd Work in Japan

Optimizing power development plan by scenarioStudy on measures from the viewpoint of macro-economics, finance and investment promotion forthe power sectorStudy on environmental and social impactassessment (ESIA)Counterpart Training (If JICA approves)Preparation fo r the Progress Report

2nd Work in Japan


5th Work in Indonesia

Explanation and discussion of the Draft FinalReportPreparation fo r and holding the 3rd WorkshopConfirmation of the results of technicaltransfer results



3rd Work in Japan

Preparation fo r recommendationsPreparation fo r the Draft FinalReport

3rd Work in Japan


4th Work in Japan

Preparation for recommendationsPreparation for the Draft FinalReport

4th Work in Japan



Explanation and discussion of theProgress ReportContinuous study from the 2nd Work inJapanStudy on the optimal scenarioStudy on the human resource develop-ment plan on the provincial levelDatabase building



Completion and Submission of the Final ReportCompletion and Submission of the Final Report



Preparation and sub-mission of the revisedInception ReportReview of necessarydata and information



1st Work in Japan(Phase 1) Preparatory work in Japan 1st Work in Japan(Phase 2) 2nd Work in Japan 3rd Work in Japan 4th Work in Japan


YearMonth

Study Stage

　　

Work in Japan　　　　　　　　　　　　

Work in Indonesia　　　　　　　　　　　　

Study Step　　

MonthWorkshopReporting

2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7

2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7

2004 2005

　The 1st W/S 　The 2nd W/S 　The 3rd W/S　Prior consultation　Interim Report 　Progress Report Draft Final Report　　Inception Report Final Report　



The BasicStudy Stage

The Detailed Study Stage

The Scenario (Study Case)Preparation Stage

The Optimal Power Development Plan Study Stage






Explanation and discussionof the Study planConsultation on the WorkPlan for site surveysConsultation on basicmatters for holding theWorkshopsOrganizing implementationstructures of the StudyCollection of necessarydata and informationPreparation fo r procure-ment of equipment


Exp lanation and discussionof the Study planConsultation on the WorkPlan fo r site surveysConsultation on basicmatters for holding theWorkshopsOrganizing imp lementationstructures of the StudyCollection of necessarydata and informationPreparation for procure-ment of equipment










Study on macroeconomic and financial measuresStudy on investment promotion policy for thepower sectorStudy on environmental and social impactassessment (ESIA)Determination of scenarios(study cases)Study on the short-term countermeasures againstpower deficitPreparation for the Interim ReportExp lanation and discussion of the Interim ReportPreparation for and holding the 2nd WorkshopSupport for preparation for Counterpart Train ing


Study on macroeconomic and financial measuresStudy on investment promotion policy for thepower sectorStudy on environmental and social impactassessment (ESIA)Determination of scenarios(study cases)Study on the short-term countermeasures againstpower deficitPreparation fo r the Interim ReportExp lanation and discussion of the Interim ReportPreparation fo r and holding the 2nd WorkshopSupport for preparation for Counterpart Train ing

2nd Work in Japan


2nd Work in Japan






3rd Work in Japan


3rd Work in Japan


4th Work in Japan

Preparation for recommendationsPreparation for the Draft FinalReport

4th Work in Japan






Completion and Submission of the Final ReportCompletion and Submission of the Final Report







Figure 1.3.1 Work Flow of the Stud

1-31-2

2-1

Chapter 2 Power Demand Forecast in Sumatra 2.1 Power Demand Forecasting Model

In this study an econometric method is applied for simulation model building. The power demand forecasting model is one of the tools used for policy decision-making, and so attention will be paid to economic growth (Regional GDP by sector), household electrification and the price elasticity of the electricity tariff. The demand function is expressed by Income index (GDP) and Price index based on econometric principles.

Figure 2.1.1 shows the schematic flow diagram for the power demand forecast. The model consists (1) a socio-economic sub-block (Economic Structure part in the figure), (2) a final power consumption sub-block (Regression Analysis and Total Power Demand parts in the figure), and (3) a power generation and peak load sub-block.

Economic StructureEconomic StructureRegression AnalysisRegression Analysis

Electrification1 Household electrification ratio

= f (GRDP/capita, Trend)2. No. of Residential customer

= f (Electrification ratio)

Total Power Demand (GWh)Total Power Demand (GWh)

Total Power Supply Required (GWh)

Total Power Supply Required (GWh) Gross Losses

GRDP (given)(Total growth rate)

CPI (Inflation)

GRDP by Sector(Nine components)

from Agriculture toSocial/public sector

GRDP Adjusted to Electricity Consumer1. Total2. Manufacturing3. Commercial4. Social/public

Power Demand by Sector1. Residential sector

= f (GRDP/customer, Price, No. of customer)2. Manufacturing industry

= f (GRDPmanufacure, Price)3. Commercial (Business) sector

= f (GRDPcommercial, Price)4. Social (Public) sector

= f (GRDPsocial, Price)

Population (Trend)

Peak Load

(MW)

Peak Load

(MW)

Load Factor

Economic StructureEconomic StructureRegression AnalysisRegression Analysis

Electrification1 Household electrification ratio

= f (GRDP/capita, Trend)2. No. of Residential customer

= f (Electrification ratio)

Total Power Demand (GWh)Total Power Demand (GWh)

Total Power Supply Required (GWh)

Total Power Supply Required (GWh) Gross Losses

GRDP (given)(Total growth rate)

CPI (Inflation)

GRDP by Sector(Nine components)

from Agriculture toSocial/public sector

GRDP Adjusted to Electricity Consumer1. Total2. Manufacturing3. Commercial4. Social/public

Power Demand by Sector1. Residential sector

= f (GRDP/customer, Price, No. of customer)2. Manufacturing industry

= f (GRDPmanufacure, Price)3. Commercial (Business) sector

= f (GRDPcommercial, Price)4. Social (Public) sector

= f (GRDPsocial, Price)

Population (Trend)

Peak Load

(MW)

Peak Load

(MW)

Load Factor

Figure 2.1.1 Schematic Flow Diagram for Power Demand Forecasting

2-2

(1) Socio-economic sub-block Macro indicators include four items, specifically: (1) population, (2) regional GDP (GRDP) by

sector, (3) consumer price index (CPI) and (4) electricity prices by sector. In electric power demand forecasting, the former items described above can be treated as external variables in order to simulate the impact of price and GDP growth. In this case, the GRDP growth rate is given as the scenario for power demand forecasting.2 (2) Final power consumption sub-block

The final power consumption (end-use power demand) sub-block comprising each sector creates structural equations by sector and calculates the sectoral demand and the total. The demand function is estimated by regression analysis in each sectoral demand for manufacturing, residential, commercial, and government/public sectors. The demand total is obtained by adding the sectoral demand. Basically, system equations by sector are created as follows.

1) Manufacturing industry

Electricity demand = f (GRDP of industrial sector, Price for industry) 2) Residential sector

Number of customers = f (Household electrification ratio3) Electricity demand = f (Electricity consumption/Customer, Price for households,

Number of customers, Previous year’s demand) 3) Commercial sector

Electricity demand = f (GRDP of commercial sector, Price for commercial sector) 4) Government/Public sector

Electricity demand = f (GRDP of public sector, Price for public sector) (3) Power generation and peak load sub-block

In this sub-sector, forecasted total electricity demand is received from the end-use electricity demand sub-block. Adding gross losses4, which are transmission /distribution (T/D) losses and own use (in-plant use), the total required electric power generation is calculated. Peak load is estimated by load factor.

2 According to BPS statistics, GRDP components are classified into nine categories. On the other hand, the public power consumption is classified into the four sectors of sales demand for residential, industrial, commercial (business) and social/public (social, government office buildings, street lighting, others). In the simulation model, the power demand for the industrial sector corresponds to category “3-b. Non Oil & Gas Manufacturing” of the GRDP components, and the power demand for the commercial sector corresponds to the category “6. Trade, Hotel and Restaurant and 8-d. Business Services”. The power demand for the social/public sector corresponds to the category “9. Public Services (Public Administration & Defense, Social & Community Services, Entertainment & Cultural Services, Personal & Household Services)” of the GRDP components.

3 Two methods have been applied for the household electrification ratio. One is estimated by use of the function of the historical trend and GRDP/capita, and the other is given as targeted values for rural electrification.

4 In this forecasting model all variables are set as internal variables or external variables. From the technical point of view, the ratios of T/D loss and own use can be input as external variables. In the case of a long-long term forecasting model, the model should incorporate the figures for national policy and power development plan including hydropower and fuel supply as external valuables.

2-3

2.2 Data Source and Scenario (1) Applied or referred data source

Time series data applied or referred for the model building are as follows.

GRDP : BPS (at 1983 constant prices and 1993 constant prices) Bangka-Belitung has been classified separately from South Sumatra since 2000 CPI : BPS (Harga konsumen di 43 kota di Indonesia), 1990-2002 Electricity data : Annual reports “PLN Statistics”, for each year Bangka-Belitung has been classified separately from South Sumatra since 2002 Population : Census (1990 & 2000) base

(2) Basic framework

1) Observation year : 1990-2002 (socioeconomic data), and 1990-2003 (electricity data) 2) Base year : 2002 3) Target year : 2020

(3) Scenario

The economic scenarios in each province are set as shown in Table 2.2.1. In this table 2002 values and 2003 values for all of Indonesia are actual economic growth rates (BPS statistics). According to the Asian Development Bank (ADB), Indonesia’s economy is expected to expand by 4.5% in 2004 and 2005.

After 2006, two scenarios of the high case and the low case are employed for the simulation. The high case scenario with a 6.5% growth rate is based on the period of 1983-1997 before the economic crises. The long-term economic outlook for all of Indonesia is estimated at around a 6% annual average base during 2006-2020.

Electricity prices in each province are set as real value constants at the current price level of 6-7 cent/kWh. Nominal values of the Rupiah will increase with inflation (Consumer Price Index).

Table 2.2.1 Economic Growth Rates Applied for Model Simulation (Unit: %) 2002 2003 2004 2005 2006-2020 Low High

Indonesia 3.69 4.10 4.50 4.50 NAD 0.13 3.50 4.00 4.50 5.00 6.50 North Sumatra 4.04 4.50 5.00 5.00 5.00 6.50 West Sumatra 4.29 4.50 5.00 5.00 5.00 6.50 Riau 4.40 4.70 5.00 5.00 5.00 6.50 South Sumatra 3.70 4.50 5.00 5.00 5.00 6.50 Jambi 3.45 4.50 5.00 5.00 5.00 6.50 Bengkulu 4.32 4.70 5.00 5.00 5.00 6.50 Lampung 5.15 5.00 5.00 5.00 5.00 6.50

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The GRDP by sector in each province is internally calculated in the model by the following procedure:

1) Firstly, the share of each GRDP component is estimated by share functions using the historical trends (logarithmic trends), which take into consideration the historical trends of economic activities in each province.

2) Secondly, the sectoral GRDP including the non-oil manufacturing industry, the commercial and the public sectors, which correspond to the classification of the power demand sector, is calculated in the model.

3) Finally, the growth rate of the sectoral GRDP is obtained. Table 2.2.2 shows the share of the sectoral GRDP involved in the electric power demand.

Table 2.2.2 Share of Sectoral GRDP (Unit: %)

Industrial (Non-Oil) Commercial Public 2002 2010 2020 2002 2010 2020 2002 2010 2020

NAD 7.96 8.69 9.28 7.72 8.80 9.67 7.26 7.87 8.36North Sumatra 22.21 23.91 24.21 17.53 15.84 14.81 7.49 7.44 7.52West Sumatra 15.37 17.43 19.10 8.26 8.89 9.40 3.12 3.21 3.30Riau 16.06 16.60 17.04 16.87 16.70 16.55 15.90 16.00 16.09South Sumatra 17.30 17.97 18.81 17.00 16.70 16.33 9.73 9.17 8.72Jambi 15.00 15.45 15.81 20.59 21.41 22.07 6.93 6.62 6.37Bengkulu 4.86 5.40 5.84 17.01 18.47 19.66 17.43 16.78 16.24Lampung 13.31 14.17 15.31 15.23 14.58 13.81 8.91 7.86 7.00

Note: Figures in South Sumatra include Bangka-Belitung province.

Table 2.2.3 shows the household electrification ratio estimated or given as external valuables. The electrification ratio is estimated as the function of the historical trend and GRDP/capita in the low case, and given as the targeted figures in the high case. In the Sumatra region, residential demand is the biggest driving force for the demand hike and rural electrification has had an influence in pushing up electric power demand.

Table 2.2.3 Household Electrification Scenario (Unit: %) Low Case (estimated) High Case (given) 2003 2008 2013 2020 2003 2008 2013 2020

NAD 56.8 65.4 72.0 79.2 56.8 70.1 86.5 94.8North Sumatra 66.3 74.2 80.1 86.3 66.3 78.6 93.2 98.8West Sumatra 38.5 45.9 53.4 64.0 38.5 46.8 56.9 67.8Riau 60.6 68.4 74.5 81.1 60.6 75.6 94.3 98.5South Sumatra 30.8 37.9 45.0 55.5 30.8 41.3 55.4 70.7Jambi 40.6 48.3 55.1 64.1 40.6 51.7 65.8 77.7Bengkulu 42.4 50.0 57.2 67.6 42.2 50.9 60.3 75.0Lampung 36.3 46.3 56.2 71.5 36.3 53.4 78.7 85.0

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2.3 Power Demand by North and South-West Sumatra System

At present the system grid in Sumatra is bringing together both the North Sumatra system and South-West Sumatra system. The former will cover the two provinces of NAD and North Sumatra, and the latter will cover the six provinces of West Sumatra, Riau, Jambi, South Sumatra, Bengkulu and Lampung. As this chapter focuses on power demand outlooks, each province is broken down into two system grids for the sake of convenience as described above.

Tables 2.3.1 and 2.3.2 show the forecasted results for the North Sumatra system and the South-West Sumatra system. In the tables, “Energy” means power generation requirement and “GR” means the annual growth rate of the peak load. The forecasted results on power demand by province are shown in Appendix I.

2-6

Table 2.3.1 Power Demand in Northern Sumatra System Low Case High Case

Total GR (%) Total System Isolated Total System Isolated Total GR (%) Total System Isolated Total System Isolated

GWh % GWh GWh GWh MW MW MW GWh % GWh GWh GWh MW MW MW

2002 4,339 5,397 5,059 338 994 905 90 2002 4,339 5,397 5,059 338 994 905 90

2003 4,728 9.0 5,724 5,322 402 1,072 973 99 2003 4,728 9.0 5,724 5,322 402 1,072 973 99

2004 5,040 6.6 6,067 5,875 192 1,130 1,077 54 2004 5,058 7.0 6,089 5,896 193 1,135 1,081 54

2005 5,362 6.4 6,421 6,221 200 1,194 1,138 55 2005 5,408 6.9 6,477 6,273 203 1,205 1,148 56

2006 5,697 6.2 6,787 6,599 188 1,259 1,210 49 2006 5,854 8.2 6,975 6,780 195 1,295 1,243 51

2007 6,043 6.1 7,164 6,992 172 1,327 1,285 41 2007 6,333 8.2 7,508 7,326 182 1,391 1,347 43

2008 6,403 5.9 7,554 7,376 178 1,396 1,354 42 2008 6,847 8.1 8,079 7,887 192 1,493 1,448 45

2009 6,776 5.8 7,958 7,843 115 1,467 1,440 28 2009 7,399 8.1 8,691 8,565 126 1,603 1,573 30

2010 7,164 5.7 8,377 8,321 55 1,541 1,527 15 2010 7,994 8.0 9,347 9,285 62 1,720 1,704 16

2011 7,569 5.6 8,812 8,757 55 1,618 1,604 14 2011 8,632 8.0 10,051 9,988 63 1,846 1,830 16

2012 7,990 5.6 9,265 9,210 55 1,697 1,683 14 2012 9,319 8.0 10,807 10,742 65 1,981 1,964 17

2013 8,430 5.5 9,736 9,681 55 1,780 1,766 14 2013 10,058 7.9 11,618 11,552 66 2,125 2,108 17

2014 8,890 5.4 10,227 10,173 54 1,866 1,852 14 2014 10,729 6.7 12,344 12,278 66 2,252 2,236 16

2015 9,370 5.4 10,740 10,686 54 1,955 1,942 13 2015 11,441 6.6 13,113 13,048 65 2,387 2,371 16

2016 9,872 5.4 11,275 11,222 53 2,049 2,036 13 2016 12,197 6.6 13,929 13,864 65 2,530 2,514 16

2017 10,397 5.3 11,835 11,782 53 2,146 2,134 13 2017 13,002 6.6 14,795 14,731 64 2,682 2,666 16

2018 10,947 5.3 12,420 12,368 52 2,248 2,236 13 2018 13,858 6.6 15,716 15,652 64 2,843 2,827 15

2019 11,523 5.3 13,032 12,981 51 2,355 2,342 12 2019 14,769 6.6 16,694 16,631 63 3,014 2,999 152020 12,127 5.2 13,673 13,622 51 2,466 2,454 12 2020 15,739 6.6 17,735 17,672 63 3,196 3,181 15

Supply in the Region Peak LoadDemand Supply in the Region Peak Load Demand

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2003

2005

2007

2009

2011

2013

2015

2017

2019

Year

NAD North Sumatra North Sumatra System

Peak

Loa

d (M

W)

(Low Case)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2003

2005

2007

2009

2011

2013

2015

2017

2019

Year

NAD North Sumatra North Sumatra System

Peak

Loa

d (M

W)

(High Case)

Figure 2.3.1 Power Demand in Northern Sumatra System

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Table 2.3.2 Power Demand in South-West Sumatra System Low Case High Case

Total GR (%) Total System Isolated Total System Isolated Total GR (%) Total System Isolated Total System Isolated

GWh % GWh GWh GWh MW MW MW GWh % GWh GWh GWh MW MW MW

2002 5,627 6,746 5,711 1,034 1,291 1,053 238 2002 5,627 6,746 5,711 1,034 1,291 1,053 238

2003 5,840 3.8 6,999 5,901 1,098 1,390 1,139 251 2003 5,840 3.8 6,999 5,901 1,098 1,390 1,139 251

2004 6,252 7.1 7,431 6,284 1,147 1,445 1,198 248 2004 6,290 7.7 7,475 6,326 1,149 1,454 1,206 248

2005 6,715 7.4 7,933 6,752 1,181 1,541 1,285 256 2005 6,811 8.3 8,045 6,859 1,187 1,563 1,306 257

2006 7,212 7.4 8,471 7,234 1,236 1,642 1,378 265 2006 7,455 9.5 8,755 7,497 1,258 1,698 1,428 270

2007 7,736 7.3 9,036 7,759 1,277 1,749 1,476 272 2007 8,162 9.5 9,532 8,214 1,318 1,846 1,564 282

2008 8,287 7.1 9,625 8,336 1,290 1,860 1,584 276 2008 8,932 9.4 10,373 9,021 1,352 2,006 1,716 289

2009 8,862 6.9 10,225 8,947 1,277 1,973 1,703 269 2009 9,768 9.4 11,268 9,910 1,358 2,176 1,889 287

2010 9,463 6.8 10,889 9,524 1,365 2,098 1,810 287 2010 10,672 9.3 12,276 10,802 1,474 2,367 2,056 310

2011 10,091 6.6 11,565 10,115 1,450 2,224 1,920 304 2011 11,648 9.2 13,347 11,756 1,592 2,570 2,235 335

2012 10,746 6.5 12,268 10,730 1,538 2,356 2,041 315 2012 12,704 9.1 14,501 12,788 1,712 2,788 2,436 352

2013 11,429 6.4 12,999 11,401 1,599 2,493 2,160 333 2013 13,843 9.0 15,742 13,930 1,811 3,023 2,644 378

2014 12,143 6.2 13,779 12,111 1,668 2,638 2,292 346 2014 14,802 6.9 16,791 14,879 1,912 3,218 2,821 398

2015 12,888 6.1 14,591 12,852 1,739 2,790 2,430 360 2015 15,795 6.7 17,876 15,863 2,013 3,420 3,003 417

2016 13,667 6.0 15,439 13,628 1,811 2,948 2,574 374 2016 16,833 6.6 19,007 16,891 2,116 3,630 3,193 437

2017 14,481 6.0 16,323 14,439 1,884 3,112 2,724 388 2017 17,924 6.5 20,195 17,974 2,222 3,851 3,393 458

2018 15,332 5.9 17,247 15,287 1,960 3,284 2,881 403 2018 19,076 6.4 21,448 19,117 2,331 4,083 3,604 479

2019 16,222 5.8 18,213 16,176 2,037 3,463 3,045 418 2019 20,296 6.4 22,774 20,329 2,444 4,328 3,827 5012020 17,154 5.7 19,222 17,106 2,116 3,650 3,216 433 2020 21,590 6.4 24,178 21,616 2,562 4,587 4,063 524

Supply in the Region Peak LoadDemand Supply in the Region Peak Load Demand

0

500

1,000

1,500

2,000

2,500

3,000

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4,500

2003

2005

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Year

Bengkulu LampungSouth Sumatra JambiWest Sumatra RiauSouth Sumatra System

Peak

Loa

d (M

W)

(Low Case)

0

500

1,000

1,500

2,000

2,500

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3,500

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4,500

2003

2005

2007

2009

2011

2013

2015

2017

2019

Year

Bengkulu LampungSouth Sumatra JambiWest Sumatra RiauSouth Sumatra System

Peak

Loa

d (M

W)

(High Case)

Figure 2.3.2 Power Demand in South-West Sumatra System

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Chapter 3 Power Deficits Possibility and Short-Term Countermeasures

This chapter will first discuss the possibility of power deficits in the Sumatra systems in the near future. The focus will be on a short-term period until 2006 as new power plants that can be developed in a short period of time can be commissioned after 2007. Power deficits will be identified using the WASP-IV5 simulation tool, taking into account the power supply and demand balance in Sumatra systems until 2006. Then, this chapter will discuss short-term countermeasures to avoid the power deficits and minimize the influence of such deficits as much as possible. 3.1 Identification of Power Deficits in Sumatra System 3.1.1 Power Plants in Sumatra System

As shown in Table 3.1.1, the Sumatra power system has 2,928 MW of installed capacity as of April

2004 and its dependable capacity is 2,465 MW (See Appendix II for detail information on power plants in the North Sumatra system and the South-West Sumatra system). The balance of 463 MW is mainly the sum of thermal power derating.

Table 3.1.1 Summary of Power Plants in the Sumatra System (as of April 2004)

PLTAPLTMH PLTD PLTG PLTU PLTGU Total

(a)

69.500 74.670 123.132 260.000 817.880 1,345.182 45.9% 49 1,137.324 207.858(5.2%) (5.6%) (9.2%) (19.3%) (60.8%) (100.0%) (84.5%) (15.5%)

367.500 5.100 107.250 200.000 0.000 679.850 23.2% 24 558.600 121.250(54.1%) (0.8%) (15.8%) (29.4%) (0.0%) (100.0%) (82.2%) (17.8%)136.960 220.928 259.766 285.000 0.000 902.654 30.8% 75 769.380 133.274(15.2%) (24.5%) (28.8%) (31.6%) (0.0%) (100.0%) (85.2%) (14.8%)504.460 226.028 367.016 485.000 0.000 1,582.504 54.1% 99 1,327.980 254.524(31.9%) (14.3%) (23.2%) (30.6%) (0.0%) (100.0%) (83.9%) (16.1%)573.960 300.698 490.148 745.000 817.880 2,927.686 100.0% 148 2,465.304 462.382(19.6%) (10.3%) (16.7%) (25.4%) (27.9%) (100.0%) (84.2%) (15.8%)

North Sumatra System(A)

South Sumatra System(C)

South-West SumatraSystem (B+C)

Sumatra Total (A+B+C)

West Sumatra System(B)

DependableCapacity

(MW)(b)

CapacityDerating

(MW)(c=a-b)

Total Installed Capacity (MW)

Name of Power SystemNo.of

Unit

% ofSumatra

Total

5 Refer to Section 5.6 Least-cost Generation Development Planning in this report for more information about the WASP-IV simulation tool.

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0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

PLTGU 60.8% 0.0% 0.0% 0.0% 27.9%PLTU 19.3% 29.4% 31.6% 30.6% 25.4%PLTG 9.2% 15.8% 28.8% 23.2% 16.7%PLTD 5.6% 0.8% 24.5% 14.3% 10.3%PLTA PLTMH 5.2% 54.1% 15.2% 31.9% 19.6%

North SumatraSystem

West SumatraSystem

South SumatraSystem

South-WestSumatraSystem

Sumatra Total

Figure 3.1.1 Installed Capacity in the Sumatra Figure 3.1.2 Power Mix by System

System (as of April 2004) in Sumatra (as of April 2004)

3.1.2 Possibility of Power Deficits in the Sumatra System

This section will examine the possibility of power deficits in the Sumatra system. The target period for this examination is for a short term until 2006 because it is assumed that gas turbine thermal power, which can be developed in a short period, will be commissioned in 2007 at the earliest. The possibility of power deficits in the North and the South-West systems will be identified using WASP-IV simulation and by analyzing the necessary power supply capabilities to secure certain system reliability6. (1) Power Supply Reliability until 2006

Tables 3.1.2 and Table 3.1.3 show the results of LOLP analysis in the North and South-West systems from 2004 to 2006 by applying WASP-IV simulation. Table 3.1.4 and Table 3.1.5 show the simulation conditions for those power plants that have already started operations or are scheduled to start operations.

Table 3.1.2 LOLP in the North System (Low Demand Case) (High Demand Case)

6 LOLP<3 days/year (0.822%)

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800MW

PLTGU 817.880 0.000 0.000 0.000PLTU 260.000 200.000 285.000 485.000PLTG 123.132 107.250 259.766 367.016PLTD 74.670 5.100 220.928 226.028PLTA PLTMH 69.500 367.500 136.960 504.460

North SumatraSystem

West SumatraSystem

South SumatraSystem

South-WestSumatraSystem

1,345MW

680MW 903MW

1,583MW

2004 2005 2006Demand (MW) 1,076.7 1,138.4 1,209.9Installed Capacity (MW) 1,385.9 1,532.9 1,532.9Dependable Capacity* (MW) 1,217.4 1,364.4 1,364.4LOLP 3.945% 1.261% 2.682%Reserve Margin 28.7% 34.7% 26.7%*Note: No capacity derating for hydropower

LOLP > 0.822% (3 days/year)

YearItem


LOLP > 0.822% (3 days/year)

YearItem

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Table 3.1.3 LOLP in the South-West System (Low Demand Case) (High Demand Case)

Table 3.1.4 Power Development Plan in the North System

(Unit: MW)

2004 2005 2006PLTA Sipansihaporas 1 33 33PLTA Renun 82 82Inalum additional capacity 65 65

Total 33 147 0 180

YearPower Plant Total

Table 3.1.5 Power Development Plan in the South-West System (Unit: MW)

2004 2005 2006PLTG Palembang Timur GT 100 100PLTG Truck Mounted 40 40PLTG Indralaya 40 40PLTG Talang Dukuh 2 15 15PLTGU Palembang Timur CC 50 50PLTG Apung 33 33PLTG Pulo Gadung 18 18PLTA Musi 210 210

Total 195 101 210 506

YearPower Plant Total

Table 3.1.2 shows that LOLP is expected to be over 3 days / year (0.822%) under both cases up to 2006 because only 180MW in new capacity will be installed in the North Sumatra system during this period. In addition, most of the reserve margins in the period are expected to be below 30%. This result suggests that there is the strong possibility of power deficits in the North Sumatra system up to 2006.

In the South-West Sumatra system, on the other hand, the LOLP and reserve margin are expected to be below 3 days / year (0.822%) and over 40% under for both cases up to 2006, respectively, because new capacity of more than 100 MW will be installed every year. Therefore, the possibility of power deficits is quite small in the South-West Sumatra system.


YearItem


YearItem

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(2) Necessary Additional Capacity to Secure System Reliability

Table 3.1.6 shows the additional capacities7 needed in the North Sumatra system to secure system reliability (LOLP<3days/year or 0.822%). The necessary additional capacities were calculated by subtracting the installed capacities in Table 3.1.6 from those in Table 3.1.2.

Table 3.1.6 Additional Capacity Needed in the North System to Secure System Reliability (Low Demand Case) (High Demand Case)

As shown in Table 3.1.6, the North Sumatra system needs the additional capacities of 50 MW to

150 MW every year until 2006 in order to maintain good system reliability that accounts for 3% to 10% of the total installed capacities in the North Sumatra system. 3.2 Short-Term Countermeasures

The power deficit was identified in the previous Section 3.1. As a result, power deficits in the North system are anticipated to be between 50MW ~ 150MW in 2005 and 2006.

In this section countermeasures against power deficits will be discussed in order to avoid the power deficits or to minimize the influence of the power deficits from the viewpoint of operation at existing power plants and operational control of the power system as short-term countermeasures. Although short-term countermeasures against power deficits are particularly necessary in the North system, the short-term countermeasures in the South-West system will also be discussed because countermeasures for the operation of existing power plants is effective for the South-West system from the viewpoint of efficient operation of power plants.

7 Plural 50MW gas turbine units are assumed to be an emergency countermeasure.

2004 2005 2006Demand (MW) 1,076.7 1,138.4 1,209.9Installed Capacity (MW) 1,535.9 1,582.9 1,682.9Dependable Capacity* (MW) 1,367.4 1,414.4 1,514.4LOLP 0.678% 0.660% 0.456%Reserve Margin 42.6% 39.0% 39.1%*Note: No capacity derating for Hydropower

Necessary Additional Capacity for LOLP < 0.822% (3 days/year)

2004 2005 2006Necessary Additional Capacity (MW) 150.0 50.0 150.0

ItemYear

YearItem 2004 2005 2006

Demand (MW) 1,080.7 1,148.4 1,243.5Installed Capacity (MW) 1,535.9 1,582.9 1,682.9Dependable Capacity* (MW) 1,367.4 1,414.4 1,514.4LOLP 0.714% 0.751% 0.701%Reserve Margin 42.1% 37.8% 35.3%*Note: No capacity derating for Hydropower

Necessary Additional Capacity for LOLP < 0.822% (3 days/year)

2004 2005 2006Necessary Additional Capacity (MW) 150.0 50.0 150.0

ItemYear

YearItem

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3.2.1 Effective Operation of Existing Power Plants Securing the proper operations for existing power plants is the most effective and important

short-term countermeasures against power deficit. Specifically, problems must be avoided by: ○ Avoiding fuel shortages by securing a fuel supply with the proper quality ○ Reducing the forced outage rate by securing proper operations and maintenance ○ Shortening the maintenance period by carrying out proper periodical inspection ○ Improving the reservoir management for hydropower plants from the viewpoint of peak

supply (1) Fuel Supply with Proper Quality

The Ombilin and Bukit Asam thermal power plants in the South-West system should secure a coal fuel supply with the proper quality.

Belawan PLTGU in the North system has recently encountered gas fuel shortages due to an insufficient gas supply from PERTAMINA. It is necessary to negotiate with PERTAMINA to secure a proper gas supply. (2) Reduction of Forced Outage Rate

It is very important to analyze the cause of the power plant problems and to study the preventive measures in order to secure a stable supply power.

The following are countermeasures by generation facility to reduce the problems, considering the results of the analysis described in the previous section. (i) Diesel Power Plants

The large number of emergency trips and the inability to start likely affect stable system operation, even though the installed capacity is relatively small. In order to avoid the spread of trouble to other power plants (ripple effect), reducing the number of problems will be necessary. Since most diesel power plants are old, prospective maintenance such as parts replacement should contribute to reducing these problems. (ii) Steam Turbine Power Plants

Since there are many problems in the fuel handling-and-supply system, specifically at coal-fired power plants (e.g. trip of coal mill), countermeasures focusing on the fuel coal can be very effective. Since fuel coal with low specifications is likely to be used in these plants, the first step will be to study the coal specifications. If the coal specifications can not be changed, capacity expansion of the fuel supply system, such as by replacing the mill with one of a bigger size, will be effective as short term countermeasures.

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(iii) Gas Turbine Power Plants Further study is necessary for the spare parts issues by reviewing the records of periodic repairs

because the data here is not likely to show the actual picture. As for the short term countermeasures, conducting the appropriate maintenance of diesel start-up motors is seen as an easy and effective solution. (iv) Hydropower Plants

The number of hydropower plant problems accounting for 11% of all problems. Forty two percent of all hydropower problems can be attributed to problems related to system troubles. Although the remaining problems (58％) were caused by the equipment, further study is needed to confirm the specific reasons. (v) Others

Operation of the Sumatra system is now very tight because of frequent power shortages and a lack of spinning reserve. Therefore, it is readily assumed that increases in generator problems and in the number of generators would lead to a lack of supply power; falling into the so-called vicious cycle. This is because the generators must be operated under severe conditions. (3) Proper Repair and Inspection of Adjustment of Periodic Inspection (i) Proper Scheduling of Periodic Inspections

The maximum power demand occurs between October and December in Sumatra. In addition, the available capacity of hydropower plants decreases during the dry season. To make up for this reduction, periodic repairs for the thermal power plant could be shifted to the period when maximum demand does not occur. Adjustable capacity by shifting (shift capacity) can be identified by reviewing operation records of the thermal power plant. (ii) Maintain and Shorten the Work Schedule for Periodic Inspections

Periodic inspections require a period for about a few weeks or months. It is very important to carry out the periodic inspections in accordance with the working schedule, to complete it on schedule and to shorten its period. (iii) Extended Operation of Power Plants

To relieve the tight situation, the interval for thermal power periodic repairs could be extended during this period. Thus, the capacity under maintenance is reduced. (4) Rehabilitation

Rehabilitation of old power plants is one of the most effective short-term countermeasures against power deficit. However, when investing in older power units, cost performance and its remaining lifetime should to be considered. Moreover, the improvement in performance through rehabilitation is rather limited.

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Example of rehabilitation:

(i) Replacement of high-pressure feed water heaters (ii) Replacement of steam turbine blades (iii) Jet cleaning of high-pressure heaters and chemical cleaning of boilers

(5) Improvement of Operations

Since inadequate operations cause problems such as dropping thermal efficiency and output derating, it is important to optimize power plant operations.

The thermal efficiency of many power plants can be improved through operational improvements. Thermal efficiency affects fuel consumption and primary energy consumption in Sumatra. Therefore, the theory and method of operational improvement should be introduced and carried out in all power plants in Sumatra. (6) Improvement of Reservoir Management for Hydropower Plants from Viewpoint of Peak

Supply Hydropower plant capacity derating should not be neglected during dry seasons in the South-West

system. Specifically, the output of run-of-river type hydropower plants depends directly on river flow. On the other hand, reservoir-type hydropower plants are operated on a periodical operation schedule such as annual, seasonal, weekly and daily. Therefore, there are some opportunities to increase power supply during the dry season and during the peak hours of each day as much as possible by reviewing the periodical operational schedule based on past inflow statistics.

If hydropower plants increase their dependable capacities during peak hours (around 4 hours) by improving daily reservoir management, dependable capacity at peak hours is likely to be increased, especially during the dry season. In this case, needless to say, a sufficient plant operation plan has to be made taking into account the impacts downstream of the power plant outlet due to increases in water discharge, as proper water supply for water utilization downstream of the outlet. 3.2.2 Operational Control of a Power System under Power Deficit (1) Brown Outs

Brown outs have already been carried out in the Sumatra system. About a 5% reduction in voltage decreases the actual demand by operating substations at 19kV instead of 20kV. Therefore, the brown out has already been confirmed technically in the Sumatra system. However, when brown outs are considered in the planning of the supply and demand balance, it should be assumed that brown outs are just one of emergency countermeasures in which low quality electricity can be continuously supplied.

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(2) Rotational Black Outs Rotational black outs are carried out only in the case that the power system can not maintain stable

operations when the power supply can not meet demand. The basic concept is as follows:

- Divide supply areas into certain groups in advance. - If a power deficit occurs, the power supply to one of the groups would be stopped. - Then the black out is rotated among these groups.

(3) Demand-Side Measures (i) Captive Buyout

Captive power supplies have large supply capacity and are extremely important in the context of Indonesia’s electrical power supply and demand. Table 4.2.5 shows the captive supply capacity connected to the system. Electricity is received constantly from PLN, but captive sources, which are used as backups against power outages, amount to 710,140kVA in the Sumatra system, 171,293kVA in the North system and 538,847kVA in the South-West system, respectively. However, the usual captive power in the Sumatra system does not have surplus power. Even if a captive power has surplus power, it is too far from the PLN's grid system. Therefore, available captive power is very limited. (ii) Energy-Saving Information for Large-Scale Clients

Until the supply and demand adjustment menu is in place, one effective measure is to request that large-scale consumers save energy in cases where the capacity of the supply operation is likely to fall short. The specific effects are unclear, but it is important to ensure that users are well informed on the importance of energy saving and peak cutting in order to facilitate users cooperation. (iii) Load Adjustment Contracts

Japanese power companies sign Load Adjustment Contracts with specific users in order to manage demand at times when the supply and demand situation is tight. Clients signing such contracts gain discounts on electricity tariffs in return for taking on the responsibility of controlling their demand. As mentioned in the previous subsection, there have also been cases of voluntary cooperation in energy saving, which indicates that there is a high potential for users to agree to Load Adjustment Contracts. (iv) Adjustment of New Users

In cases where it is anticipated that growth in demand will exceed planned levels, and supply capacity will not keep pace, measures for demand control will be necessary. These include a temporary freeze on contracts with new users.

4-1

Chapter 4 Generation Development Plan

As of the 2004 year-end, electricity in Sumatra was mainly serviced by two PLN systems, the North Sumatra system and South-West Sumatra system. Based on the demand forecast discussed in Chapter 2, the Study team formulated generation development plans (Least-cost Case) for each system by simulation of WASP-IV, in which the cost for expansion and operation of the system during the study period (hereinafter referred to as “system cost”) is minimized.

On the other hand, PLN has a plan for an interconnection between the North system and the

South-West system involving the construction of an interconnection transmission line and this plan shows that the Whole Sumatra system will provide electricity in Sumatra in the future. Therefore, the Study team also formulated a generation development plan (Least-cost Case) for all of Sumatra and evaluated the economic efficiency of the interconnection and appropriate year for interconnection by comparing development plans for separate systems.

Moreover, case studies and sensitivity studies on uncertain preconditions are discussed because a generation development plan heavily depends on preconditions on the formulation of the plan. Finally, the proposed plan is put in the Study.

4.1 Reviewing Historical Demand

Figure 4.1.1 shows the target power systems for generation development planning in the Study.

Figure 4.1.1 Target Power Systems for Generation Development Planning

.

West Sumatra

Riau

North Sumatra

Aceh

Jambi

Bengkulu Lampung

South Sumatra

Whole Sumatra Interconnected System

Noth Sumatra System (Sumut-Aceh System)

South-West Sumatra System (Sumbagsel-Sumsel-Riau-Jambi System)

4-2

4.2 Generation Development Plan for the North and the South-West Sumatra System (Least-cost Case) 4.2.1 Preconditions of Simulation (North Sumatra System and South-West Sumatra System) (1) Common preconditions for both systems

Table 4.2.1 Preconditions for Simulation (common to both systems)

Item Precondition Remarks Study Period Until year of 2020 Number of Periods in a Year 4 periods in a year - Considering seasonal fluctuation of demand and

supply capacityHydro Conditions 3 conditions - Rich, Normal and Dry conditions with the

probability of occurrence being 15%, 70%, 15% Demand Peak Demand - Refer to Tables 2.3.1 and 2.3.2 Load Duration Curve

(LDC) - Created the LDCs based on actual generation records

in each system - No change to LDC throughout the study period

System Reliability - 2006 : not applicable 2007 - : LOLP 0.822% and below

- After the year of 2007 when the development of new candidate plants will be possible

Discount Rate 12 % - Same as the figure in the PLN power development Cost for Un-served Energy (ENS8 Cost）

0.5 US$/kWh - Assumed at around two-thirds of the figure (US$0.85 /kWh) in the Jawa-Bali system

(2) Fixed development project

Table 4.2.2 Fixed Development Projects for Simulation

System Year Type Name of Project Installed Capacity Fuel Remarks

North 2004 Hydro Sipahsihaporas 1 33.0 MW - Add on 2005 Hydro (Pondage) Renun 82.0 MW - 2008 Steam Turbine Labuhan Angin 230.0 MW Coal

2009,2010 Geothermal Sarulla*1 165.0 MW Geo 2012 Hydro (ROR9) Asahan III 151.0 MW －

South-West 2004 Gas Turbine Palembang Timur (GT Open Cycle) 100.0 MW Gas Open Cycle 2004 Gas Turbine Truck Mounted 20.0 MW Gas 2004 Gas Turbine Indralaya 40.0 MW Gas 2004 Gas Turbine Talang Dukuh 2 15.0 MW Gas 2005 Combined Cycle Palembang Timur (Combined Cycle) 50.0 MW*2 Gas Combined Cycle 2005 Gas Turbine Apung 33.0 MW Gas Relocation 2005 Gas Turbine Pulo Gadung 18.0 MW Gas 2006 Hydro (Pondage) Musi 210.0 MW － 2007 Steam Turbine Tarahan 1, 2 200.0 MW Coal 2010 Combined Cycle Keramasan 82.0 MW Gas 2010 Geothermal Ulu Belu 110.0 MW Geo *1: Although the project is not committed as of the end of 2004, PLN has the right for development and hopes to commence

development in 2009 and 2010 with the capacity of 100MW and 55MW, respectively. *2: Additional Capacity

8 Energy Not Served 9 Run of River

4-3

(3) Recovered unit

Table 4.2.3 shows the list of future reinstalled units after maintenance works for simulation.

Table 4.2.3 Future Recovered Units for Simulation

System Year Type Name of Plant Installed Capacity Fuel RemarksSouth-West 2005 Gas Turbine Keramasan 2 11.750 MW Gas 2005 Diesel Payo Se'lincah 5 5.218 MW HSD

(4) Retirement or relocation units

The simulation considered the decommissioning of all diesel units for retirement or relocation in the near future due to the high generation costs. Moreover, the retirement of some existing generation units is under consideration due to their aging. The table in Appendix III shows the list of units for retirement and relocation. (5) Candidate generation units for development

Table 4.2.4 shows the details of candidate generation units for the North Sumatra system and the South-West Sumatra system. The Study team assumed that the North system has no candidate units fueled by natural gas in consideration of the availability of the future gas supply in the region. Table 4.2.4 Characteristics of Candidate Generation Units for the North and South-West Sumatra System

(Least-cost Case)

Thermal Power Hydropower10 Steam

Turbine Gas Turbine

Combined Cycle*3 Asahan I ROR Reservoir 2 Merangin Reservoir 1

Abbreviation ST GT CC ASH1 ROR RES2 MRG RES1

System North Sumatra South-West Sumatra South-West North Sumatra South-West Sumatra

Installed Capacity (MW) 100 50 150 180 100 400 350 100

Development Cost*1 (US$/kW) 1,000 450 600 1,461 1,700 1,400 1,217 1,500

Life Time (Year) 30 20 20 50 50 50 50 50 Construction Period (Year) 3.0 2.0 2.5 5.0 4.0 6.0 5.5 5.0

Fuel Type Coal HSD Gas - - - - - 30.0

US$/ton 0.22

US$/Ltr-fuel3.5

US$/MMBTU- - - - -

Fuel Cost

566 2,439 1,389 - - - - Heat Rate*2

(kCal/kWh) 2,324 2,529 1,870 - - - - -

Developed Year On and after 2008

On and after 2007

On and after 2008 On and after 2012

*1: Excludes interest during construction *2: At maximum operation capacity *3: Take-or-pay contracts were considered for gas-fired combined cycle generation units in the South-West Sumatra system.

10 Asahan No.1 and Merangin HPP projects were prepared as identified candidate project because Engineering Designs for these projects have

already been made. Model candidate plants were prepared based on the existing Feasibility Study.

(US$/Unit-fuel)

(cent/MkCal)

4-4

4.2.2 Simulation Results (North Sumatra System and South-West Sumatra System)

Table 4.2.5 shows the output of WASP-IV simulation involving newly developed capacity in the Least-cost Case for the North Sumatra system and the South-West Sumatra system and Table 4.2.6 shows system costs up until 2020 for each system.

Table 4.2.5 Output of WASP-IV Simulation for the North and South-West System (Least-cost Case)

Table 4.2.6 System Cost for the North and South-West Sumatra System (Least-cost Case)

(Unit : million US$, NPV in 2003) (Unit : million US$, NPV in 2003)

Low High Low High

(1) Construction Cost 610 977 (1) Construction Cost 557 911

(2) Salvage Value 79 143 (2) Salvage Value 106 140

(3) Operation Cost 2,311 2,474 (3) Operation Cost 2,028 2,289

(4) ENS Cost 32 37 (4) ENS Cost 5 7

System Cost System Cost

(1) - (2) + (3) + (4) (1) - (2) + (3) + (4)2,874 3,345

ItemDemand Case

ItemDemand Case

2,484 3,067

(Unit : MW)

Peak PeakDemand Demand(MW) (MW)

2003 973.1 2003 973.12004 1,076.7 2004 1,080.72005 1,138.4 2005 1,148.42006 1,209.9 2006 1,243.52007 1,285.4 2007 1,347.32008 1,353.8 2008 1,448.02009 1,439.6 2009 1,572.62010 1,526.6 2010 1,704.02011 1,603.6 2011 1,829.62012 1,683.2 2012 1,963.92013 1,766.1 2013 2,108.02014 1,852.3 2014 2,235.72015 1,942.1 2015 2,370.92016 2,035.8 2016 2,514.22017 2,133.5 2017 2,666.12018 2,235.6 2018 2,827.42019 2,342.3 2019 2,998.82020 2,453.9 2020 3,180.9

*1 : Asahan I*2 : Run-of-River Type 100MW*3 : Reservoir Type 400MW

Developed Capacity (MW) Total 1,330 MW Capacity (MW) Total 2,080 MW

900 250

3Total 15 units Total 20 units

680180 Developed 1,100 300

100

Hydro

Number of Units

9 5 1 Number of Units

11 6

Low Demand Case High Demand Case

Year ST GT Hydro Year ST GT

200

200

50

180*1

100

100100100

200

100200

250

50

300100200

100

180*1

100*2

400*3100

(Unit : MW)


2003 1,138.7 2003 1,138.72004 1,197.7 2004 1,206.12005 1,284.8 2005 1,305.62006 1,377.5 2006 1,428.32007 1,476.4 2007 1,564.12008 1,584.4 2008 1,716.42009 1,703.4 2009 1,889.02010 1,810.4 2010 2,056.42011 1,920.0 2011 2,235.12012 2,040.8 2012 2,436.32013 2,159.6 2013 2,644.52014 2,291.8 2014 2,820.62015 2,429.6 2015 3,002.82016 2,573.5 2016 3,193.02017 2,723.8 2017 3,392.82018 2,880.7 2018 3,603.62019 3,044.8 2019 3,826.72020 3,216.4 2020 4,063.1

*1 : Substitution unit of coal-fired thermal power plant taking into consideration the lack of supply capacity in Pekanbaru in the near future.

*2 : Merangin*3 : Reservoir Type 100MW*4 : Reservoir Type 100MW x 2units

300

300

200

200100

100200

100

100

200

350*2

100*3


Year ST GT Hydro Year ST GT CC

100

Hydro

Number of Units


12 2

0


550550 Developed 1,200 100

6

Capacity (MW) Total 1,700 MW Capacity (MW) Total 2,750 MW Developed

CC

150*1

3

450

150

150

700 900

150300

150*1

150150

350*2

200*4

100*3

100

( North Sumatra System ) ( South-West Sumatra System )

( North Sumatra System ) ( South-West Sumatra System )

4-5

4.3 Generation Development Plan for the Whole Sumatra System (Least-cost Case) 4.3.1 Preconditions of Simulation (Whole Sumatra System)

Preconditions shown in sections 4.2.1 (1) to (4) were also adopted in the simulation for the Whole Sumatra system. The other preconditions used only for the simulation in the Least-cost Case for the Whole Sumatra system are shown below. (1) Interconnection year

The simulation adopted the year of 2009 for the commissioning of the interconnection line based on PLN’s plan. (2) Peak demand and load duration curve

The sum of the forecasted peak demands for each system shown in Tables 2.3.1 and 2,3,2 is adopted as the peak demand for the simulation11. In terms of the load duration curve, the Study team adopted the load duration curve that was created by the summation of hourly demands in each system in 2003 in chronological order. (3) Development plan before interconnection

The development plan for the separate systems was used for the plan before interconnection. (4) Development cost for interconnection transmission line

The Study team assumed a length of 290km and a project cost of US$58 million for the interconnection transmission line. (5) Candidate generation unit for development

Table 4.3.1 Details of Candidate Generation Units for the Whole Sumatra System (Least-cost Case)

Thermal Power Hydropower Steam

Turbine Gas Turbine

CombinedCycle*3 Asahan I ROR Reservoir 2 Merangin Reservoir 1

Abbreviation ST GT CC ASH1 ROR RES2 MRG RES1 Installed Capacity (MW) 100 50 150 180 100 400 350 100 Development Cost*1 (US$/kW) 1,000 450 600 1,461 1,700 1,400 1,217 1,500

Life Time (Year) 30 20 20 50 50 50 50 50 Construction Period (Year) 3.0 2.0 2.5 5.0 4.0 6.0 5.5 5.0 Fuel Type Coal HSD Gas - - - - -

30.0 US$/ton

0.22US$/Ltr-fue

l

3.5US$/MMBT

U

- - - - － Fuel Type 566 2,439 1,389 - - - - Heat Rate*2 (kCal/kWh) 2,324 2,529 1,870 - - - - -

Developed Year On and after 2008

On and after 2007

On and after 2008 On and after 2012

*1 Excludes interest during construction *2 At maximum operation capacity *3 Take-or-pay contracts were considered for gas-fired combined cycle generation unit.

11 The difference between the peak demand between the sum of the annual peak demands of each systems and the combined demands in

chronological order, was negligible based on comparisons between both peak demands

(US$/unit-fuel)

(cent/Mkcal)

4-6

4.3.2 Simulation Results (Whole Sumatra System)

Table 4.3.2 shows the output of WASP-IV simulation involving newly developed capacity in the Least-cost Case for the Whole Sumatra system and Table 4.3.3 shows system costs up until 2020.

Table 4.3.2 Output of WASP-IV Simulation for the Whole Sumatra System (Least-cost Case)

Table 4.3.3 System Cost for the Whole Sumatra System (Least-cost Case)

(Unit : million US$, NPV in 2003)

Low High

(1) Construction Cost 1,197 1,804

(2) Salvage Value 224 285

(3) Operation Cost 4,242 4,679

(4) ENS Cost 33 39

System Cost

(1) - (2) + (3) + (4)5,248 6,237

ItemDemand Case

(Unit : MW)


2003 2,111.8 2003 2,111.82004 2,274.4 2004 2,286.82005 2,423.2 2005 2,454.02006 2,587.4 2006 2,671.82007 2,761.8 2007 2,911.42008 2,938.2 2008 3,164.42009 3,143.0 2009 3,461.62010 3,337.0 2010 3,760.42011 3,523.6 2011 4,064.72012 3,724.0 2012 4,400.22013 3,925.7 2013 4,752.52014 4,144.1 2014 5,056.32015 4,371.7 2015 5,373.72016 4,609.3 2016 5,707.22017 4,857.3 2017 6,058.92018 5,116.3 2018 6,431.02019 5,387.1 2019 6,825.52020 5,670.3 2020 7,244.0

*1 : Substitution unit of coal-fired thermal power plant taking into consideration the lack of supply capacity in Pekanbaru in the near future.*2 : Asahan I*3 : Run-of-River Type 100MW*4 : Merangin*5 : Reservoir Type 100MW x 2 units*6 : Reservoir Type 400MW

180*2

200*5 450*3*4

750

150

150*1

150

Developed

CC

150*1

1

1501,300 Capacity (MW) Total 2,880 MW Capacity (MW) Total 4,530 MW

200


1,2301,230 Developed 2,300 250

5

Hydro

Number of Units


23 5



300

200

350*4

200

200300300

180*2

200*5

250

400100300

300100

100*3

300300200

400200

400*6

400*6

4-7

4.4 Examination on Interconnection Transmission Line

4.4.1 Advantages of Interconnection in Generation Development Plan

The general advantages of interconnecting several systems in generation development planning are as shown below.

1) Reduction of the impact of forced outages on the operation of the system 2) Possibility of eliminating unbalanced formation of power sources caused by unbalanced

distribution of primary resources such as fossil fuel, steam energy for geothermal and water resource for hydropower

3) Reduction of the reserve capacity to meet the target supply reliability of the system Consequently, it seems that the generation development in interconnected systems is economically

superior to the generation development in separate systems. The Study team evaluated the economic efficiency of interconnections between the North Sumatra

system and the South-West Sumatra system by comparing both development plans in the estimated system costs up until 2020.

4.4.2 Comparison of Generation Development Plans Tables 4.4.1, 4.4.2 and 4.4.3 show the results of the comparison of both development plans

(Least-cost Case).

Table 4.4.1 Comparison of Installed Capacity in 2020

Low Demand Case (Unit : MW)

Hydropower 2,238.0 （33.3%） 473.5 （16.0%） 1,264.5 （32.4%） 1,738.0 （25.3%） 500.0Steam Turbine 2,215.6 （32.9%） 1,130.0 （38.1%） 1,385.6 （35.5%） 2,515.6 （36.6%） -300.0Combined Cycle 1,199.9 （17.8%） 817.9 （27.6%） 682.0 （17.5%） 1,499.9 （21.8%） -300.0Gas Turbine 685.8 （10.2%） 270.5 （9.1%） 465.3 （11.9%） 735.8 （10.7%） -50.0Diesel 0.0 （0.0%） 0.0 （0.0%） 0.0 （0.0%） 0.0 （0.0%） 0.0Geothermal 275.0 （4.1%） 165.0 （5.6%） 110.0 （2.8%） 275.0 （4.0%） 0.0Special Supply 110.0 （1.6%） 110.0 （3.7%） 0.0 （0.0%） 110.0 （1.6%） 0.0

Total 6,724.2 （100.0%） 2,966.9 （100.0%） 3,907.3 （100.0%） 6,874.2 （100.0%） -150.0

High demand Case (Unit : MW)

Hydropower 2,238.0 （26.7%） 973.5 （26.2%） 1,264.5 （25.5%） 2,238.0 （25.8%） 0.0Steam Turbine 3,215.6 （38.4%） 1,330.0 （35.8%） 1,885.6 （38.0%） 3,215.6 （37.1%） 0.0Combined Cycle 1,799.9 （21.5%） 817.9 （22.0%） 1,132.0 （22.8%） 1,949.9 （22.5%） -150.0Gas Turbine 735.8 （8.8%） 320.5 （8.6%） 565.3 （11.4%） 885.8 （10.2%） -150.0Diesel 0.0 （0.0%） 0.0 （0.0%） 0.0 （0.0%） 0.0 （0.0%） 0.0Geothermal 275.0 （3.3%） 165.0 （4.4%） 110.0 （2.2%） 275.0 （3.2%） 0.0Special Supply 110.0 （1.3%） 110.0 （3.0%） 0.0 （0.0%） 110.0 （1.3%） 0.0

Total 8,374.2 （100.0%） 3,716.9 （100.0%） 4,957.3 （100.0%） 8,674.2 （100.0%） -300.0

InterconnectedSystem

(a)South-West Total Balance

(a) - (d)

Separate SystemBalance(a) - (d)

(c) (d)South-West TotalPlant Type


(a)

NorthPlant Type

North(b)

Separate System

(b) (c) (d)

4-8

Table 4.4.2 Comparison of Investment Cost up until 2020

Table 4.4.3 Comparison of System Cost up until 2020

In both demand cases the installed capacity in 2020 for the Whole Sumatra system is smaller than the sum of the installed capacities in 2020 of the North system and the South-West system. The difference seems to result from the advantage of 3) shown in section 4.4.1 and this result shows that the construction of an interconnection transmission line in 2009 would contribute to the economical expansion of the power system. Correspondingly, the system cost up until 2020 for the Whole system are less than the system cost for the separate systems.

Low Demand Case (Unit : million US$)

Hydropower 1,719.0 （48.9%） 263.0 （17.2%） 726.0 （42.8%） 989.0 （30.7%） 730.0Steam Turbine 1,300.0 （37.0%） 900.0 （58.8%） 700.0 （41.3%） 1,600.0 （49.6%） -300.0Combined Cycle 90.0 （2.6%） 0.0 （0.0%） 270.0 （15.9%） 270.0 （8.4%） -180.0Gas Turbine 90.0 （2.6%） 112.5 （7.4%） 0.0 （0.0%） 112.5 （3.5%） -22.5Diesel 0.0 （0.0%） 0.0 （0.0%） 0.0 （0.0%） 0.0 （0.0%） 0.0Geothermal 255.0 （7.3%） 255.0 （16.7%） 0.0 （0.0%） 255.0 （7.9%） 0.0Special Supply 58.0 （1.7%）－－－－－－ 58.0

Total 3,512.0 （100.0%） 1,530.5 （100.0%） 1,696.0 （100.0%） 3,226.5 （100.0%） 285.5

High Demand Case (Unit : million US$)

Hydropower 1,719.0 （35.1%） 993.0 （40.0%） 726.0 （28.9%） 1,719.0 （34.4%） 0.0Steam Turbine 2,300.0 （47.0%） 1,100.0 （44.3%） 1,200.0 （47.8%） 2,300.0 （46.1%） 0.0Combined Cycle 450.0 （9.2%） 0.0 （0.0%） 540.0 （21.5%） 540.0 （10.8%） -90.0Gas Turbine 112.5 （2.3%） 135.0 （5.4%） 45.0 （1.8%） 180.0 （3.6%） -67.5Diesel 0.0 （0.0%） 0.0 （0.0%） 0.0 （0.0%） 0.0 （0.0%） 0.0Geothermal 255.0 （5.2%） 255.0 （10.3%） 0.0 （0.0%） 255.0 （5.1%） 0.0Special Supply 58.0 （1.2%）－－－－－－ 58.0

Total 4,894.5 （100.0%） 2,483.0 （100.0%） 2,511.0 （100.0%） 4,994.0 （100.0%） -99.5

Balance(a) - (d)


(a)

Balance(a) - (d)

(b) (c) (d)

Separate SystemNorth South-West

(b)Plant Type

Plant TypeSeparate System

North South-West Total

(c) (d)Total


(a)

Low Demand Case (Unit : million US$, NPV in 2003)

(1) Construction Cost 1,197.0 （22.8%） 610.0 （21.2%） 557.0 （22.4%） 1,167.0 （21.8%） 30.0 (2) Salvage Value 224.0 （4.3%） 79.0 （2.7%） 106.0 （4.3%） 185.0 （3.5%） 39.0 (3) Operation Cost 4,242.0 （80.8%） 2,311.0 （80.4%） 2,028.0 （81.6%） 4,339.0 （81.0%） -97.0 (4) ENS Cost 33.0 （0.6%） 32.0 （1.1%） 5.0 （0.2%） 37.0 （0.7%） -4.0

System Cost(1) - (2) + (3) + (4) 5,248.0 （100.0%） 2,874.0 （100.0%） 2,484.0 （100.0%） 5,358.0 （100.0%） -110.0

High Demand Case (Unit : million US$, NPV in 2003)

(1) Construction Cost 1,804.0 （28.9%） 977.0 （29.2%） 911.0 （29.7%） 1,888.0 （29.4%） -84.0 (2) Salvage Value 285.0 （4.6%） 143.0 （4.3%） 140.0 （4.6%） 283.0 （4.4%） 2.0 (3) Operation Cost 4,679.0 （75.0%） 2,474.0 （74.0%） 2,289.0 （74.6%） 4,763.0 （74.3%） -84.0 (4) ENS Cost 39.0 （0.6%） 37.0 （1.1%） 7.0 （0.2%） 44.0 （0.7%） -5.0

System Cost(1) - (2) + (3) + (4) 6,237.0 （100.0%） 3,345.0 （100.0%） 3,067.0 （100.0%） 6,412.0 （100.0%） -175.0

Balance(a) - (d)


(a)

Balance(a) - (d)

(b) (c) (d)

Separate SystemNorth South-West

(b)Plant Type

Plant TypeSeparate System

North South-West Total

(c) (d)Total


(a)

4-9

Consequently, generation development in the Whole system by construction of the transmission line for interconnection is economically superior to the development of separate systems from the aspect of future expansion and operation of the system. 4.4.3 Examination on Interconnection Year

As described above, it has been shown that the generation development of a system interconnecting

all of Sumatra is economically superior to the generation development in each separate system. In addition, the Study team examined the impact of the year in which the interconnection is made

on the economic efficiency of generation development in the interconnected system. Figure 5.7.1 shows the correlation between the year of the interconnection and the resulting benefits.

Figure 4.4.1 Correlation between Interconnection Year and Benefit of Interconnection

Figure 4.4.1 shows that the earlier interconnection offers greater benefit because the earlier

interconnection has a longer period for providing the benefits of interconnection. As described in section 4.4.1, the generation development in the interconnected system has advantages not only in economic terms, but also in supply reliability. Therefore, it is hoped that the transmission line between the North and the South-West system will be developed at the earliest possible date.

Consequently, the Study team conducted the subsequent simulations on the assumption that the

interconnection transmission line will be in commission at the beginning of 2009.

Ben

efit

of In

terc

onne

ctio

n up

to 2

020

(Sys

tem

Cos

t

- Sys

tem

Cos

t

) Se

para

te

In

terc

onne

ctio

n

(thou

sand

US$

)

0

50,000

100,000

150,000

200,000

2008 2010 2012 2014 2016 2018 2020 2022Interconnection Year

4-10

4.5 Case Studies and Sensitivity Analysis

A generation development plan is usually heavily influenced by various changes to conditions surrounding the power sector. Therefore, the Study team conducted case studies and sensitivity studies on these uncertain parameters for the simulation based on the least-cost development plan for the Whole system that was shown in section 4.3.

4.5.1 Cases and Preconditions for the Study

The cases conducted for the case study and the sensitivity analysis are shown in Table 4.5.1.

Table 4.5.1 Cases and Preconditions for Case Study and Sensitivity Analysis (Case Study)

Case Precondition CO2 Emission Prevention Case CO2 Emission Intensity after 2015 is 0.500kg-CO2 and below

Limited Natural Gas Supply Case Natural gas supply to the South-West system until 2020 is 100,000MMBTU per day and below

Environmental Social Consideration weighted Case (ESC weighted Case)

Cost parameters are multiplied by environmental and social consideration factors shown in Table 4.5.2.

(Sensitivity Analysis)

Item Case Precondition Gas Price Increase Case : G1 Gas Price : 4.0US$/MMBTU Gas Price Increase Case : G2 Gas Price : 4.5US$/MMBTU Coal Price Increase Case : C1 Coal Price : 40US$/ton

Fuel Price

Coal Price Increase Case : C2 Coal Price : 50US$/ton Supply Reliability (LOLP) LOLP 1, 3*, 5days/year Case Discount Rate Discount Rate 3, 6, 9, 12*, 15, 18% Case

Low ENS Cost Case ENS Cost : 0.2 US$/kWh Middle ENS Cost Case* ENS Cost : 0.5 US$/kWh Cost for Un-served Energy High ENS Cost Case ENS Cost : 0.8 US$/kWh

Supplementary Explanation Environmental and Social Considerations Weighted Case

In the Study the generation development plan should be formulated taking into consideration the

environmental and social impacts of the power plant development. Therefore, the Study team estimated an environmental load factor (refer to section 8.4.3 in Main Report (Volume 2) for details) in each plant type for the purpose of evaluating the impact. The Study team conducted a case study for environmental and social considerations by multiplying the cost parameter of each unit by the estimated environmental and social considerations factor (hereinafter referred to as ESC factor).

Table 4.5.2 ESC (Environmental and Social Considerations) Factor

Hydropower Plant Thermal Power Plant Reservoir ROR Mini ST (Coal) ST (Gas) ST (Oil) CC (Gas) GT (Gas) GT (Oil) Diesel（Oil）

5.9% 2.4% -2.6% 5.0% 4.1% 4.7% 4.1% 0.0% 0.5% 0.5%

4-11

4.5.2 Results of Case Study Tables 4.5.3, 4.5.4 and 4.5.5 show the output of the WASP-IV simulation for newly developed

capacity in the cases for the case study. The results of the sensitivity analysis are shown in Appendix III.

Table 4.5.3 Output of WASP-IV Simulation (CO2 Emission Prevention Case)

Table 4.5.4 Output of WASP-IV Simulation (Limited Natural Gas Supply Case)

(Unit : MW)


2003 2,111.8 2003 2,111.82004 2,274.4 2004 2,286.82005 2,423.2 2005 2,454.02006 2,587.4 2006 2,671.82007 2,761.8 2007 2,911.42008 2,938.2 2008 3,164.42009 3,143.0 2009 3,461.62010 3,337.0 2010 3,760.42011 3,523.6 2011 4,064.72012 3,724.0 2012 4,400.22013 3,925.7 2013 4,752.52014 4,144.1 2014 5,056.32015 4,371.7 2015 5,373.72016 4,609.3 2016 5,707.22017 4,857.3 2017 6,058.92018 5,116.3 2018 6,431.02019 5,387.1 2019 6,825.52020 5,670.3 2020 7,244.0


400*6

100

100 400*6

180*2

200*5 450*3*4

2,100

300450

150*1

300450

450

Developed

CC

150*1

5

750

300

300

600 Capacity (MW) Total 2,780 MW Capacity (MW) Total 4,580 MW

200


1,2301,230 Developed 1,000 250

14

Hydro

Number of Units


10 5



200

200

350*4

200

200

180*2

200*5

250

400100300

100*3

(Unit : MW)


2003 2,111.8 2003 2,111.82004 2,274.4 2004 2,286.82005 2,423.2 2005 2,454.02006 2,587.4 2006 2,671.82007 2,761.8 2007 2,911.42008 2,938.2 2008 3,164.42009 3,143.0 2009 3,461.62010 3,337.0 2010 3,760.42011 3,523.6 2011 4,064.72012 3,724.0 2012 4,400.22013 3,925.7 2013 4,752.52014 4,144.1 2014 5,056.32015 4,371.7 2015 5,373.72016 4,609.3 2016 5,707.22017 4,857.3 2017 6,058.92018 5,116.3 2018 6,431.02019 5,387.1 2019 6,825.52020 5,670.3 2020 7,244.0


300400500

400*6

100

400

100*3

300

180*2

200*5 450*3*4

400*6

150

150*1

Developed

CC

150*1

1

1501,400 Capacity (MW) Total 2,980 MW Capacity (MW) Total 4,530 MW

200


1,2301,230 Developed 2,900 250

1300

Hydro

Number of Units


29 5



100

200

350*4

200

200300300

180*2

200*5

250

400100300

100

4-12

Table 4.5.5 Output of WASP-IV Simulation (ESC Weighted Case)

4.6 Proposed Generation Development Plan in the Study

The Study team conducted a series of studies based on economic efficiency and formulated the development plans that minimized the cost for expansion and operation of the system from the viewpoint of economic operation in the future. However, the development plan should be formulated in consideration of not only its economic efficiency, but also its impact on the environment and society.

A generation development has not only positive impact, such as the stimulation of economic activity and the improvement of infrastructure around the developed areas, but it also has negative impacts such as changes in the environment and society. The negative impacts include not only local issues, but also global issues such as greenhouse warming and acid rain caused by the increasing CO2 and SOX emissions. Therefore, the consideration of the impacts of generation development on the environment and society is necessary.

The Study team conducted a case study involving the ESC weighted Case in recognition of the importance and necessity of environmental and social considerations for the development and operation of the power system, which considers the negative impact of generation development on the environment and society. The system cost in this case is almost same as in the Least-cost Case.

Consequently, the Study team proposed a development plan in the ESC Weighted Case (hereinafter referred to as the Proposed Case) because this case considers not only economic efficiency, but also environmental and social considerations. Tables 4.6.1 to 4.6.3 show some results of the Proposed Case and Tables 4.6.4 and 4.6.5 show the detailed generation development plans. Other results of the simulation in the Proposed Case are shown in Appendix III.

(Unit : MW)


2003 2,111.8 2003 2,111.82004 2,274.4 2004 2,286.82005 2,423.2 2005 2,454.02006 2,587.4 2006 2,671.82007 2,761.8 2007 2,911.42008 2,938.2 2008 3,164.42009 3,143.0 2009 3,461.62010 3,337.0 2010 3,760.42011 3,523.6 2011 4,064.72012 3,724.0 2012 4,400.22013 3,925.7 2013 4,752.52014 4,144.1 2014 5,056.32015 4,371.7 2015 5,373.72016 4,609.3 2016 5,707.22017 4,857.3 2017 6,058.92018 5,116.3 2018 6,431.02019 5,387.1 2019 6,825.52020 5,670.3 2020 7,244.0

*1 : Substitution unit of coal-fired thermal power plant taking into consideration the lack of supply capacity in Pekanbaru in the near future.*2 : Asahan I*3 : Run-of-River Type 100MW*4 : Merangin*5 : Reservoir Type 100MW*6 : Reservoir Type 400MW*7 : Reservoir Type 100MW x 2 units

250

400100300

300

300

200

350*4

200

200200300

180*2

100*5


Year ST GT Hydro Year ST GT CC Hydro

Number of Units


23 5

200


1,2301,230 Developed 2,300 250

5

Capacity (MW) Total 2,880 MW Capacity (MW) Total 4,530 MW Developed

CC

150*1

1

1501,300 750

150

150*1

150

300

180*2

200*7 450*3*4

400*6

100

200

100

400

100*3

400*6

100*5

300200

4-13

Table 4.6.1 Transition of Installed Capacity (Proposed Case)

Table 4.6.2 Necessary Investment Cost (Proposed Case)

Table 4.6.3 System Cost (Proposed Case)

Low Demand Case (Unit : MW, %)

Hydropower 562.0 （18.1%） 854.0 （21.1%） 1,738.0 （33.3%） 2,238.0 （33.3%）Steam Turbine 745.6 （24.0%） 915.6 （22.7%） 1,215.6 （23.3%） 2,215.6 （33.0%）Combined Cycle 817.9 （26.3%） 1,199.9 （29.7%） 1,199.9 （23.0%） 1,199.9 （17.8%）Gas Turbine 625.7 （20.1%） 685.8 （17.0%） 685.8 （13.1%） 685.8 （10.2%）Diesel 290.9 （9.4%） 0.0 （0.0%） 0.0 （0.0%） 0.0 （0.0%）Geothermal 0.0 （0.0%） 275.0 （6.8%） 275.0 （5.3%） 275.0 （4.1%）Special Supply 64.0 （2.1%） 110.0 （2.7%） 110.0 （2.1%） 110.0 （1.6%）

Total 3,106.0 （100.0%） 4,040.2 （100.0%） 5,224.2 （100.0%） 6,724.2 （100.0%）

High Demand Case (Unit : MW, %)

Hydropower 562.0 （18.1%） 854.0 （18.6%） 1,838.0 （29.3%） 2,238.0 （26.7%）Steam Turbine 745.6 （24.0%） 1,415.6 （30.8%） 2,115.6 （33.7%） 3,215.6 （38.4%）Combined Cycle 817.9 （26.3%） 1,199.9 （26.1%） 1,199.9 （19.1%） 1,799.9 （21.5%）Gas Turbine 625.7 （20.1%） 735.8 （16.0%） 735.8 （11.7%） 735.8 （8.8%）Diesel 290.9 （9.4%） 0.0 （0.0%） 0.0 （0.0%） 0.0 （0.0%）Geothermal 0.0 （0.0%） 275.0 （6.0%） 275.0 （4.4%） 275.0 （3.3%）Special Supply 64.0 （2.1%） 110.0 （2.4%） 110.0 （1.8%） 110.0 （1.3%）

Total 3,106.0 （100.0%） 4,590.2 （100.0%） 6,274.2 （100.0%） 8,374.2 （100.0%）

Year2004 2010 2015 2020

Year2004 2010 2015 2020


2006-2010 2011-2015 2016-2020Hydropower 0.0 1,009.0 710.0 1,719.0Coal-fired ST 0.0 300.0 1,000.0 1,300.0Combined Cycle 90.0 0.0 0.0 90.0Gas Turbine 90.0 0.0 0.0 90.0Geothermal 255.0 0.0 0.0 255.0

Total 435.0 1,309.0 1,710.0 3,454.0



Total 957.5 1,859.0 2,020.0 4,836.5

Total

Total

Year

Year


Low High(1) Construction Cost 1,193 1,804(2) Salvage Value 224 285(3) Operation Cost 4,246 4,679(4) ENS Cost 33 39System Cost(1) - (2) + (3) + (4) 5,248 6,237

Item Demand Case

Table 4.6.4 Generation Development Plan for the Whole Sumatra System (Proposed Case, Low Demand Case)

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Whole Sumatra System Generation Development Plan

Proposed Case Low Demand CaseItem / Plant Name Type 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Total

Peak Demand (MW) 2,274.4 2,423.2 2,587.4 2,761.8 2,938.2 3,143.0 3,337.0 3,523.6 3,724.0 3,925.7 4,144.1 4,371.7 4,609.3 4,857.3 5,116.3 5,387.1 5,670.3 Annnual Energy (GWh) 13,224.9 14,090.1 15,044.9 16,058.9 17,084.7 18,275.5 19,403.5 20,488.6 21,653.8 22,826.6 24,096.6 25,420.0 26,801.5 28,243.6 29,749.6 31,324.2 32,970.9 Load Factor 　　 (%) 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4Existing Plant Combined Cycle PLTGU 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 Steam Turbine PLTU 745.6 745.6 745.6 745.6 745.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 Gas Turbine PLTG 430.7 442.4 442.4 442.4 442.4 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 Diesel PLTD 290.9 295.0 295.0 74.7 74.7 Geothermal PLTP Hydropower PLTA 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 Small-scale Hydropower PLTA 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 Special Supply 64.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 ( Sub Total ) 2,878.0 2,874.9 2,874.9 2,654.5 2,654.5 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2Fixed Project(North Sumatra System) Labuhan Angin PLTU 230.0 230.0 Sarulla PLTP 110.0 55.0 165.0 Sipansihaporas 1 PLTA 33.0 33.0 Renun PLTA 82.0 82.0 Asahan III PLTA 154.0 154.0 INALUM 65.0 65.0(South-West Sumatra System) Palembang Timur CC PLTGU 150.0 150.0 Keramasan CC PLTGU 82.0 82.0 Tarahan PLTU 200.0 200.0 Palembang Timur GT open Cycle PLTG 100.0 -100.0 0.0 Truck Mounted PLTG 40.0 40.0 Indralaya PLTG 40.0 40.0 Talang Dukuh 2 PLTG 15.0 15.0 Apung PLTG 33.0 33.0 Pulo Gadung PLTG 18.0 18.0 Ulu Belu PLTP 110.0 110.0 Musi PLTA 210.0 210.0 ( Sub Total ) 228.0 248.0 210.0 200.0 230.0 110.0 247.0 0.0 154.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1,627.0Candidate Unit Coal-fired ST 100MW PLTU 200.0 100.0 200.0 200.0 300.0 300.0 1,300.0 Gas Turbine (HSD) 50MW PLTG 200.0 200.0 Gas-fired Combined Cycle 150MW PLTGU 150.0 150.0 Asahan I PLTA 180.0 180.0 Run-of-River HPP 100MW PLTA 100.0 100.0 Merangin PLTA 350.0 350.0 Reaservoir HPP 100MW PLTA 100.0 100.0 200.0 Reservoir HPP 400MW PLTA 400.0 400.0 ( Sub Total ) 0.0 0.0 0.0 200.0 0.0 150.0 0.0 200.0 180.0 100.0 350.0 200.0 200.0 300.0 300.0 300.0 400.0 2,480.0Developed Plant Total (MW) 228.0 248.0 210.0 400.0 230.0 260.0 247.0 200.0 334.0 100.0 350.0 200.0 200.0 300.0 300.0 300.0 400.0 4,107.0Total Supply Capacity in the System (MW) 3,106.0 3,350.9 3,560.9 3,740.5 3,970.5 3,793.2 4,040.2 4,240.2 4,574.2 4,674.2 5,024.2 5,224.2 5,424.2 5,724.2 6,024.2 6,324.2 6,724.2Reserve (%) 37 38 38 35 35 21 21 20 23 19 21 20 18 18 18 17 19

Table 4.6.5 Generation Development Plan for the Whole Sumatra System (Proposed Case, High Demand Case)

Whole Sumatra System Generation Development Plan

Proposed Case High Demand CaseItem / Plant Name Type 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Total

Peak Demand (MW) 2,286.8 2,454.0 2,671.8 2,911.4 3,164.4 3,461.6 3,760.4 4,064.7 4,400.2 4,752.5 5,056.3 5,373.7 5,707.2 6,058.9 6,431.0 6,825.5 7,244.0 Annnual Energy (GWh) 13,297.0 14,269.2 15,535.6 16,928.8 18,399.9 20,128.1 21,865.5 23,634.9 25,585.7 27,634.2 29,400.7 31,246.3 33,185.5 35,230.5 37,394.1 39,688.0 42,121.4 Load Factor 　　 (%) 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4 66.4Existing Plant Combined Cycle PLTGU 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 Steam Turbine PLTU 745.6 745.6 745.6 745.6 745.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 Gas Turbine PLTG 430.7 442.4 442.4 442.4 442.4 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 Diesel PLTD 290.9 295.0 295.0 74.7 74.7 Geothermal PLTP Hydropower PLTA 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 Small-scale Hydropower PLTA 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 Special Supply 64.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 ( Sub Total ) 2,878.0 2,874.9 2,874.9 2,654.5 2,654.5 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2Fixed Project(North Sumatra System) Labuhan Angin PLTU 230.0 230.0 Sarulla PLTP 110.0 55.0 165.0 Sipansihaporas 1 PLTA 33.0 33.0 Renun PLTA 82.0 82.0 Asahan III PLTA 154.0 154.0 INALUM 65.0 65.0(South-West Sumatra System) Palembang Timur CC PLTGU 150.0 150.0 Keramasan CC PLTGU 82.0 82.0 Tarahan PLTU 200.0 200.0 Palembang Timur GT open Cycle PLTG 100.0 -100.0 0.0 Truck Mounted PLTG 40.0 40.0 Indralaya PLTG 40.0 40.0 Talang Dukuh 2 PLTG 15.0 15.0 Apung PLTG 33.0 33.0 Pulo Gadung PLTG 18.0 18.0 Ulu Belu PLTP 110.0 110.0 Musi PLTA 210.0 210.0 ( Sub Total ) 228.0 248.0 210.0 200.0 230.0 110.0 247.0 0.0 154.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1,627.0Candidate Unit Coal-fired ST 100MW PLTU 400.0 100.0 300.0 100.0 300.0 400.0 200.0 300.0 200.0 2,300.0 Gas Turbine (HSD) 50MW PLTG 250.0 250.0 Gas-fired Combined Cycle 150MW PLTGU 150.0 150.0 150.0 300.0 750.0 Asahan I PLTA 180.0 180.0 Run-of-River HPP 100MW PLTA 100.0 100.0 Merangin PLTA 350.0 350.0 Reaservoir HPP 100MW PLTA 200.0 200.0 Reservoir HPP 400MW PLTA 400.0 400.0 ( Sub Total ) 0.0 0.0 0.0 250.0 150.0 400.0 100.0 300.0 180.0 450.0 300.0 300.0 400.0 350.0 400.0 450.0 500.0 4,130.0Developed Plant Total (MW) 228.0 248.0 210.0 450.0 380.0 510.0 347.0 300.0 334.0 450.0 300.0 300.0 400.0 350.0 400.0 450.0 500.0 5,757.0Total Supply Capacity in the System (MW) 3,106.0 3,350.9 3,560.9 3,790.5 4,170.5 4,243.2 4,590.2 4,890.2 5,224.2 5,674.2 5,974.2 6,274.2 6,674.2 7,024.2 7,424.2 7,874.2 8,374.2Reserve (%) 36 37 33 30 32 23 22 20 19 19 18 17 17 16 15 15 16

4-15

4-16

4.7 Preparation of Detailed Generation Development Plan for Transmission Planning

The Study team prepared the detailed generation development plan for transmission planning discussed in Chapter 5 because transmission planning requires the location of future developed power plants. The detailed plan was prepared based on the Proposed Case (High Demand Case).

4.7.1 Candidate Sites for Development

The Study team prepared a list of candidate sites for development through discussions with counterparts based on existing power development plans by PLN, potential sites of primary energy and reports on already conducted studies. Table 4.7.1 shows the list of candidate sites that were selected in the Study.

Table 4.7.1 List of Candidate Sites for Development12

Candidate Site

Plant Type System Location Remarks

North Meulaboh up to 600MW North Sibolga up to 200MW North Medan*1

South-West Cirenti up to 600MW South-West Musi RawasSouth-West MubaSouth-West PrabumulihSouth-West Banjar Sari

Coal-fired Steam Turbine

South-West Tarahan up to 200MW South-West PekanbaruSouth-West Talang Dukuh

Gas-fired Combined Cycle

South-West PalembangGas Turbine site is selected in consideration of demand-supply balance

North Peusangan 86.4MW North Asahan I 180.0MW North Tampur 428.0MW North Jambu Aye 160.0MW South-West Merangin 350.0MW South-West Ketaun 84.0MW

Hydropower13

South-West Ranau 60.0MW

4.7.2 Identification of Developed Site and Development Year

A power plant should be developed close to the consumption points from the viewpoint of reducing the

cost for transmission development and the transmission losses. Therefore, based on the development plan

shown in Table 4.6.5, the Study team allocated the development capacity required to the regions in

consideration of the demand-supply balance in each region.

Table 4.7.2 shows the generation development plan for transmission planning discussed in Chapter 5.

The demand-supply balance by system is shown in Appendix III.

12 These sites were selected without evaluation and comparison of individual projects. 13 Candidate sites for hydropower were selected from the projects with engineering designs (E/D) or feasibility studies (F/S). The Study team

excluded the Wampu hydropower project from the list of candidates because some of its facilities might extend into a national park.

Table 4.7.2 Generation Development Plan for Transmission Planning (Proposed Case, High Demand Case)

4-17

Whole Sumatra System Generation Development PlanProposed Case High Demand Case

Item / Plant Name Type 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Total Peak Demand (MW) 2,286.8 2,454.0 2,671.8 2,911.4 3,164.4 3,461.6 3,760.4 4,064.7 4,400.2 4,752.5 5,056.3 5,373.7 5,707.2 6,058.9 6,431.0 6,825.5 7,244.0 Annnual Energy (GWh) 13,297.0 14,269.2 15,535.6 16,928.8 18,399.9 20,128.1 21,865.5 23,634.9 25,585.7 27,634.2 29,400.7 31,246.3 33,185.5 35,230.5 37,394.1 39,688.0 42,121.4 Load Factor 　　 (%) 66 66 66 66 66 66 66 66 66 66 66 66 66 66 66 66 66Existing Plant Combined Cycle PLTGU 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 817.9 Steam Turbine PLTU 745.6 745.6 745.6 745.6 745.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 485.6 Gas Turbine PLTG 430.7 442.4 442.4 442.4 442.4 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 339.8 Diesel PLTD 290.9 295.0 295.0 74.7 74.7 Geothermal PLTP Hydropower PLTA 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 521.5 Small-scale Hydropower PLTMH 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 Special Supply 64.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 ( Sub Total ) 2,878.0 2,874.9 2,874.9 2,654.5 2,654.5 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2 2,217.2Fixed Project( North Sumatra System ) Labuhan Angin PLTU 230.0 230.0 Sarulla PLTP 110.0 55.0 165.0 Sipansihaporas 1 PLTA 33.0 33.0 Renun PLTA 82.0 82.0 Asahan III PLTA 154.0 154.0 INALUM (additional capacity) 65.0 65.0( South-West Sumatra System ) Palembang Timur CC PLTGU 150.0 150.0 Keramasan CC PLTGU 82.0 82.0 Tarahan PLTU 200.0 200.0 Palembang Timur GT open Cycle PLTG 100.0 -100.0 0.0 Truck Mounted PLTG 40.0 40.0 Indralaya PLTG 40.0 40.0 Talang Dukuh 2 PLTG 15.0 15.0 Apung PLTG 33.0 33.0 Pulo Gadung PLTG 18.0 18.0 Ulu Belu PLTP 110.0 110.0 Musi PLTA 210.0 210.0 ( Sub Total ) 228.0 248.0 210.0 200.0 230.0 110.0 247.0 0.0 154.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1,627.0Candidate Unit( North Sumatra System ) PLTU Sibolga PLTU 200.0 200.0 PLTU Meulaboh PLTU 200.0 100.0 100.0 200.0 600.0 PLTU Medan PLTU 200.0 100.0 300.0 PLTG Arun PLTG 60.0 60.0 PLTG Aceh PLTG 150.0 150.0 PLTG Medan PLTG 50.0 50.0 PLTA Asahan I PLTA 180.0 180.0 PLTA Peusangan PLTA 86.4 86.4 PLTA Tampur PLTA 428.0 428.0( South-West Sumatra System ) PLTGU Pekanbaru PLTGU 150.0 150.0 150.0 450.0 PLTGU Jambi PLTGU 150.0 150.0 PLTGU Palembang PLTGU 150.0 150.0 PLTU Tarahan PLTU 100.0 100.0 200.0 PLTU Musi Rawas PLTU 100.0 100.0 200.0 PLTU Muba PLTU 200.0 200.0 PLTU Prabumulih PLTU 100.0 100.0 200.0 PLTU Cirenti PLTU 100.0 100.0 100.0 300.0 PLTU Banjar Sari PLTU 100.0 100.0 PLTG Jambi PLTG 50.0 50.0 PLTA Merangin PLTA 350.0 350.0 PLTA Ketaun PLTA 84.0 84.0 PLTA Ranau PLTA 60.0 60.0 ( Sub Total ) 0.0 0.0 0.0 260.0 150.0 400.0 100.0 300.0 180.0 436.4 244.0 300.0 400.0 400.0 428.0 450.0 500.0 4,548.4Developed Plant Total (MW) 228.0 248.0 210.0 460.0 380.0 510.0 347.0 300.0 334.0 436.4 244.0 300.0 400.0 400.0 428.0 450.0 500.0 6,175.4Total Supply Capacity in the System (MW) 3,106.0 3,350.9 3,560.9 3,800.5 4,180.5 4,253.2 4,600.2 4,900.2 5,234.2 5,670.6 5,914.6 6,214.6 6,614.6 7,014.6 7,442.6 7,892.6 8,392.6Reserve (%) 36 37 33 31 32 23 22 21 19 19 17 16 16 16 16 16 16*1 : Additionaly required unit as the result of identification

*1

4-18

4.8 Issues and Recommendations 4.8.1 Interconnection between the North System and the South-West System

The interconnection by the construction of an interconnection transmission line between the North Sumatra system and the South-West Sumatra system will play an important role in achieving the generation development in Sumatra more efficiently and economically. Also, the interconnection year should be as early as possible. Therefore, it is essential to conduct technical investigations and to find and procure the funds needed for the development of the interconnection transmission line in the years ahead.

4.8.2 Promotion of Hydropower Development

As shown in the generation development plans above, the development of hydropower plants has an important part to play in the generation development of the power system in Sumatra in the future. Especially during the period between 2012 and 2018, the development of several hydropower projects will be required for economical expansion and operation of the system. The plans also indicate that if those hydropower projects are not implemented, thermal power plants will be developed instead of those hydropower projects and this will take away from the economic development of power system.

Consequently, to achieve the economic generation development, it is desirable to promote the

implementation of hydropower projects steadily for which feasibility studies have already been conducted and to upgrade the study phase of the projects for which pre-feasibility studies or reconnaissance studies have already been conducted.

4.8.3 Promotion of Coal-fired Power Development until 2011

The share held by coal-fired power plants in the overall capacity in Sumatra will increase in the future. Therefore, its development plays a key role in the generation development in Sumatra. Especially during the period between 2008 and 2011, the development plan in the Proposed Case (High Demand Case) requires the development of coal-fired power plants with a total of 800MW in installed capacity. To achieve generation development in accordance with the plan, it is desirable not only to promote the development of the new coal thermal projects planned in the North system and South-West system, but also to consider the add-on projects at on-going project sites such as Labuhan Angin and Tarahan.

4-19

4.8.4 Development Site for Gas-fired Combined Cycle Power Plants and Procurement of Future Gas Supply

The future development sites for power plants should be selected in consideration of the

demand-supply balance in regional systems because the length of the interconnection transmission lines between the systems are several hundred kilometers even if each system is interconnected, and geographically unbalanced development might leads to unnecessary expansion of transmission facilities such as upgrading the designed voltage of transmission lines earlier than expected.

The gas-fired combined cycle power plant in the South-West system can be placed at locations

relatively close to a demand center compared to hydropower and coal-fired thermal power plant. Therefore, the development sites for gas-fired combined cycle power plant should be selected in consideration of the demand-supply balance in regional systems. The Study team examined the demand-supply conditions in each regional systems and the result shows that a severe shortage of supply capacity will occur in Riau province in 2008 and in Jambi and Lampung provinces in 2015. Therefore, it is hoped that gas-fired combined cycle power plants will be placed in these province in the future.

The procurement of future gas supply is also important in Sumatra. In the North system, the system

needs a gas supply of about 90,000 MMBTU/day for the economical operation of the Belawan combined cycle power plant and it will have to procure the gas supply of 60,000MMBTU/day in 2020 though the fuel requirement will decrease due to decline of the plant factor. On the other hand, in the South-West system the system has to procure new gas supply for the installation of new gas-fired combined cycle power plants. In addition to these efforts, the introduction of add-on steam turbines should be considered for existing gas-fired gas turbine power plants for more effective use of procured gas fuel.

4.8.5 Development of Gas Turbine Power Plants in Aceh Province After installation of the Renun hydropower plant and Labuhan Angin coal-fired thermal power

plant to the North system in 2005 and in 2007, respectively, the condition of power supply in the North system will be improved. However, the condition of power supply will become extremely severe in the Aceh regional system as it is very far from these new power plants. Moreover, all of the power plants including rental power plants in the Aceh regional system are diesel power plant as of the end of 2004 and the system is bound to generate electricity with high generation cost. To improve the situation in the Aceh system, there is an urgent need to develop oil-fired gas turbine power units for the system.

5-1

Chapter 5 Transmission Planning and System Analysis

In this chapter transmission plans are developed based on the demand forecast (High Case) in Chapter 2 and the power development plan (Proposed Case) in Chapter 4. Meanwhile, coal resources abound in South Sumatra and it is expected that power development will be mainly implemented in South Sumatra. Therefore, the South Case, where power development is advanced in South Sumatra, is also studied. 5.1 Conditions 5.1.1 Study Cases

Table 5.1.1 shows the Study cases for transmission planning.

Table 5.1.1 Study Cases for Transmission Planning Interconnection

Demand Forecast Power Development PlanMalaysia IC Java IC

1 High Case Proposed Case No No 2 High Case South Case No No

Table 5.1.2 shows the differences between the Proposed Case and South Case with regard to the

candidates for power development.

Table 5.1.2 Differences between Power Development Candidates Difference from Proposed Case

North Sumatra PLTP Sarulla (▲165MW) 2010

South Sumatra PLTU Muba (+200MW)

North Sumatra PLTU Meulaboh (▲400MW) PLTU Medan (▲300MW) PLTA Tampur (▲428MW) 2020

South Sumatra PLTU Banjar Sari (+1,100MW)

The 150kV (designed for 275kV) interconnection between the North Sumatra system and the West Sumatra system is considered in both cases, on the assumption that it will be completed in 2009.

5-2

Table 5.1.3 shows the demand forecast and the generation capacity in North Sumatra, West Sumatra and South Sumatra in 2010 and 2020.

Table 5.1.3 Demand Forecast and Installed Capacity by System Installed Capacity Demand Forecast Proposed Case South Case

2010

South29%

North45%

West26%

South38%

West20%

North42%

South43%

West20%

North37%

2020

South28%

North44%

West28%

South32%

North44%

West24%

South45%

North31%

West24%

Note: North (NAD, Sumatera Utara) West (Riau, Sumatera Barat, Jambi) South (Sumatera Selatan, Bengkulu, Lampung)

5.1.2 Criteria and Methodology (1) Criteria

The N-1 rule is applied for the transmission planning. This indicates that no blackout and no generation restrictions will occur with an N-1 contingency. (2) Methodology

Power flow analysis, stability analysis and short circuit analysis are conduced for transmission planning. In regard to stability, it is required that the system should be kept stable with a three-phase to ground fault and clearing by a main protective relay (3LGO). 5.1.3 Program and Data for System Analysis

PSS/E14, which is developed by PTI, is adopted for the system analysis. The data for system analysis are from PLN and standard data are adopted for the future system.

14 Power System Simulator for Engineering

1,893MW 1,771MW

936MW

1,728MW 1,971MW

936MW

2,563MW 3,765MW

2,036MW

3,691MW2,665MW

2,036MW

1,704MW 1,081MW

975MW

3,181MW 2,043MW

2,021MW

5-3

5.2 Transmission Plan 5.2.1 Proposed Case (1) 2010

Figure 5.2.1 shows the Sumatra system for 2010 in the Proposed Case. In this case it is assumed that the demand and the supply in each system (North Sumatra system, West Sumatra system and South Sumatra system) are balanced. Therefore, power dispatching is possible with the 150kV system. (2) 2020

Figure 5.2.2 shows the Sumatra system for 2020 in the Proposed Case. In this case power dispatching is possible with one 275kV transmission line route from Aceh to Lampung (except the section from Meulaboh to Binjai, where two routes are necessary). To complete this 275kV backbone, 150kV transmission lines designed for 275kV (Galang - Sarulla, P.Sidempuan - Payakumbuh, Kiliranjao - Lahat) will be upgraded to 275kV and new 275kV transmission lines will be constructed. 5.2.2 South Case (1) 2010

Figure 5.2.3 shows the Sumatra system for 2010 in South Case. In this case, the power flow of the 150kV transmission line between South Sumatra and West Sumatra will be heavy and the system will be unstable with a transmission line fault. Therefore, it will be necessary to upgrade the 150kV transmission lines designed for 275kV between West Sumatra and South Sumatra (Kiliranjao - Lahat) to 275kV and to construct a new 275kV transmission line between Kiliranjao and Payakumbuh. In addition, the power flow of the 150kV transmission line will be heavy between Payakumbuh in West Sumatra and P.Sidempuan in North Sumatra. As the system will be unstable with transmission line faults, it is also necessary to upgrade the transmission line to 275kV. (2) 2020

Figure 5.2.4 shows the Sumatra system for 2020 in the South Case. In this case it is necessary to construct 500kV transmission lines from Banjar Sari in South Sumatra to Galang in North Sumatra to accommodate large-scale power transfers.

Figure 5.2.1 Proposed Case (2010)

PLTA K.Panjan

P.Sidempuan PLTP Sarulla

Sibolga

PLTU Sibolga

Porsea

Tele

Galang

PLTGU PLTU Belawan

Binjai

P.Brandan

S.Rotan T.Tinggi

~

G.Para

T.Kuning

Sidikalang

~ PLTA Renun

~PLTA Sipansihaporas

K.Tanjung

R.Prapat

Labuhan Angin PLTU

S.Empat

Payakumbuh

G.Sakti

PLTU Ombilin

Kiliranjao

M.Bungo Bangko

L.Linggau

Lahat

Baturaja

Borang

Mariana

T.Kelapa

Palembang Timur PLTGU

Keramasan PLTG PLTU PLTGU

~

S.Tiga

Prabumulih

~

T.Lembu

Rengat

T.Kuantan

Bangkinang

Duri

DumaiTembilahan

~A.Duri

P.Selincah

~Kaji PLTG

PLTP U.Belu

PLTA B.Tegi

PLTU Tarahan

PLTA Besai

Kalianda

Sribawono

S.Surabaya

Kotabumi

B.Kemuning

Tegineneng

Sutami

Natar Pagelaran

Menggala

Gumawang

~

~~

Adijaya

~

P.Alam

Salok

Solok

Indarung Bungus

P.Luar Batusangkar

L.Alung

PLTA Maninjau

~ PLTA Singkarak

~Betung

~

~

Metro

T.Betung

~

Tarahan

~

~

B.Batu

Manna

B.AsamPLTU

~

Curup

~PLTA Musi

G.Tua

K.Pinang

~ INALUM A.Kanopan

Kisaran

Brastagi

P.Siantar

~ Perbaungan

Denai

T.Morawa

Namorambe

GISKimGlugur

Mabar P.Pasir

Lamhotma Labuhan

~

P.Geli Simangkuk

~

P.Panjang

~

ACEH

SUMATERA UTARA

RIAU

SUMATRA BARAT

BENGKULU

JAMBI

SUMATERA SELATAN

LAMPUNG

M.RawasPLTU

~

~

B.Aceh

~

PLTG Arun Sigli Bireun

Lhoksewmawe Idie

Langsa

T.Cut

P.Limo

PIP ~ S.Haru

SUMATERA BARAT

Panyabungan

~Tarutung

~

~

~

~

Power Plant Substation 150kV Transmission Line 275kV Transmission Line 500kV Transmission Line HVDC Interconnection

~

Legend

5-4

Figure 5.2.2 Proposed Case (2020)

PLTA K.Panjan

P.Sidempuan

PLTA Asahan 1

PLTP Sarulla

Sibolga

Porsea

Tele

Galang

PLTGU PLTU Belawan

PLTU MeulabohBinjai

P.Brandan

S.Rotan T.Tinggi

~

G.Para

T.Kuning

Sidikalang

~ PLTA Renun


K.Tanjung

R.Prapat

~

~

S.Empat

Payakumbuh

G.Sakti

PLTU Ombilin

Kiliranjao

M.BungoBangko

L.Linggau

Lahat

Baturaja

Borang

Mariana

T.Kelapa



Muba PLTU

~

PLTA Merangin

S.Tiga

Prabumulih

~

T.Lembu

Rengat

T.Kuantan

Kulim

Bangkinang

Duri

DumaiTembilahan

~A.Duri

P.Selincah

~Kaji PLTG

PLTP U.Belu

PLTA B.Tegi

PLTU Tarahan

PLTA Besai

Kalianda

Sribawono

S.Surabaya

Kotabumi

B.Kemuning

Tegineneng

Sutami

Natar Pagelaran

Menggala

Gumawang

~

~~

Adijaya

~

P.Alam

~

Salok

Solok

Indarung Bungus

P.Luar

Kambang

Batusangkar

L.Alung

PLTA Maninjau

~ PLTA Singkarak

~Betung

~

~

Metro

T.Betung

~

Tarahan

~

~

~S.Lilin

B.Siapiapi

B.Batu

Manna

B.AsamPLTU

Bnjar Sari PLTU

~

Curup

~PLTA Musi

PLTA Kutaun ~

G.Tua

K.Pinang

~ INALUM

PLTA Asahan 3

A.Kanopan Kisaran

Brastagi

P.Siantar

~ Perbaungan

Denai

T.Morawa

Namorambe

GISKimGlugur

Mabar P.Pasir

Lamhotma Labuhan

~

P.Geli Simangkuk

~

P.Panjang

~

~

ACEH

SUMATERA UTARA

RIAU

SUMATRA BARAT

BENGKULU

JAMBI

SUMATERA SELATAN

LAMPUNG

~

PLTA Ranau

M.RawasPLTU

CirentiPLTU

~

~

~

~

B.Aceh

~

~

~PLTG Arun

Sigli Bireun Lhoksewmawe

Idie Langsa

T.Cut PLTA Peusangan

~

PLTA Tampur

Takengon

P.Limo

PIP ~ S.Haru

SUMATERA BARAT

Panyabungan

Tarutung

~

~

~

PLTU Sibolga Labuhan Angin

PLTU

~


~

Legend

5-5

Figure 5.2.3 South Case (2010)

PLTA K.Panjan

P.Sidempuan Sarulla

Sibolga

Porsea

Tele

Galang

PLTGU PLTU Belawan

P.Brandan

S.Rotan T.Tinggi

~

G.Para

T.Kuning

Sidikalang

~ PLTA Renun


K.Tanjung

R.Prapat

S.Empat

Payakumbuh

G.Sakti

PLTU Ombilin

Kiliranjao

M.BungoBangko

L.Linggau

Lahat

Baturaja

Borang

Mariana

T.Kelapa



~

S.Tiga

Prabumulih

~

T.Lembu

Rengat

T.Kuantan

Bangkinang

Duri

DumaiTembilahan

~A.Duri

P.Selincah

PLTP U.Belu

PLTA B.Tegi

PLTU Tarahan

PLTA Besai

Kalianda

Sribawono

S.Surabaya

Kotabumi

B.Kemuning

Tegineneng

Sutami

Natar Pagelaran

Menggala

Gumawang

~

~~

Adijaya

~

P.Alam

Salok

Solok

Indarung Bungus

P.Luar Batusangkar

L.Alung

PLTA Maninjau

~ PLTA Singkarak

~Betung

~

Metro

T.Betung

~

Tarahan

~

~

B.Batu

PLTU

~B.Asam

~

Curup

~PLTA Musi

G.Tua

K.Pinang

~ INALUM A.Kanopan

Kisaran

Brastagi

P.Siantar

~ Perbaungan

Denai

T.Morawa

Namorambe

GISKimGlugur

Mabar P.Pasir

Lamhotma Labuhan

~

P.Geli Simangkuk

~

P.Panjang

~

ACEH

SUMATERA UTARA

RIAU

SUMATRA BARAT

BENGKULU

JAMBI

SUMATERA SELATAN

LAMPUNG

M.RawasPLTU

~

~

~PLTG Arun


Idie Langsa

T.Cut

P.Limo

PIP ~ S.Haru

SUMATERA BARAT

Panyabungan

Tarutung

~

Binjai

B.Aceh

~

~

Muba PLTU

~Kaji PLTG

~


PLTU

~


~

Legend

5-6

Figure 5.2.4 South Case (2020)

PLTA K.Panjan

P.Sidempuan

PLTA Asahan 1

PLTP Sarulla

Sibolga

Porsea

Tele

Galang

PLTGU PLTU Belawan

Binjai

P.Brandan

S.Rotan T.Tinggi

~

G.Para

T.Kuning

Sidikalang

~ PLTA Renun


K.Tanjung

R.Prapat

~

~

S.Empat

Payakumbuh

G.Sakti

PLTU Ombilin

Kiliranjao

M.BungoBangko

L.Linggau

Lahat

Baturaja

Borang

Mariana

T.Kelapa



Muba PLTU

~

PLTA Merangin

S.Tiga

Prabumulih

~

T.Lembu

Rengat

T.Kuantan

Kulim

Bangkinang

Duri

DumaiTembilahan

~A.Duri

P.Selincah

~Kaji PLTG

PLTP U.Belu

PLTA B.Tegi

PLTU Tarahan

PLTA Besai

Kalianda

Sribawono

S.Surabaya

Kotabumi

B.Kemuning

Tegineneng

Sutami

Natar Pagelaran

Menggala

Gumawang

~

~~

Adijaya

~

P.Alam

~

Salok

Solok

Indarung Bungus

P.Luar

Kambang

Batusangkar

L.Alung

PLTA Maninjau

~ PLTA Singkarak

~Betung

~

Metro

T.Betung

~

Tarahan

~

~

~S.Lilin

B.Siapiapi

B.Batu

Manna

Bnjar Sari PLTU

~

G.Tua

K.Pinang

~ INALUM

PLTA Asahan 3

A.Kanopan Kisaran

Brastagi

P.Siantar

~ Perbaungan

Denai

T.Morawa

Namorambe

GISKimGlugur

Mabar P.Pasir

Lamhotma Labuhan

~

P.Geli

Simangkuk

~

P.Panjang

~

~

ACEH

SUMATERA UTARA

RIAU

SUMATRA BARAT

BENGKULU

JAMBI

SUMATERA SELATAN

LAMPUNG

~

PLTA Ranau

M.RawasPLTU

CirentiPLTU

~

~

~

~

B.Aceh

~

~PLTG Arun


Idie Langsa

T.Cut PLTA Peusangan

Takengon

Curup

~PLTA Musi

PLTA Kutaun ~

P.Limo

PIP ~ S.Haru

SUMATERA BARAT

Panyabungan

PLTU Meulaboh~

Tarutung

~

PLTU B.Asam

~

~

~


PLTU

~


~

Legend

5-7

5-8

5.3 Planned Facilities

Tables 5.3.1 and 5.3.2 show the lengths of transmission lines and the capacities of transformers expanded from 2006 to 2020 in the main Sumatra system.

Table 5.3.1 Length of Transmission Lines (Unit: km)

Proposed Case South Case 275kV 539 725 500kV 0 0 2006-2010

Subtotal 539 725 275kV 1,756 1,240 500kV 0 1,140 2011-2015

Subtotal 1,756 2,380 275kV 0 0 500kV 0 0 2016-2020

Subtotal 0 0 275kV 2,295 1,965 500kV 0 1,140 Total

Subtotal 2,295 3,105 Note: The Malaysia-Sumatra interconnection and the Java -

Sumatra interconnection are not included.

Table 5.3.2 Capacities of Transformers (Unit: MVA)

Proposed Case South Case 275/150kV 0 3,500 500/275kV 0 0 500/150kV 0 0

2006-2010

Subtotal 0 3,500 275/150kV 7,500 5,000 500/275kV 0 0 500/150kV 0 0

2011-2015

Subtotal 7,500 5,000 275/150kV 500 0 500/275kV 0 3,500 500/150kV 0 1,000

2016-2020

Subtotal 500 4,500 275/150kV 8,000 8,500 500/275kV 0 3,500 500/150kV 0 1,000

Total

Subtotal 8,000 13,000

5-9

5.4 Construction Cost

Table 5.4.1 shows the estimated construction cost for expansion of the 275kV and 500kV systems in Sumatra from 2006 to 2020.

Table 5.4.1 Estimated Construction Cost [Main System] （Unit: million US $）

Proposed Case South Case FC LC Total FC LC Total

Transmission Line 72 36 108 96 49 145 Substation 0 0 0 129 16 145 2006-2010 Subtotal 72 36 108 225 65 290

Transmission Line 233 118 351 545 273 818 Substation 279 35 314 240 31 271 2011-2015 Subtotal 512 153 665 785 304 1,089

Transmission Line 0 0 0 0 0 0 Substation 23 2 25 201 25 226 2016-2020 Subtotal 23 2 25 201 25 226

Transmission Line 305 154 459 641 322 963 Substation 302 37 339 570 72 642 Total Subtotal 607 191 798 1,211 394 1,605

Note: The costs for the Malaysia-Sumatra interconnection and the Java-Sumatra interconnection are not included.

5.5 Issues and Recommendations 5.5.1 Expansion of Main System in Sumatra

To maintain an appropriate level of reliability in Sumatra, the expansion of the transmission system in Sumatra should be implemented in accordance with the transmission plan that was developed in this study. The plan needs to be modified appropriately according to the changes in the demand forecast and the situation of each site in the power development plan.

From a viewpoint of transmission planning, it is desirable that new power plants should be located near demand centers and that the amount should be balanced with the demand. If the power plant is far from the demand center, long-distance power transmission will be necessary. In this case, large amounts of construction costs for transmission lines will be necessary and the transmission loss will also be large.

However, the potential of hydropower and geothermal power is high in Sumatra, of which locations are fixed. Additionally, coal resources abound in South Sumatra and natural gas abounds in Riau and South Sumatra. Therefore, the locations of new power plants tend to be fixed in Sumatra, and it is difficult to develop new power plants near demand centers and to balance the demand and the supply in each region.

5-10

In conclusion, it is desirable to implement power development to balance the demand and supply in each system (the North Sumatra system, the West Sumatra system and the South Sumatra system) in Sumatra for as long as possible. However, if regionally unbalanced power development is unavoidably advanced, it will be important to expand the transmission system at the proper times.

5.5.2 Measures to Improve Stability Stability problems can easily occur in the Sumatra system because the Sumatra Island is very large

and its length is almost 1,700km. If the system cannot maintain stability, the generators cannot continue stable operation due to transmission line faults and other disturbances. As a result, a black out of the entire system could occur in the worst case. To avoid this problem, the transmission system needs to be expanded properly in Sumatra. Meanwhile, it is also important to install appropriate protection and control equipment and to maintain them to provide system stability.

If the protection system does not work properly when there is a transmission line fault, the fault will continue and the system would collapse. To avoid this it is desirable to double the main protection systems for trunk lines. Step-out relays also need to be installed. They will separate unstable systems and maintain the system stability. In addition, the adoption of the following measures needs to be considered to improve stability: (1) shortening of fault clearing times by replacing protection relays and circuit breakers; (2) adoption of quick response excitation; (3) adoption of power system stabilizer (PSS); (4) installation of SVC (Static Var Compensator) and others.

Although distance relays are presently adopted in the Sumatra system, it is desirable to adopt PCM (Pulse Code Modulation) relays, which have higher reliability and for which operation times are shorter. To accommodate the adoption of PCM relays, it is necessary to develop networks using optical fibers through the adoption of OPGW (Optical Ground Wire) and by stringing optical fibers on transmission towers in line with their construction. 5.5.3 Timing of 275kV introduction

275kV needs to be introduced in the Sumatra system in the following cases:

(1) The case where the demand and the supply are not balanced in each system (North Sumatra system, West Sumatra system and South Sumatra system) because of delays in power development or regionally unbalanced power development

(2) The case where the Merangin hydropower plant (350MW) is developed (3) The case where the Meulaboh coal-fired power plant (200MW) is developed (4) The case where the Malaysia-Sumatra interconnection is constructed

5-11

If the power development is implemented to balance the demand and the supply in each system, it will be possible to dispatch power with the 150kV system until around 2010. However, the transmission limit between the South Sumatra system and the West Sumatra system will be restricted from around 100 to 200MW because of stability problems. Therefore, if the construction of Pekanbaru power plant (150MW), which is planed in Riau, is delayed, 275kV-upgrading of the South-West Sumatra interconnection will be necessary.

On the other hand, it is desirable to construct the North-West Sumatra interconnection early because better economy is expected by reducing the reserve margin and fuel costs by optimal operation of the generators, as presented in Chapter 4. If the interconnection is operated at 150kV, the transmission capacity will be limited to around 200MW because of stability. Therefore, if either Sibloga (200MW) or Sarulla (165MW) is delayed, which is planed in North Sumatra for around 2010, the North-West Sumatra interconnection will need to be operated at 275kV.

Meanwhile, it is necessary to introduce 275kV in the Sumatra system in the case of developing Merangin (350MW) in Jambi, Meulaboh (200MW) in Aceh, or the Malaysia-Sumatera interconnection (HVDC 600MW).

If it is judged that 275kV is necessary in the Sumatra system based on the situation of power development and demand increase, it will be necessary to start construction of new 275kV transmission lines and/or 275kV-upgrading of the existing 150kV transmission lines at the appropriate times, considering the schedule. 5.5.4 Transmission Plan in Aceh

In Aceh the situation is very complicated because of generation shortage caused by demand increase, overload of the existing 150kV transmission lines with a one-circuit fault, transient and steady-state stability problems and others. As a measure against supply shortage and overload of the transmission lines, it is necessary to install gas turbines in line with demand increases in Aceh. However, the stability is very poor in Aceh, so transient and steady-state stability problems will occur as a result of the installation of the generators.

A drastic measure against this problem is the construction of 275kV transmission lines from Medan to Banda Aceh and the separation of the generators at Banda Aceh from the 150kV system. However, early construction of the 275kV transmission lines from Medan to Banda Aceh, of which the length is around 500km, is not realistic from the viewpoints of construction period and cost. Under these circumstances, as short-term measures it is desirable to improve the protection and control system or to install an SVC (Static Var Compensator) to maintain the system stability for the gas turbines at Banda Aceh. As a middle to long-term measure, it is desirable to construct 275kV transmission lines from Medan to Banda Aceh in line with the power development in Aceh to drastically solve the stability problem.

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Concentration of generators should be avoided so as not to worsen the stability problem. Therefore, the gas turbines should be distributed to some substations with large demand such as Banda Aceh, Lhoksewmawe (Arun), and Langsa to mitigate the stability problem. If one 100MW generator is adopted in Banda Aceh, voltage stability problems will occur with the tripping of the generator. To avoid this it will be necessary to adopt two 50MW generators in Banda Aceh.

The diesel generators in Aceh are scheduled to be decommissioned because of aging. The schedule

needs to be coordinated with the power development plan and the transmission line, and appropriate timing should be selected.

In conclusion, the power development plan, the transmission plan and the protection and control plan should all be coordinated and appropriate measures should be taken for the Aceh system. 5.5.5 Construction of Second Trunk Lines in Sumatra

From a viewpoint of transmission planning, it is desirable that the amount of demand and supply should be balanced in each region as long as possible to make a power development plan.

In the Proposed Case power development is allocated to each system (North Sumatra system, West Sumatra system and South Sumatra system) to balance demand and supply regionally. In this case one 275kV backbone from Aceh to Tarahan accommodates power dispatch in Sumatra until around 2020. However, the power flow of the 275kV transmission line between Bangko and Muara Bungo will be very heavy in 2015, and it will be close to the one-circuit thermal capacity of the transmission line (620MW). This suggests that the system will hardly be able to accommodate additional power transfers.

Therefore, if one of the power development plans in North Sumatra or West Sumatra is delayed, the 275kV transmission line will be overloaded with a one-circuit fault and power transmission will be restricted. In addition, many of the candidates for power development are located in South Sumatra, so it is highly expected that the imbalance for demand and supply will become large in the long run.

Therefore, it is necessary to start expansion of the transmission system with the proper timing, if second trunk lines are necessary considering the progress of each power development plan and the demand increases. The lengths of the second trunk lines are around 600km from South Sumatra to West Sumatra and around 500km from West Sumatra to North Sumatra. Therefore, the construction period is expected to be long, and so it will be necessary to provide a long enough construction schedule.

If 275kV is adopted for the second trunk lines, the total transmission capacity of the two 275kV

routes would be less than around 1,000MW from the South Sumatra system to the West Sumatra system, because of stability and thermal capacity. This means that large-scale transmission will not be possible. Therefore, 500kV should be adopted for the second trunk lines.

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Chapter 6 Environmental and Social Considerations (ESC) - Initial Environmental Evaluation (IEE) -

6.1 ESC Scheme for the Study (Method of IEE15)

Indonesian legislation on EIA requires the completion of an AMDAL process before a project is implemented. On a master plan stage, however, what scheme is required for ESC is not specifically designated though ESC itself is encouraged even at this stage16. On the other hand, IEE (Initial Environmental Examination) is required for a master plan study according to the JICA ESC Guidelines.

This JICA study on the Optimal Electric Power Development in Sumatra is regarded as a preliminary planning study for formulating the master plans of Sumatra region in RUKN. Therefore, it is assumed to be proper that IEE is applied to this JICA study as an ESC process. The IEE in the Study can be used as a strategic environmental assessment (SEA) for an upstream stage of power development planning and will also be conducted as a preliminary assessment to EIA/AMDAL at the feasibility study stage.

6.1.1 IEE Flow

The flow of the IEE conducted in this Study is shown below.

(1) Discussion of TOR for IEE (ESC at MP) with the implementing organizations (MEMR, PT. PLN) and MOE

(2) Baseline study for IEE on environmentally / socially sensitive zones, and existing data on environmental costs regarding a project

(3) Scoping for IEE with implementing organizations and stakeholders (MOE, Dinas PE, BAPPEDA and BAPEDALDA)

(4) Discussion on IEE (ESC at MP) in three workshops with stakeholders (MEMR, PT.PLN H.Q. & Sumatra offices, and Dinas PEs)

(5) IEE of alternative scenarios with simulation by the WASP-IV model and inclusion of environmental costs

(6) Initial consideration on mitigation approaches (7) Optimal development plan with IEE study (8) Information disclosure on the results of IEE

15 IEE stands for Initial Environmental Examination and Initial Environmental Evaluation. The former applies to an IEE study during this MP

study, and the latter to IEE during the Master Plan Stage in the Indonesian policy formulation of RUKN (National Electricity General Plan). 16 A strategic environmental assessment (SEA) guideline for the MP stage is now under development in the MOE of Indonesia, but has yet to be

finalized. The IEE process does not exist in the Indonesian AMDAL scheme.

6-2

6.1.2 Stakeholders

Stakeholders at the MP stage17 are as shown below.

• Beneficially-Affected （Sumatra as a whole）: - People and Communities in Sumatra - Eight (8) Provinces (including Dinas PE, BAPPEDA) and Public Sectors in Sumatra - Industrial, Commercial & Other Private Sectors.

• Administration: - Responsible Agency: MEMR - Executing Agency: PT. PLN - Environmental Administration: MOE and BAPEDALDAs in Sumatra provinces

• Other Concerned Parties, National & International Society • Assisting Agency: JICA

6.2 Scoping 6.2.1 Protected Areas in Sumatra

MOF issued the Map of Natural Protected Areas in Indonesia as of December 2003. Refer to the

Map regarding Sumatra as shown in Appendix IV. Power facilities such as power plants and transmission lines in these Protected Areas should be avoided in accordance with the regulations. 6.2.2 Scoping by Facility Type

At this stage of power development planning, locations of specific facilities are still not distinctive.

However, it is possible and valid to assume certain environmental and social impacts by facility type since those impacts reflect the characteristics of the facility types.

Scoping was conducted by power facility type categorized as shown in Table 6.2.1 (See Appendix IV for the scoping format and criteria for the scoping items of the Study). The results of the scoping are shown in Table 6.2.2.

Table 6.2.1 Types of Power Facilities

Hydropower • Dam/ Reservoir Type • Run of River Type

Power Plants Thermal Power • Steam Turbine, Gas Turbine, Combined Cycle, Diesel • Fuel: Coal/ Natural Gas/ Diesel/ Heavy-fuel Oil

Geothermal Power Transmission Lines and Substation

17 The guidelines, Decree No.8/ 2000 (BAPEDAL; 2000a), distinguish terms such as interested community, affected community and

concerning community.

Table 6.2.2 Results of Scoping by Power Facility Type

Gas Oil(HSD)

Oil(HSD)

Oil(MFO)

InvoluntaryResettlement A B C B B B B B B B B B B C C C C B BMinority or weakpeople of society A C C B B B B B B B B B B C C C C B CInequality andseparation in society A B C B B B B B B B B B B C C C C B C

Cultural heritage A B C B B B B B B B B B B C C C C B C

Local landscape A B C A A A A A A A A A A C C C C A AEconomic activities(regional or local) A B C A A A A A A A A A A B B B B B C

Water Usage A A B A C A C A C A C A C C C C C C CContagious orInfectious disease B B C C C C C C C C C C C C C C C C C

Accidents B B C B B B B B B B B B B C C C C B C

Protected Area A A C A A A A A A A A A A B B B B A AGeographical/Geological Features B C C C C C C C C C C C C C C C C C CSediment &Hydrology A B C C C C C C C C C C C C C C C A C

Ecosystems/ Wildlife A A C A C A C A C A C A C C C C C B C

Global warming C C C A A B B B B B B B B B B B B C C

Air Pollution C C C A A B B A A B B A A B A A A B C

Water Pollution A B C A B A B A B A B A B B B B B A C

Soil Contamination C C C B B B B B B B B B B B B B B B C

Wastes A B C A A C C B B C C B B C B B B C C

Noise & Vibration B B C A A A A A A A A A A A A A A A C

Others C C C C C C C C C C C C C C C C C C B

Accidents A B C B B A A A A A A A A A A A A B A*: Right side column refers to thermal power plants with cooling tower system for condenser cooling water.

Oil*(MFO)

Steam Turbine

Gas* Oil*(HSD)

Combined Cycle

Soci

al E

nviro

nmen

tN

atur

al E

nviro

nmen

tPo

llutio

ns &

Pub

lic H

azar

ds

Dam/Re-servoir

Item

Hydro Power

Run-of-river

Mini/Microhydro

Thermal PowerTrans-

mission &Sub-

station

Geo-thermal

DieselGas Turbine

Coal* Gas*

6-3

6-4

6.3 Inclusion of Environmental Cost into Project Cost in Formulating Power Development Plan The title of this section refers to incorporating environmental costs (lost values by environmental

damage or costs for environmental mitigation, protection and conservation measures) into a market economy system, and then including it in the table of a project costs.

It is assumed that environmental costs can be categorized into the following two types:

・ Costs for environmental mitigation measures ・ Lost values by environmental damage

The former are, for example, countermeasure costs against environmental risks and for

employment of environmentally proper systems and materials, equipment costs for emission / effluent control and industrial waste treatment, costs for environmental management such as monitoring activities, social compensation and others. The latter are such as loss of basis of livelihood, human health and mental damage, forest degradation, air and water quality degradation, lost assets both cultural and natural, negative impacts on communities and global environment.

As to the former, it is a challenge to get reasonable and valid costs since standard costs are not readily available. Furthermore, evaluating the latter is an even more difficult task since defining the extent and the cause-and-effect relationships of negative impacts and then to convert the damage into a market economy value, or monetary value, is not an easy task.

The challenge of the study with respect to ESC is to incorporate these internalized environmental costs into the WASP-IV simulation. 6.3.1 Application of Scoping Results

The Study proposes two ways to apply the scoping results to the formulation of a power development plan.

(1) To use the results for WASP-Ⅳ simulation itself by weighting the environmental and social impacts by power facility type

(2) To analyze and evaluate the placement plans of power facilities in the power development plan presented by the WASP-Ⅳ simulation, referring to the scoping results by power facility type.

6-5

(1) Application of the scoping results to the WASP-IV simulation As described above, environmental costs consists of the so-called internal costs, usually estimated

as internal costs of a project, and so-called external costs, not included in the internal costs items of a project.

Environmental Costs (TEC) Internal Costs (IEC): Costs for the measures of controlling and alleviating environmental

impacts18 that can be mitigated External Costs (EEC): Adverse environmental impacts and damages that cannot be mitigate

TEC = IEC + EEC <Equation 6.3.1>

Internal and external costs can be broken down into the following items. IEC ＝（Costs for Environmental Study）＋ Mitigation Costs

＋ Environmental Management Costs • Costs for Environmental Study include assessment costs • Mitigation Costs include environmental conservation measures, social considerations,

compensations for resettlement and land acquisition • Environmental Management Costs include management, monitoring and periodical

environmental reporting

EEC ＝ loss of livelihood basis by resettlement and other reasons ＋ human health and mental damage by pollutions and public hazards ＋ loss of valuable ecosystems and landscapes that are both utilized and unutilized ＋ increased negative impacts and risks on communities ＋ α（such as global environmental impacts）

These are encoded in the following manner:

a. Environmental Study Costs <IEC> b. Compensations for Resettlement and Land Acquisition <IEC> c. Mitigation Costs（excluding resettlement and land acquisition costs）<IEC> d. Environmental Management Costs <IEC> e. External Costs <EEC>

18 Includes negative social impacts.

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Then, the next equation is formed with Equation 6.3.1, regarding the total environmental cost (TEC) that is a summation of internal and external costs.

TEC ＝ a + b + c + d + e <Equation 6.3.2>

This study does not target the planning of a specific project, but creates the basic program to

organize many prospective projects in the future and provide a foundation for the needs of individual projects, examining the composition of projects, placement of facilities and deployment schedule. Therefore, this study does not aim to internalize the environmental costs of a specific project. Rather, it aims to have the differences in environmental impacts (costs) by power facility type reflected in the WASP-Ⅳ simulation and focuses on a project cost and its environmental cost ratio by facility type.

The relationship between Environmental Costs(TEC) and total impacts evaluated by scoping, TEC ≈

the total impacts, can be assumed to exist conceptually. That is to say, the following approximate equation holds well by type of facility.

a + b + c + d + e ≈ impact level evaluated by the scoping <Equation 6.3.3>

A is given 3 as its score, B is given 2, C is given 1 in Table 6.2.2 in order to convert the scoping results into numerical quantities. On the second line, impact levels by type of facility are normalized, assuming a gas turbine with natural gas as the impact level of 1. Table 6.3.1 shows the ESC factor used for adding environmental costs in the WASP-IV simulation with ESC.

Table 6.3.1 Environmental Impact Level (ESC Factor) by Facility Type

Facility Type Scoping Total

Normalized Index Score

(GTG/ DO=1) ESC Factor

Hydropower Dam Reservoir 51 1.65 5.9% Run-of River 39 1.26 2.4% Mini Micro 22 0.71 -2.6% Thermal Power Steam Turbine Coal* 48 1.55 5.0% 43 1.39 3.5% Gas* 45 1.45 4.1% 40 1.29 2.6%

Oil (M)* 47 1.52 4.7% 42 1.35 3.2%

Combined Cycle Gas* 45 1.45 4.1% 40 1.29 2.6% Oil (H)* 47 1.52 4.7% 42 1.35 3.2% Gas Turbine Gas* 31 1.00 0.0% Oil (H) * 33 1.06 0.5% Diesel Oil (H) 33 1.06 0.5% Oil (M) 33 1.06 0.5%

Geothermal 41 1.32 2.9% Note: Facility types with * refers to thermal power plants with a cooling tower system for condenser cooling water.

ESC Factor＝(b-1)*0.1 / 1.1. TEC ≈ ESC Factor + 10% internalized environmental cost (it is assumed that 10％ is already included in the Least Cost Case).

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(2) Evaluation from the ESC aspects on WASP-IV simulation results for Proposed Case (ESC Weighted Case)

In this sub-section, the simulation results will be evaluated from the environmental and social consideration (ESC) aspects. The evaluation does not focus on each individual project, but the power development plans at the master plan stage will comprehensively be evaluated from the ESC aspects. Specifically, a major target is to compare simulation results for the Proposed Case (ESC Weighted Case) with those of the Least-cost Case studied in Chapter 4.

Specific development plans are required for the securing, maintaining and managing needed to

follow the laws, regulations and standards in the procedures of the Environmental Impact Assessment (EIA, AMDAL). (i) Least-cost Case

In the Low Demand Case of the least cost case, the total installed capacity will reach 6,724MW in 2020 and will be 2.3 times as large as 2,878MW in 2004. It consists of: 2,217MW existing power plants, 16 sites and 1,627MW in fixed projects, and 24 units and 2,880MW in candidate projects. In the High Demand Case, the total installed capacity will reach 8,374MW in 2020 and will be 2.9 times as large as that in 2004. In that case, candidate projects are increased by 39 units and 4,580MW compared to the Low Demand Case. Fixed projects consist of 2 sites and 430MW in coal thermal power plants, 5 sites and 146MW in gas turbine thermal power plants, 2 sites and 232MW in combined-cycle thermal power plants, 2 sites and 275MW in geothermal power plants, 4 sites and 479MW in hydropower plants, and 65MW increase in power purchase.

As for candidate projects, in the Low Demand Case coal thermal power plants (unit installed capacity: 100MW) will reach 13 units with 1,300MW in total (45.1% of all candidate projects), combined-cycle power plants with gas fuel (unit installed capacity: 150MW) will reach 1 unit with 150MW (5.2%), hydropower plants will reach 6 sites with 1,230MW (42.7%), and gas turbine thermal power plants (unit installed capacity: 50MW) will be 4 units with 200MW (6.9%). In the High Demand Case, coal thermal power plants will reach 23 units with 2,300MW in total (50.8% of total candidate projects), combined-cycle power plants will reach 5 units with 750MW (16.6%), hydropower plants will reach 6 sites with 1,230MW (27.2%), and gas turbine thermal power plants will reach 5 units with 250MW (5.5%).

In the both cases, coal thermal will rank first in total installed capacity and account for around a half of the total developed installed capacity. This result reflects the economy of coal thermal power plants whose fuel cost is low as a base power source. In the High Demand Case, coal thermal power plant will be developed 1.8 times as large as that in the Low Demand Case. Hydropower plant will rank second in total installed capacity following coal thermal power plant, and will reach 1,230MW in the both High and Low Demand Cases. In the Low Demand Case, gas turbine thermal power plant and combined-cycle thermal power plants will rank third and forth following coal thermal and hydropower while combined-cycle thermal and gas turbine thermal power will rank third and forth in the High Demand Case.

6-8

Table 6.3.2 Development Plan of Fixed Projects

(MW)No. Power Plant Name Type 2004 2005 2006 2007 2008 2009 2010 2011 2012 Total1 Tarahan PLTU 200 2002 Labuhan Angin PLTU 230 230

PLTU Total 200 230 430- (Palembang Timur GT) (PLTG) 100 -100 03 Truck Mounted PLTG 40 404 Indralaya PLTG 40 405 Talang Dukuh 2 PLTG 15 156 Apung PLTG 33 337 PuloGadung PLTG 18 18

PLTG Total 195 -49 1468 Palembang Timur CC PLTGU 150 1509 Keramasan CC PLTGU 82 82

PLTGU Total 150 82 23210 Sarulla PLTP 110 55 16511 Ulu Belu PLTP 110 110

PLTP Total 110 165 27512 Sipansihaporas 1 PLTA 33 3313 Renun PLTA 82 8214 Musi PLTA 210 21015 Asahan III PLTA 154 154

PLTA Total 33 82 210 154 47916 Inalum (additional) PLTA 65 65

Special Total 65 65Total 228 248 210 200 230 110 247 0 154 1,627

Table 6.3.3 Capacity Transition Plan of Existing Power Plants by Type (MW)

PLTU 746 746 746 746 746 486 486 486 486PLTD 291 295 295 75 75 0 0 0 0PLTG 431 442 442 442 442 340 340 340 340PLTGU 818 818 818 818 818 818 818 818 818PLTP 0 0 0 0 0 0 0 0 0PLTA 522 522 522 522 522 522 522 522 522Mini HP 8 8 8 8 8 8 8 8 8Special 64 45 45 45 45 45 45 45 45

Total 2,878 2,875 2,875 2,655 2,655 2,217 2,217 2,217 2,217

Type 2004 2005 2006 2011 2012~20202007 2008 2009 2010

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Table 6.3.4 Least-cost Case (Low Demand Case: 2020)

Least-cost Case (Low Demand Case) (Number)PLTU PLTG PLTGU PLTP PLTA Special Total

Fixed Project 2 5 2 2 4 1 16Candidate Project 13 4 1 0 6 0 24

Total 15 9 3 2 10 1 40(MW)

PLTU PLTG PLTGU PLTP PLTA Special TotalExisting Plant 486 340 818 0 529 45 2,217Fixed Project 430 146 232 275 479 65 1,627Candidate Project 1,300 200 150 0 1,230 0 2,880

(45.1%) (6.9%) (5.2%) (0.0%) (42.7%) (0.0%) (100.0%)Fixed + Candidate 1,730 346 382 275 1,709 65 4,507Project (38.4%) (7.7%) (8.5%) (6.1%) (37.9%) (1.4%) (100.0%)

Total 2,216 686 1,200 275 2,238 110 6,724(32.9%) (10.2%) (17.8%) (4.1%) (33.3%) (1.6%) (100.0%)

Table 6.3. 5 Least-cost Case (High Demand Case: 2020)

Least-cost Case (High Demand Case) (Number)PLTU PLTG PLTGU PLTP PLTA Special Total

Fixed Project 2 5 2 2 4 1 16Candidate Project 23 5 5 0 6 0 39

Total 25 10 7 2 10 1 55(MW)

PLTU PLTG PLTGU PLTP PLTA Special TotalExisting Plant 486 340 818 0 529 45 2,217Fixed Project 430 146 232 275 479 65 1,627Candidate Project 2,300 250 750 0 1,230 0 4,530

(50.8%) (5.5%) (16.6%) (0.0%) (27.2%) (0.0%) (100.0%)Fixed + Candidate 2,730 396 982 275 1,709 65 6,157Project (44.3%) (6.4%) (15.9%) (4.5%) (27.8%) (1.1%) (100.0%)

Total 3,216 736 1,800 275 2,238 110 8,374(38.4%) (8.8%) (21.5%) (3.3%) (26.7%) (1.3%) (100.0%)

6-10

Asahan II I PLT ARenun PLTA

Sipansih aporas PLTA

Lubhan Angin PLTU

Sibolga PLTU

Sarula PLTP

Merangin PLTA

Ketaun PLTA

Musi PLTA

Musi Rawas PLTU

Ulu Belu PLTP

Asahan I PLTA

Petro Muba PLTU

Indoralaya PLTG

Talang Dukuh PLTGU

Keramasan PLTGU


Apung & Pulo Gadung PLTG

Tarahan PLTU

Peusangan PLT A

Medan PLTU

Tampu PLTA

Jambu Aye PLT A

Meulaboh PLTU

Cirenti PLTU

Pekanbaru PLTGU

Legend

Hydro (PLTA)

Gas Turbine (PLTG)

Combined Cycle (PLTGU)

Coal Thermal (PLTU)

Geo Thermal (PLTP)

Diesel (PLTD)

Payo Selin ch PLTD

Palembang PLTGU

Banjar Sari PLTU

Truck Mounted PLTG

Prabumulih PLTU

Ranau PLTA

Asahan II I PLT ARenun PLTA

Sipansih aporas PLTA

Lubhan Angin PLTU

Sibolga PLTU

Sarula PLTP

Merangin PLTA

Ketaun PLTA

Musi PLTA

Musi Rawas PLTU

Ulu Belu PLTP

Asahan I PLTA

Petro Muba PLTU

Indoralaya PLTG

Talang Dukuh PLTGU

Keramasan PLTGU


Apung & Pulo Gadung PLTG

Tarahan PLTU

Peusangan PLT A

Medan PLTU

Tampu PLTA

Jambu Aye PLT A

Meulaboh PLTU

Cirenti PLTU

Pekanbaru PLTGU

Legend

Hydro (PLTA)

Gas Turbine (PLTG)


Coal Thermal (PLTU)

Geo Thermal (PLTP)

Diesel (PLTD)

Legend

Hydro (PLTA)

Gas Turbine (PLTG)


Coal Thermal (PLTU)

Geo Thermal (PLTP)

Diesel (PLTD)

Payo Selin ch PLTD

Palembang PLTGU

Banjar Sari PLTU

Truck Mounted PLTG

Prabumulih PLTU

Ranau PLTA

Figure 6.3.1 Protected Areas in Sumatra and Locations of Newly Developing Power Plants

(Produced by retouching “Protected Areas in Indonesia”, as of December 2003, Ministry of Forestry, Directorate General of Forest Protection and Natural Conservation)

6-11

The simulation results are evaluated from the ESC viewpoint as follows:

(Coal Thermal Power Plant) - Coal thermal will be developed with a total capacity of 2,730MW in the High Demand Case and 1,730MW in the Low Demand Case together with existing plants (430MW) and candidate projects (High Demand Case: 2,300MW, Low Demand Case: 1,300MW).

- Since coal thermal power plants may cause impacts on air pollution such as SOx, NOx, soot and dust, impacts on water pollution such as leachate from coal piles and ash disposal sites, and problems regarding the disposal and treatment of waste such as coal ash will require careful consideration.

- Other than the impacts mentioned above, careful consideration should also be given to impacts on existing water utilization by intake or discharge of condenser cooling water, impacts on ecosystems and wildlife by thermal water discharge, and problems caused by noise and vibration.

- In addition, careful consideration should also be given to impacts on environmentally protected areas and secondary impacts on them, impacts on local landscape, and any impacts on such economic activities as agriculture and fishery in cases where the power plant is developed at the mouth of river or along the coastal areas.

- Coal thermal power plants will be developed so as many as 23 units/ 2,300MW in the High Demand Case, 13 units/ 1,300MW in the Low Demand Case and so careful consideration should especially be given if some of these plants are located in the same sites. In specific, coal thermal is likely to be intensively developed as mine-mouth thermal power plants in the south region of Sumatra because there are many potential deposits of coal resources. Since coal thermal power plants will predominate over the system (38.4% in the High Demand Case, 32.9% in the Low Demand Case), global warming issues caused by CO2 emissions may arise.

(Combined-Cycle Thermal Power Plant)

- Combined-cycle thermal will be developed with a total capacity of 982MW in the High Demand Case and 382MW in the Low Demand Case, together with existing plants (232MW) and candidate projects (High Demand Case: 750MW, Low Demand Case: 150MW).

- As for combined cycle thermal power plants, careful consideration should be given to air pollution such as NOx depending on in the project location. However, since the combined cycle thermal power plant is a type of power generation that makes very efficient use of natural gas fuel and since the total installed capacity developed during the period will be less than that of coal thermal, impacts on air pollution caused by combined-cycle thermal will be estimated as being less than that of coal thermal.

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- Careful consideration should be given to impacts on water quality by thermal water discharge, impacts on existing water utilization by intake or discharge of condenser cooling water, impacts on ecosystems and wildlife by thermal water discharge, and problems caused by noise and vibration.

- In addition, careful consideration should also be given to impacts on environmentally protected areas and secondary impacts on them, impacts on local landscape, and any impacts on economic activities such as agriculture and fishery when the power plant is developed at the mouth of a river or along the coastal areas.

- Since the total development capacity will reach 5 units, 750MW in the High Demand Case and 982MW together with 2 fixed projects (Palembang Timur and Keramasan), careful consideration will need to be given to the above-mentioned points if these plants are intensively located.

- As for safety aspects, the safety of gas pipelines to power plants should be properly secured.

(Hydropower Plant)

- The candidate projects will reach 5 sites with 830MW in total capacity and 10 sites with 1,709MW together with fixed projects (4sites, 479MW) that are the same in both the High Demand Case and Low Demand Case.

- The candidate projects consist of: 1 site (100MW) with run-of-river type, Asahan I (180MW), Merangin (350MW) with dam/ reservoir type, and 3 dam/ reservoir type hydropower plants (2 sites with 100MW each and 1 site with 400MW).

- As for hydropower plant, careful consideration should be given to impacts on water utilization, ecosystems and wildlife along the areas affected by river diversion. And careful consideration should also be given to making plans to avoid environmentally protected areas and secondary impacts. Merangin hydropower is a reservoir type hydropower plant which utilizes the natural lake Kerinci, but it is not immediately located in the Kerinci Seblat National Park. It is, however, assumed that a development plan will include relevant facilities such as transmission lines and access roads which will pass through the national park or natural preservation areas because the power plant is surrounded with the park. In spite of this, since the detail plan is not decided, it is necessary to reassess whether the project should be implemented after taking into account the environmental impacts at the stage when the plan is materialized.

- As for a dam/ reservoir type hydropower, attention should specifically be paid to the impacts on society such as resettlement due to the existence of a large-scale reservoir, impacts on minorities and weak members of society due to change in life style, impacts on local society due to physical separation by a reservoir, disappearance of a heritage due to submergence, and change in the local landscape. If a run-of-river type hydropower project causes resettlement based on the project plan,

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careful consideration should also be given. For example, the Asahan III project originally required the resettlement of about 100 households at the early stage of planning because it was planned as a dam/reservoir type hydropower. But it has been changed to a run-of-river type hydropower project that mitigated impacts and resulted in the resettlement of only 10 households.

- As for hydropower in Sumatra, the resettled residents from the Kotopanjang hydropower site in Riau province have recently filed a lawsuit against the Japanese Government because they were not satisfied with the resettlement. This has taught us that careful consideration should be given to any dam/reservoir type hydropower project with resettlement plan by applying the Strategic Environmental Assessment (SEA) including information disclosure to the public and opinion exchanges through stakeholder meetings at the early project stages such as at the formulation stage of a master plan.

- In addition, as for a dam/reservoir type hydropower plant, careful consideration should be given to sedimentation in a reservoir, erosion at downstream riverbanks, water deterioration in a reservoir such as eutrophication and turbidity for long-term issues due to waste flowing into a reservoir and issues on slope collapses and landslides around a reservoir caused by the existence of a reservoir and fluctuation in a water level. Downstream safety involving discharge from a dam and an outlet, and safety against dam collapse should be secured.

- Hydropower plants, for which the careful considerations mentioned above are given, shall have the merit of clean and renewable energy which produces little CO2.

(Gas Turbine Thermal Power Plant)

- Gas turbine thermal power plants consisting of 4 units/ 200MW in the Low Demand Case and 5 units/ 250MW in the High Demand Case will be developed as candidate projects in 2007. They will reach totals of 346MW and 396MW together with 5 sites / 146MW in fixed projects.

- Candidate gas turbine thermal power plants will be developed to meet the demand as an emergency countermeasure (a short-term countermeasure) as soon as 2007 when the other types of economical power plants cannot be commissioned. This is because these plants can be developed for a short period compared with the other power sources, in spite of being a less economical power source than the others.

- A gas turbine power plant itself causes less impact than the other types of thermal power because its unit capacity (50MW) is smaller than the other power sources and it uses natural gas with better quality. It can avoid impacts on social environment with less difficulty because it can be developed anywhere as it only need a small amount of space.

- From pollution aspects, careful consideration should specifically be given to noise and vibration

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issues because the plants can be situated close to urban residences in a load center. In addition, the safety of gas pipelines must be secured if fuel for the plant is supplied through gas pipelines.

- The same environmental considerations as with a large-scale thermal power plant, such as combined-cycle thermal power plants with the same fuel, are specifically necessary if a lot of these plants are located in the same places. In this case, careful consideration should be given to air pollution, impacts on environmentally protected areas and impacts on the social environment.

- In order to reduce environmental impact, it is possible to change, in the future, gas turbine thermal power plants developed as short-term countermeasures into combined cycle thermal power plants with higher efficiency by adding steam turbine units. However, this will depend on conditions such as size and location of the site. It is important that deliberate consideration will be given to this when a specific plan is formulated.

(Geothermal Power Plant)

- A geothermal power plant with 2 sites (275MW) will be developed as fixed projects, while there will be no candidate projects by 2020.

- Careful consideration should be given to planning geothermal power plants to avoid environmentally protected areas and secondary impacts on the areas because potential geothermal power plants are likely to be situated in environmentally protected areas and/or near the areas like where hydropower plants are situated. Careful consideration should sometimes be given to impacts on a local landscape. There are no environmentally protected areas near the Sarula site in North Sumatra province and the Ulebelu site in Lampung province.

- Careful consideration should be given to impact on utilization of underground water in surrounding areas due to any impact on underground water structures because geothermal power utilizes underground thermal sources and hot steam. In addition, since extracting underground steam may cause air pollution by hydrogen sulfide and water contamination due to toxic substances such as arsenic and mercury, countermeasures returning the substances to deep underground by return wells should be taken. Depending on the location of the site, for example the plant is located near residential areas, careful consideration should also be given to such issues as noise and vibration. The safety of high-pressure steam pipelines should specifically be secured if the pipelines are situated close to residential areas.

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(Diesel Power Plant) - There will not be any fixed projects nor any candidate projects for diesel power plants. All of the existing diesel power plants with a total capacity of around 300MW will be decommissioned by 2009.

- Almost all existing diesel power plants are so old and less efficient in generation that the impacts on the environment would be higher than those from new power plants. The existing diesel power plants will seemingly be replaced with other new power sources in the future such as thermal power and hydropower. Therefore, the decommissioning of existing diesel power plants is desirable from the environmental aspects.

- However, if planned new power plants are not successfully developed in the future, existing diesel power plants, as emergency countermeasures, will be relocated to Sumatra from other regions. In that case, the relocation should be done while making the proper environmental and social considerations.

- Diesel power plants are likely to be situated in urban areas. Therefore, careful consideration, specifically for noise and vibration issues and impacts on air pollution, should be given for this development. In addition, attention to impacts from air pollution should specifically be given if the diesel power plant uses fuel containing harmful constituents such as heavy fuel oil.

The below tables refer to the comparisons in the total capacity of candidate projects, the total

investment cost and the system cost up to 2020, of the CO2 Emission Prevention Case, the Limited Natural Gas Supply Case, the ESC Weighted Case and the ESC Weighted Case without Merangin Hydropower Plant with those of the Least-cost Case. The following subsections from (b) to (d) describe the comparisons between the cases with the Least-cost Case. The subsection (e) describes the comparison between the ESC Weighted Case and the ESC Weighed Case without Merangin HPP.

Table 6.3.6 Comparison in Total Capacity of Candidate Projects up to 2020 (Low Demand Case)

(Unit: MW)

TotalCapacity

deviationTotalCapacity




deviation

Least-cost Case 1,300 Base 200 Base 150 Base 1,230 Base 2,880 Base

CO2 Emission Prevention Case 600 -700 200 0 750 600 1,230 0 2,780 -100

Limited Natural Gas SupplyCase 1,400 100 200 0 150 0 1,230 0 2,980 100

ESC Weighted Case 1,300 0 200 0 150 0 1,230 0 2,880 0

ESC Weighted Casewithout Merangin HPP 1,400 100 200 0 300 150 880 -350 2,780 -100

PLTA Total

CasePLTU PLTG PLTGU

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Table 6.3.7 Comparison in Total Capacity of Candidate Projects up to 2020 (High Demand Case)

Table 6.3.8 Comparison in Investment Cost (total investment cost up to 2020)

(Unit: million US$)

TotalInvestment

Costdeviation

TotalInvestment

Costdeviation

Least-cost Case 3,454 Base 4,836.5 Base

CO2 Emission Prevention Case 3,114 -340 4,346.5 -490

Limited Natural Gas Supply Case 3,554 100 5,076.5 240

ESC Weighted Case 3,454 0 4,836.5 0

ESC Weighted Casewithout Merangin HPP 3,218 -236 4,875.5 39

Case


Table 6.3.9 Comparison in System Cost (total system cost up to 2020)19

(Unit: million US$, NPV in 2003)

Sysytem Cost deviation System Cost deviation

Least-cost Case 5,248 Base 6,237 Base

CO2 Emission Prevention Case 5,228 -20 6,220 -17

Limited Natural Gas Supply Case 5,263 15 6,275 38

ESC Weighted Case 5,248 0 6,237 0

ESC Weighted Casewithout Merangin HPP 5,252 4 6,277 40

Case


19 The Table shows the system cost of the CO2 Emission Prevention Case is lower than that of the Least-cost Case. But the system cost up to

2025 of the Least-cost Case is the lowest among the cases.

(Unit: MW)

TotalCapacity





deviation

Least-cost Case 2,300 Base 250 Base 750 Base 1,230 Base 4,530 Base

CO2 Emission Prevention Case 1,000 -1,300 250 0 2,100 1,350 1,230 0 4,580 50

Limited Natural Gas SupplyCase 2,900 600 250 0 150 -600 1,230 0 4,530 0

ESC Weighted Case 2,300 0 250 0 750 0 1,230 0 4,530 0

ESC Weighted Casewithout Merangin HPP 2,900 600 350 100 450 -300 880 -350 4,580 50

PLTA Total

CasePLTU PLTG PLTGU

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(ii) ESC (Environmental and Social Consideration) Weighted Case The difference in candidate projects of the Least -cost Case and those of the ESC Weighted Case

are as follows:

- Total capacity of the candidate projects up to 2020 is the same between the Least-cost Case and the ESC Weighted Case. Twenty-four units with 2,880MW in the Low Demand Case and 39 units with 4,530MW in the High Demand Case will be developed.

- In the Low Demand Case, 1 hydropower site (100MW) out of 2 hydropower sites (200MW) in 2015 in the Low Demand Case is extended its commissioning year to 2017, while 1 unit (100MW) out of 3 units (300MW) of coal thermal in 2017 is brought forward to 2015.

- On the other hand, in the High Demand Case, there are no difference between the development plan of the Least-cost Case and that of the ESC Weighted Case even in the commissioning year.

- Gas turbine power plants do not change in terms of developed capacity and commissioning year. Geothermal will not be developed as candidate projects like in the Least-cost Case.

The results of the ESC Weighed Case are compared with those of the Least-cost Case from the

environmental and social consideration aspects as follows:

Firstly, in the Low Demand Case, no difference in total capacity of candidate projects is found between the Least-cost Case and the ESC Weighted Case by applying the ESC factor to the simulation study. However, the order in development of coal thermal and hydropower after 2015 is changed. A reservoir type hydropower (100MW) is extended from 2015 to 2017, while 1 unit of coal thermal (100MW) is brought forward from 2017 to 2015. These candidate projects switched their commissioning year with each other. We could say that this reflects the ESC factor of a reservoir type hydropower is higher than that of a coal thermal. From the system cost aspects, construction cost becomes lower and operation cost becomes higher because a hydropower with higher in capital cost is extended and, on the other hand, a coal thermal with higher in operation cost (fuel cost) is brought forward. However, total system cost is same between both the Least-cost Case and the ESC Weighted Case.

On the other hand, in the High Demand Case, no difference in total capacity and commissioning

year of candidate projects is found, and total investment cost and system cost are the same between both the Least-cost Case and ESC Weighted Case. Therefore, we could say that the Least-cost Case is the same as the ESC Weighted Case in the High Demand Case from ESC aspects because the ESC factor applied in the study makes no difference in total capacity of each type of power plant and commissioning year, namely development plan.

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(3) Evaluation of Transmission Plan from the ESC aspects The transmission plan that is studied after formulation of the optimal power development plan will

be assessed from the ESC aspects.

Transmission lines planned between the power plants and a power system should be surveyed and studied during the planning of an individual power plant. Even when the power plant has no problems from the ESC aspects, the power plant cannot supply electricity to the grid system if construction of the transmission lines is difficult due to problems along the transmission line routes. Therefore, it should be noted that careful consideration should be given to transmission line plans when a power plant is being planned.

As for transmission lines supply power to a load center, if difficulties in the ESC are hard to avoid

and mitigate, specifically in the areas where buildings, facilities and residences are crowded, measures such as underground installation to avoid and mitigate these problems can be taken. In this case, it should be noted that the cost for underground installation of transmission lines is higher than that of overhead transmission lines.

Interconnection transmission lines are generally very long (more than a few hundred km) and have

high voltage such as 275kV and 500kV to reduce transmission loss and secure stability as it connects different regions. As a result, transmission tower structures are large (around 50-100m high). Therefore, impacts on natural and social environment such as the impacts on the local landscape become large. In addition, careful consideration should be given to environmentally protected areas because transmission lines are often situated in mountainous and depopulated areas and other areas where the natural environment prevails.

Careful consideration should be given to transmission lines at the planning stage. This includes the

selection of transmission line routes to avoid being situated in protected areas and to minimize impact on landscape, the painting of transmission towers in scenic areas, and avoiding electrocution by securing enough clearance between the ground and the lines, doubling the protection relays, and warning the public to not climb the transmission lines. In urban areas, underground installation of transmission lines is one countermeasure to avoid or mitigate impacts by transmission line.

In Sumatra the West system often suffered from power outages in 2004 because construction works

on the 275kV interconnection transmission line between Bangko and Lubuk Linggau was delayed due to long delays arising from such issues as compensation for landlords and, in addition, power shortage in the West system

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From this lesson, careful consideration should be given to the development of transmission lines by

applying the Strategic Environmental Assessment (SEA) including information disclosure to the public and

opinion exchanges through stakeholder meetings at the early stage of planning such as the formulation stage of a master plan.

As for impact by the electric magnetic fields (EMF), public organizations have expressed their

view that EMF does not have harmful impacts on the human body by comprehensively assessing many studies.

Any plans for major transmission lines with higher voltages in 275kV and 500kV will roughly be

assessed from the ESC aspects.

Power development in the Proposed Case 1 is the greatest among the above four cases. A 500kV transmission line between Galang and PLTU Bnjar Sari will be added if power development is facilitated in the South system (South Case 1), while the interconnection lines to the Malaysia and Java-Bali systems will be added if the cases includes the interconnection plans (Proposed Case 2 and South Case 2).

Therefore, the order of amount of transmission line development is as follows:

South Case 2 > South Case 1 > Proposed Case 2 > Proposed Case 1 From the ESC aspects, the impact to natural and social environments is on the same order as those

for transmission line development. On the other hand, from the viewpoint of power development, the following should be considered:

○ The amount of power development will be decreased due to the merits of interconnection if the

interconnections to the Malaysia and Java-Bali systems are included in the plan. ○ The impacts to natural and social environment by total power development will be changed

because the power mix in all of Sumatra and each region will be changed if power development in the South system is facilitated. For example, power development in the north and west systems will be decreased if that in the South system is increased, and hydropower development in the North and West system will be decreased if coal thermal power in the South system is increased.

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As for the former point, the total impacts on natural and social environment should be considered taking into account both impacts by the interconnection line increase and the power development decrease. On the other hand, as for the latter point, the regional differences in the amount of power development will result in varying degrees of impact on the natural and social environment. Therefore, the impacts on the natural and social environments should be comprehensively assessed by taking account of the above-mentioned items and the impacts by 500kV transmission lines.

Since specific transmission line routes have not been fixed yet, relations between the transmission

line plan described above and environmentally protected areas will be roughly identified. Careful consideration should specifically be given to the following from ESC aspects. Specifically, careful consideration should, in the future, be given to the planned transmission lines including the following ones when it is identified that they may cause impacts on environmentally protected areas. ○ Banda Aceh - PLTU Meulaboh - Binjai (275kV, 2cct.)

- Careful consideration should also be given to the national park Gunung Leuser and the game reserve Lingga Isaq to avoid impacts when the route is selected.

○ PLTU Meulaboh - PLTA Tampur - Binjai (275kV, 2cct.)

- Careful consideration should also be given to the national park Gunung Leuser and the game reserve Lingga Isaq to avoid impacts when the route is selected.

○ Binjai - Galang (275kV, 2cct.)

- Careful consideration should be given to the grand forest park Bukit Barisan when line route selection.

- Careful consideration when line route selection should be given to other protected areas such as nature recreation parks and nature reserves, which are respectively small, exist near the route.

○ PLTA Merangin - Bangko (275kV, 2cct.)

- Merangin hydropower plant itself may affect the national park Kerinci Seblat. Since the transmission line between the power plant and Bangko substation may affect the national park, careful consideration should be given to the park.

○ Kalianda - Java Bali interconnection (150kV, 2cct.)

/ PLTU Bnjar Sari - Java Bali interconnection (HVDC) ○ G.Sakti - Malaysia interconnection (HVDC）

Careful consideration for not only the natural and social environment in Sumatra, but also those in Java island and Malaysia, should be given for these interconnection lines.

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Transmission lines connect power plants and substations. The surrounding areas near substations may be crowded with transmission lines where many transmission lines are concentrated. In this case, the transmission lines may cause impacts on the local landscapes and make it harder to reach a consensus on their construction in densely populated urban areas. Effective consideration should be given to substations that may be crowded with many transmission lines like those mentioned above. Such considerations may include selecting a location in advance where the local landscape is hardly affected and few residents are living. If an additional transmission line is planned to connect to an existing substation, one of the countermeasures is to change the location of the substation and build a new substation.

It is important to avoid or mitigate impacts on the environment to avoid building new transmission lines by replacing existing transmission lines with reinforced ones and installing more than one line on the transmission towers.

6.4 Initial Study of Mitigation Measures

In this subsection, fundamental mitigation measures will be discussed. Specific mitigation measures for each individual project should be made by studying the optimal measures based on results of sufficient surveys and analysis at the pre-feasibility study and feasibility study stages on every site from now on.

It is important to make mitigation measures for the optimal power development plan based on the

fundamental policies as follows: ○ Effective use of energy resources

- Adopting high efficiency equipment - Reducing transmission, substation and distribution losses - Facilitation of renewable energy use

○ Improving management of effluvium and waste by applying zero-emission, reduction, recycling and reuse policy

○ Complete environmental management by establishing monitoring systems ○ Building communication with surrounding residents and stakeholders and establishing

cooperative relationship

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One of the mitigation measures is to facilitate the measures from not only the supply side but also the demand side as follows.

○ Saving electricity consumption by applying DSM

- Effective use of energy by electricity consumers - Facilitating the introduction of energy-saving equipment - Raising energy-saving consciousness

Each mitigation measure will be described by environmental items as follows:

(1) Social Environmental Aspects (i) Consideration of Site Location and Selection of Transmission Line Routes

(Environmental and Social Item) Involuntary resettlement, Minority or weak people of society, Inequality and separation in society, Cultural heritage, Local landscape

(Mitigation Measures) - These impacts should be avoided in the development plan as much as possible. If they cannot be

avoided, they should be minimized. - Dam/reservoir type hydropower: Changing the dam location or lowering its height would be worthwhile if resettlement could be remarkably improved. In the case of a thermal power project.

- Thermal power: The development plan should fundamentally be changed since it is easier to change the site location.

- Transmission line: Avoid resettlement problems by making detours around the area. (ii) Formulation of Proper Resettlement Plan and Compensation Plan, Residents' Consensus and Proper

Implementation (Environmental and Social Item)

Involuntary resettlement (Mitigation Measures)

- If resettlement cannot be avoided, residents' consensus is necessary by formulating resettlement and compensation plans and by properly explaining the plans to the targeted residents.

- It is necessary to properly prepare and maintain financial measures and implementation structures to realize the plans.

- In addition, these processes should be guaranteed under the legal system. - In formulating resettlement plans and compensation plans, and in reaching consensus by

explaining to residents, information disclosure and holding stakeholder meetings are necessary at an early stage by introducing concepts from the Strategic Environmental Assessment (SEA).

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(iii) Careful Consideration of Layout, Shape, and Color of Power Plants (Environmental and Social Item)

Local landscape (Mitigation Measures)

- Reviewing the layout of a power plant. - Placing tall buildings, such as a boiler building, turbine, generator building and a stack on the

inside of a site to avoid being in plain site may mitigate impacts on local landscape. - Having the coloring of a building match the local landscape. - In the case of hydropower plants, adopting tunnel or shaft type waterways and using underground

powerhouses may mitigate impacts on local landscapes and environments. - In the case of substations where many transmission lines may concentrate and be crowed, careful

considerations in advance, such as locating them on the sites where they may not affect local landscape and where there are few residents.

- Building a new additional substation by changing its location from the existing one is a countermeasure that can be adopted for a plan connecting new transmission lines to an existing substation.

(iv) Maintaining Proper Water Utilization

(Environmental and Social Item) Water usage

(Mitigation Measures) - In the planning of a hydropower plant, formulating a generation plan that includes discharging the

proper water flow to downstream of the dam and outlet by deliberately examining the situation for downstream water utilization.

- In planning the taking and discharging of condenser cooling water at a thermal power plant, the location of the plant and layouts for intake and an outlet should be properly planned taking into account impacts on fishery activities around the plant.

- Adopting a cooling tower system for condenser cooling is one countermeasure against impacts on water utilization.

(2) Natural Environmental Aspects (i) Consideration of Site Location and Selection of Transmission Line Routes

(Environmental and Social Item) Protected area, Impacts on ecosystems/ wildlife, or the secondary impacts on them

(Mitigation Measures) - Dam/ reservoir type hydropower: Changing the location of the dam site and lowering the dam height

are worthwhile to revise the plan if impacts on environmentally protected areas and ecosystems/ wildlife can be avoided or mitigated.

- Thermal power: The development plan should fundamentally be changed in order to avoid impacts on environmentally protected areas and ecosystems/ wildlife

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- Transmission line: Avoid environmentally protected areas and ecosystems/ wildlife by making detours around the area.

- Transmission line expansion plan: Avoid expansion of transmission lines as much as possible by reinforcing the transmission lines on the existing transmission tower and by mounting more than one transmission line on the transmission towers while keeping the same single route.

- Secondary impacts such as impacts by many immigrants due to the creation of a reservoir after building the facilities should also be deliberately considered.

(ii) Minimizing Land Alteration

(Environmental and Social Item) Geographical/ geological features

(Mitigation Measures) - In the panning stage of a specific power plant, alteration of land should be minimized even if the

land has to be altered. - Excavation, dredging, reclamation and landfills should be minimized, taking into account the

balance of earth and sand. Furthermore, earth and sand by excavation and dredging should be effectively used for reclamation and landfill.

- Studying not only the project itself but also regional development plans could minimize impacts. - Soil runoff should be avoided by installing walls if such runoff is anticipated.

(iii) Adopting Generation Equipment with High Efficiency

(Environmental and Social Item) Ecosystem/ wildlife, Global warming

(Mitigation Measures) - Adopting highly efficient equipment can reduce impacts on the air environment and CO2 emission

per kWh due to higher generation efficiency. - Unit capacity should be upgraded if many units are planned to be built at the same site in order to

reduce CO2 emission. (iv) Applying Kyoto Mechanisms

(Environmental and Social Item) Global warming

(Mitigation Measures) - CDM can contribute to countermeasures against global warming issues and reduce project cost. - CDM should be utilized to develop renewable energies such as hydropower, geothermal,

photovoltaic cell and biomass generation, and to apply highly efficient equipment to thermal power.

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(v) Countermeasures against Slope Collapse and Landslide around a Reservoir (Environmental and Social Item)

Geographical/ geological features (Mitigation Measures) - Avoid site locations where land collapses and landslides are anticipated by carrying out sufficient

geological surveys at the planning stages. - Some of the countermeasures are to make a hydropower plant with conditions for limiting the high

water level, regulating the fluctuation speed for a reservoir water level, and applying countermeasure works to the dangerous slopes.

(3) Pollution and Public Hazards (i) Countermeasures against Air Pollution (a) Utilizing Proper Quality Fuels

(Environmental and Social Item) Air pollution

(Mitigation Measures) - Utilization of proper quality fuel: Coal thermal and oil thermal power use fuels containing sulfur and

ash. Utilizing fuels which contains these matters as little as possible can reduce impacts on environment.

- It is necessary to deliberately evaluate economic benefits and whether fuel should be changed to ones with better quality or whether countermeasure equipment should be installed with low quality fuel.

- Environmental countermeasures for existing thermal power are environmental mitigation by proper quality measures such as conversion from oil into natural gas and conversion into low sulfur oil.

- Conversion into low sulfur oil should comprehensively be studied, taking into account the entire country’s oil consumption because applying a conversion to low sulfur oil to specific power plants is not always a wise policy.

- In the study, countermeasures should assume that low quality fuel will be intensively used at new power plants with installation of environmental equipment and converted into proper quality fuel at existing power plants without this equipment.

(b) Adopting a Taller Stack


(Mitigation Measures) - Raising the height of a stack at a thermal power plant could reduce impacts to the surrounding

environment by decreasing ground level concentration due to improved diffusion effect for exhaust gas.

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(c) Adopting Electrostatic Precipitators (Environmental and Social Item) Air pollution (soot and dust) (Mitigation Measures) - As for coal thermal among thermal power, the Electrostatic Precipitator (EP) should be installed to

prevent diffusion of soot and dust into the surrounding environment as coal fuel contains a lot of ash constituents.

- Large-scale oil thermal, except for gas thermal, should also be studied as to whether EP should be installed by evaluating anticipated impacts on the surrounding environment.

(d) Adopting Flue Gas Desulfurizer

(Environmental and Social Item) Air pollution (SOx)

(Mitigation Measures) - As for coal thermal and oil thermal among thermal power, impacts on the surrounding environment

such as acid rain may be anticipated. Therefore, installation of the Flue Gas Desulfurizer (FGD) should be studied if this is anticipated.

(e) Adopting Exhaust Gas Denitrizer (Environmental and Social Item)

Air pollution (NOx) (Mitigation Measures)

- Specifically, installation of FGD at coal thermal power plants should be studied according to the

amount of development and geographical features as coal contains a lot of nitrogen. (f) Adopting Highly Efficient Equipment


(Mitigation Measures) - Adopting highly efficient equipment can reduce impacts on the air environment per kWh due to

higher generation efficiency. - Upgrading unit capacity, for example installed capacity from 100MW to 300MW per unit, can

generally improve generation efficiency because the larger a unit capacity is, the easier the technology for improving generation efficiency can be applied. Therefore, upgrading unit capacity is recommended for reducing air pollution when many units are planned to be built at the same site.

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(ii) Countermeasures against Deterioration in Water Quality (a) Countermeasures against Thermal Effluent

(Environmental and Social Item) Water pollution (Thermal effluent), Ecosystems/ wildlife, Water usage

(Mitigation Measures) - Impacts on the surrounding environment due to thermal effluent from thermal power plants should

be evaluated with the anticipated temperature rise. - To reduce the affected area, adopting the following system is recommended; a cooling system taking

water from low temperature layers (deep layers); a quick diffusion system for thermal effluent; studying the layout of intakes and outlets to prevent recirculation of thermal effluent.

- Proper planning for the location of power plants, intakes and outlets of cooling water for condensers should be studied taking into account the surrounding ecosystems / wildlife.

- Adopting a cooling tower system to cool water for condensers is one countermeasure against impacts on ecosystems / wildlife.

(b) Countermeasures against Deterioration in Water Discharged from Dam and Power Plant

(Environmental and Social Item) Water pollution, Ecosystems/ wildlife, Water usage

(Mitigation Measures) - Selective water withdrawal equipment, which takes the top clear layer of reservoir water in order to

prevent taking deteriorated sediment water, should be installed if reservoir water may deteriorate for a long period at a reservoir-type hydropower plant.

(c) Measures for Preventing Eutrophication in a Reservoir

(Environmental and Social Item) Water pollution (Eutrophication), Ecosystems/ wildlife, Water usage

(Mitigation Measures) - There may be eutrophication of the hydropower plant reservoir depending on upstream water use,

draining of living water in the surrounding area and the quality of the water source. Reservoir water quality should be evaluated at the planning stage by making assumptions based on water quality investigations and environmental surveys in the surrounding area.

- Increasing the number of exchange times for the reservoir water may be one countermeasure resulting from reviews of generation and operation plans.

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(iii) Recycle Use and Management of Waste such as Coal Ash (Environmental and Social Item)

Wastes (Mitigation Measures)

- As for a new coal thermal power plant, the study of the effective use of coal ash, securing an ash disposal area, and establishing the proper management of ash disposal areas are necessary in planning the plant.

(iv) Countermeasures against Noise and Vibration

(Environmental and Social Item) Noise and Vibration

(Mitigation Measures) - A layout that keeps enough distance between the main equipment and the border of the plant site and

the installation of soundproof walls and equipment will be necessary. (v) Announcement of Water Discharge to Downstream of Dam and Outlet

(Environmental and Social Item) Accidents (Hydropower)

(Mitigation Measures) - To prevent damage to downstream river users, it is necessary to establish restrictions on power plant

operation to regulate the speed in which the water level rises downstream and install an announcement system to inform downstream river users in advance of the water discharge.

6.4 Recommendations for ESCs in the Next Planning Process Step (1) ESC needed for the next step in the planning process

The basic concepts of this study include basic measures such as avoiding protected areas. However, this study does not determine the location of each project included in the draft of the master plan. From this point on, as locations of individual projects are to be further narrowed, these locations will need to match the regional development plan of each province in Sumatra, the spatial plan and designations of protected areas. Accordingly, the proponent of projects needs to be in close contact with the mining and energy department (Dinas PE), planning department (BAPPEDA), environmental management department (BAPPEDA), and forestry department (Dinas Forestry) of each province (prefecture if necessary).

The next planning stage of this study is the feasibility study for each electric power development project whose necessity is recognized in the master plan. The following are recommendations for ESCs needed for the feasibility study in individual projects such as hydroelectric power development, thermal power plant development and projects for transmission grids.

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a) Implementation of the EIA study in the feasibility study In the feasibility study for each project, the project proponent (PLN) needs to proceed with the EIA

process (AMDAL in Indonesian) in accordance with the government decree on environmental impact assessment (government decree No. 27 of 1999). EIA would be required in all plans, except for small ones, for power development. The feasibility study will clarify such factors as location of the project and dimensions of buildings, facilities and equipment. It will thus need to look into environmental and social impacts and mitigation measures in a more thorough fashion than at the master plan stage. For instance, development of a thermal power plant often needs a field study of pollutants in the air around the prospective location and a simulation of the spread of pollutants. On the other hand, a hydroelectric power development needs a study of the current state of river water quality and the ecosystem, a more thorough understanding of the impacts from resident resettlement, and plans for specific mitigation (minimizing the scale of resettlement and compensation for resettlement). In addition, EIA needs to produce the EIA report and formulate an environmental management plan as well as an environmental monitoring plan (government decree No. 27 of 1999).

Prior to implementing EIA it is important to set in a clear and fair manner the objective, method and scope of the ESC study (hereinafter referred to as TOR of EIA). The implementing agency (the project proponent) must confer and be in close contact with the relevant government agencies on how to proceed with ESC prior to setting the need and contents of EIA, depending on the size of the project. If the project affects more than one province or is particularly large, the project proponent must confer with the national Environment Ministry. If the project is within the boundaries of a province or prefecture, the proponent is to engage in a dialogue with the environment department (BAPEDALDA) of the province or prefecture.

Communication with the government agencies responsible for environmental administration makes

it easier to carry out information disclosure to project stakeholders and participation of stakeholders in the project planning and implementation process. The executive order No. 8 of 2000 by the BAPEDAL Secretary on ESCs, the JICA environmental and social guidelines in effect since April 2004 and other international ESC and EIA guidelines all focus on and gives high priority to the participation of stakeholders.

In formulating a project plan, the priorities in terms of the measures to alleviate impacts (mitigation measures) should be in the following order: (1) Avoid; (2) Minimize; (3) Rectify; (4) Reduce; and (5) Compensate. In other words, the most important concept in mitigation of impacts is to avoid them in the first place if at all possible. If they cannot be avoided, then one may choose to minimize them. Compensation is seen as the last resort.

In EIA in the feasibility study and during project implementation, most of the time a donor agency supports EIA and a private EIA specialized organization implement it on a contractual basis. However, the project implementing agency’s capacity for ESC will be challenged when the contents planned in

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EIA are to be put into practice in a sustainable manner after the project. At the stage of EIA implementation, the project implementing agency needs to firmly establish a system within itself to implement ESC in the project at hand in order to make possible its ownership of the project after implementation, as well as sustainable environmental management. For the sake of efficiency, it is possible to outsource the EIA study to an outside organization. However, by taking the lead in ESC at project office, the system mentioned above can prepare for the implementation of measures for ESC and sustainable environmental management after the project. b) Hydroelectric power development

In hydroelectric power development one needs to pay particular attention to the following aspects at the EIA stage in the feasibility study (F/S). Relations with protected areas

The outline of the project is to become clear at the F/S stage. Accordingly, it is necessary to set details of the project plan with particular attention to relations with the locations of natural protected areas. The project team needs to pay attention to the impacts of related surrounding facilities such as access roads in addition to dams, water reservoirs, power plants and conduits. Indonesia has nature reserves, wildlife reserves, national parks, tourist recreational parks and forest parks. Sometimes the project team may need to give due consideration to protected cultural heritage sites, enclaves of minority people and scenic areas. In recent years, particular attention has been paid to animal passages (biological corridors) that connect protected areas and parks from the perspective of protecting wildlife and ecosystems. Electric power transmission routes

With regard to electric power transmission lines, there have been cases of taking a detouring route in an area with small impacts and sometimes through a protected area with approval by an assessment. However, a project plan should avoid such methods if at all possible. A hydroelectric power plant may be constructed in a reservoir or somewhere upstream of a river basin. Accordingly, it is necessary to formulate a plan for an electric power plant in such a way that it enables selection of power transmission routes with due consideration to preservation of forests and landscape, along with a reduction of disaster risks. Consideration of environmental impacts including secondary ones such as increase in migrating

population through a newly built access road In the existing hydroelectric power development projects, there have been numerous problems

including the following: deterioration of vegetation in river basins due to disorderly cultivation by residents who moved to the vicinity of the project and illegal logging by various companies; dumping of garbage; pollution of lakes and rivers due to such garbage and an increase in the inflow of discharged water from fish culture. These problems have been caused by access roads that let people go into remote areas and make access by car easier, invigorating and diversifying commercial activities. The project

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team needs to have discussions with local governments regarding the implementing plans for restriction on entry into the area, notification systems for commercial activities, and environmental education on such subjects as the proper management of garbage. Then the team needs to incorporate such implementation plans as a management plan for the regional environment in the environmental management plan that goes with EIA. Minimizing the scale of resident resettlement Formulating a resettlement method with the least impact

Though it may be necessary to relocate residents for the construction of a hydroelectric power plant, the highest priority is to minimize the scale of resident resettlement even if resettlement is unavoidable. If compensation through resettlement is the only remaining option, the project proponent must formulate a reasonable and workable resettlement plan that makes the living conditions of the relocated families as similar as possible to the conditions prior to the resettlement. For that purpose, dialogues with residents are essential. The following are indicators for selecting a resettlement destination.

Minimizing the moving distance for an involuntary resettlement

Securing drinking water and water for daily use

Selecting a resettlement destination with as similar living conditions as possible

Securing a safe and sanitary living environment

Similarities in working and educational conditions Maintaining unity with neighboring communities

Access to places for religious and recreational activities

Coordination of interests and joint water resource management with other sectors using water

Water resources used for hydroelectric power generation in the river are shared with various users. Accordingly, it is very important to confer with stakeholders on rules to obey in the use of water. Rights to the usage of water must be coordinated in advance as there are regions that set the priorities for the rights in a traditional way.

c) Construction of a thermal electric power plant

In planning the construction of a thermal electric power plant, one needs to pay particular attention to the following aspects at the EIA stage in the feasibility study (F/S). Prediction on the impact of air pollution

At the F/S stage of individual projects, details including the following become clear: location of the construction, type of fuel, scale of the facilities and composition of the facilities. Accordingly, at the EIA level an environmental prediction will be needed on the concentration of pollutants in the ambient atmosphere. Predicative assessment will also be needed on such matters as smoke dust, SOX, NOx, photochemical smog and acid deposition.

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Checking the regulations on the air quality and study of facility designs and pollution prevention measures (mitigation)

The project proponent needs to check national and regional regulations on the concentrations of air pollutants and study the following aspects for mitigation in the basic design: fuel to use, composition of facilities for preventing pollution (e.g. height of chimneys, dust collector, desulphurization and denitration equipment) and operation methods. Consideration for compound impacts to such matters as the air quality of the area

A thermal electric power plant is likely to be set up near a city with high traffic density or a waterfront or an estuary near an industrial zone. Therefore, the project proponent needs to put forward forecasts with due consideration to the following: NOx emission from cars, diesel gas emissions from large vehicles, acidic substances from nearby factories (SOx, NOx), heavy-metal pollutants and ozone and compound impacts from these substances. To take effective measures against compound impacts, the project proponent needs to exchange information with local governments and work proactively with them on comprehensive regional development plans and environmental management plans. Study of disposal and control methods of coal ashes and other by-products in coal-burning thermal

power plants A coal-burning thermal electric power plant needs the proper management and disposal of coal

ashes. Ways of disposing of coal ashes include the following: putting them in a landfill or using them for construction materials, ceramics and soil conditioners. From the stage of design outline, the project team needs to formulate a concrete plan for the disposal of coal ashes including the quantities of disposal by method, securing the needed land and ways to prevent the scattering of ashes. Existing projects have not taken adequate measures in transporting routes and disposal sites for preventing the scattering of ashes by watering, covering with soil, and the proper disposal of waste water. Forecasting and study of countermeasures for problems in fuel shipping, noise and vibration

Since a thermal electric power plant uses petroleum and natural gas as fuel, there are risks of fire and explosion in the ships, vehicles and pipelines that carry this fuel. There will be also the problems of noise and vibration if a thermal power plant is set up in an urban area. There have been problems caused by changes in the outside environment after the planning stage, e.g. an increase in residential houses near the plant boundaries. Accordingly, the project proponent should study countermeasures by creating with the relevant government agencies rules and regulations on safety measures for fuel shipping routes and the use of land in the vicinity. d) Transmission grids

In planning transmission grids one needs to pay particular attention to the following aspects at the EIA stage in the feasibility study (F/S).

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Study of land usage along the grid route A study on stakeholders and land usage along the grid route is needed to clarify the following items.

・Existence of protected areas ・Lifestyles, characteristics and number of stakeholders ・Basic conditions of their awareness on and cooperation with electric power projects ・Number of households to be relocated ・Types and values of agricultural products in forests and farms

Study of ways to avoid protected areas

Transmission grid routes are to be established on the principle of avoiding protected areas. An alternative location for grids is to be considered if there is no way of going around protected areas. Study of safety measures

Safety measures under overhead wires are to be studied. (2) Consideration of cumulative and compound impacts

From the perspective of strategic environmental assessment, project formulation needs to be done very carefully with attention not only to environmental and social impacts from a single project that appear immediately, but also cumulative impacts as a result of long-term and underlying causes, as well as compound impacts from multiple projects, sectors and human activities in the same areas and locations over a long time. The JICA Guidelines for ESCs since April 2004 also request due consideration on such cumulative and compound impacts20. a) Cumulative impacts over years

The following are cumulative impacts from long-term repeated factors in the development of an electric power plant.

- Accumulation of chemical impacts (media) ・Deposition of oxidized substances・Rare metallic substances・Photochemical smog on trees

and inhabitants - Accumulation of impacts on the air quality ・Heat-trapping gases such as CO2

- Accumulation of hydrological impacts ・Change in the quantity of flow ・Collection of ground water and steam ・Change in water temperature and quality

- Cumulative impacts on geological shape, conditions, and ground ・Change in landscape・Continuous slope failure

20 JICA Guidelines for ESCs, 2.3, p.7, April 2004

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- Accumulation of biological and ecological impacts ・Change in river basin・Fishes that swim upstream・Amount of forests and ratio of vegetation

cover - Cumulative impacts on the global environment ・Global warming・Amount of natural resources

- Cumulative impacts on the socio-economy and the regional economy ・Triggering human activities in undeveloped places

The project team needs to plan a study to assess long-term impacts in a thorough manner, not just a

shortsighted assessment. Most of the problems, however, are ones that a single project may not be able to address on its own. It is thus necessary to thoroughly consult the local environmental management and protection plans at the time of ESCs (assessment) and examine the role of the electric power project at hand. If there is no basic environmental management and protection plan in the area even though problems are expected to worsen, then it may make sense for the project proponent to approach local government actively and help formulate a local environmental basic plan. The party that requests the project also needs to consider giving job instructions (TOR) to make possible such study and evaluation activities. b) Compound impacts by multiple projects and sectors

The followings are examples of compound impacts by human activities and economic/industrial sectors in the same area or phenomenon, as well as by the electric power sector.

- Development of remote areas, undeveloped areas around new access roads ・Partnership with local governments (local environmental management)

- Concentration of factories in areas such as river estuaries ・Waste water・Gas emissions・Impacts on vulnerable ecosystems such as mangrove wetlands

- Control of the total amount of pollutants ・Regional restriction on the total emission・Compound impacts of and exposure to pollutants

- Destruction of landscape - Global warming - Depletion of natural resources ・Water resources・Underground mineral resources

Like the problems of cumulative impacts, these problems cannot be addressed by a single electric

power development project or the electric power sector alone. Recommended measures include the following: approach local governments and environmental administration; formulation of self-imposed regulations and standards by industries; and joint research on environmental improvement by industries.

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(3) Recommendations on environmental management and monitoring Indonesia’s decrees21 require the submission of the environmental management plan (RKL) and

monitoring plan (RPL) attached to the EIA report. To comply with the requirement, the existing electric power projects implement monitoring and submit reports on a regular basis. ESCs in the project include the following: environmental management throughout the project life cycle, i.e. at the stages of construction, operation and proper closure of the facilities; and environmental monitoring to realize such environmental management. This section proposes measures for making improvement in the conduct of environmental management and monitoring in electric power projects in Indonesia, and appropriate countermeasures to be taken if problems are discovered. (a) Environmental management and monitoring of air and water pollution and improper waste disposal

Throughout the project cycle, environmental management to prevent and control harmful effects must be carried out on the following: direct impacts on the surrounding environment from the construction and operation of electric power facilities. This has to be done even after the end of the development project as long as the impacts are continuing. Indicators of pollutants and changes in the surrounding environment

The following is a table on indicators of pollutants and changes in the surrounding environment.

Air pollution Water pollution Sulfur oxides（SOx） Nitrogen oxides（NOx） Smoke dust Carbon dioxide （ CO2 ） , carbon

monoxide（CO） Ozone（O3） Control of coal ash (fly ash, etc.) Hydrogen sulfide (geothermal power

generation) Hydrocarbon Trace metal

Pollution indicators of dams and lakes: COD; water plants; zooplanktons; amount of floating garbage; change in surrounding environment (e.g. tourism, fish culture) Indicators of water quality of rivers and

downstream of discharged water: Organic pollution; BOD; COD; thermal discharged water (water temperature), others Leaching water from coal storage and coal ash

disposal facilities Waste water treatment and leakage of waste fuel,

oil content and others Pollution by soil runoff Arsenic and mercury (geothermal power

generation) Soil pollution Others

Bottom deposit in dams reservoirs (waste and rotten trees) Bottom deposit soil in rivers (zones

where flow has decreased) Pollution by leaching water Exposure of harmful earth and sand at

cut earth and filling Arsenic and mercury (geothermal

power generation)

Waste materials such as waste oil, chemicals, coal ash, and by-product plaster Noise, vibration Decrease in ground water level, subsidence of

ground Offensive foul odor Radio disturbance

21 Government decree on environmental impact assessment (Government decree No. 27, 1999), decree of the Environmental Management

Director on the guideline for environmental management and monitoring plans (Environmental Management Director decree No. 105, 1997), others

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Safety measures Communication and warning system for

water discharge Safety of gas pipelines Transportation safety on fuel shipping

route

Control of flammable and combustible fuel and materials

Maintenance and checking of high-voltage electric power lines, and observation on situation beneath the lines

Safety of steam pipes (geothermal power generation)

Process and standards of environmental management

Implementation of environmental management measures begins with (1) monitoring of the quantities of pollutants and the indicators above. Then the environmental management unit is to do the following: (2) evaluate the monitoring results; (3) implement appropriate measures if there are problems; and (4) take preventive measures to make sure the same problems do not occur. The unit is to (5) confirm improvements and try to identify new problems when the monitoring cycle begins again. Thus the environmental management cycle is complete.

Management standards are needed to evaluate monitoring results. The management unit should set standards of its own (internal standards) in areas without existing standards by law, ministry decrees, or internal regulations, regarding the concentration of pollutants and environmental indicators.

The environmental management unit should note that the purpose of setting environmental management standards is to take concrete measures for problems. Accordingly, the unit needs two types of management standards, one is the standards on the normal range of indicators to identify problems and the other is a manual (standard operation procedure) to implement counter measures. It is recommended that the unit should begin with setting internal standards in accordance with the table above. When the existing management standards are so strict as not to reflect the actual situation, the standards will need revisions to enable the concerned units and staffs to take practical and workable measures.

The following knowledge, experience and judgment are at work in the formulation of environmental management standards concerning the normal range of indicators and a manual for countermeasures.

(i) Knowledge and insights of experts (ii) Experience of engineers and expert staff in

the project sites (iii) Knowledge, insights, and techniques of

consultants (iv) Government deliberations and decisions (v) Opinions and judgement of stakeholders

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There is the concern that the purpose of environmental management and monitoring activities will be to simply satisfy the legal requirements. To avoid such a situation, PLN must utilize the experience of engineers and expert staff at the project sites. The best thing to do is to collect the views of stakeholders and make sure that the management standards meet their code of values once the outline of the standards are made with the experience of staff members at the sites taken into account. If the sector or an organization as a whole sets practical standards, then it will be possible to examine such matters as environmental management policies for ESCs in line with the standards at the project level in a stakeholder meeting. Human resources development and the implementation structure

To proceed with the process of environmental management standards and the environmental management process, human resources and an organizational structure with the following capacities and authorities are needed.

On formulation of environmental management standards: 1. Engage in detailed and technical discussions with experts and consultants on ESCs and

environmental management 2. Summarize the experiences of on-site engineers and staff members on environmental

management issues and measures, and reflect them in the formulation of standards 3. Explain the management standards to the administrative agencies and coordinate with their

requirements 4. Run meetings such as stakeholder meetings

As coordinator of the environmental management process: 1. With the support of professional experts, control monitoring, evaluation and study of measures

in light of environmental management standards and policies 2. Make sure that measures are taken for identified problems and check if they are proper 3. Investigate how to improve the system to prevent similar problems in the future 4. Confirm that matters at hand have improved as a result of the action or preventive measure

With regard to ESCs as a whole, the human resources and systems (the environmental management

unit) are also to consider in each PLN project the necessity and contents of ESCs --- whether they are SEA, EIA, or simplified assessment --- and control the study in each project.

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Recommendations The following is a summary of recommendations on environmental management and monitoring

of pollution and changes in the surrounding environment by electric power facilities. ① The management unit is to set environmental management standards on pollutants and

changes in the surrounding environment ② Environmental management standards include both defined normal ranges of indicators and

the standard operation manual to implement counter measures ③ The management unit is not to create unrealistic standards that impede the implementation of

measures. Accordingly, the formulation of standards is not to be completely delegated to a consultant; but it should integrate the experiences and insights of on-site staff members and professional experts.

④ The organization concerned is to establish a unit that can proceed with the comprehensive study plan on ESCs and the tasks ① to ③, coordinate all the works and assign several expert staff to these tasks. They are to be capable of explaining the standards and necessary environmental management works to the government and stakeholders and coordinate their views and support.

(b) Environmental issues due to development-induced human migration and regional environmental

management As often seen at hydroelectric power development sites, new access roads have brought people to

previously remote areas and their activities may invigorate the local economy. However, they may also cause the following problems.

Disorderly cultivation of undeveloped areas Unlawful logging of reserved forests and water source forests that conserve areas in a river

basin Illegal entry into and residence in protected areas Pollution of lakes and rivers Dumping of garbage from daily life (domestic waste)

These problems are not the direct results of hydroelectric power development, but are caused

indirectly by changes in the surrounding environment, i.e. increase of incoming population. It is recommended that the project should consult with local governments and support the formulation of a local environmental management plan as part of the strategic environmental assessment (SEA). Another option is to include in the environmental management plan attached to EIA the implementation plan for entry restrictions, a registration system for commercial activities, and environmental education on waste management.

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(c) Building database on environmental costs Environmental costs in each project in the electric power sector are to be recorded and organized. It

would make sense to create classifications and formats for common cost items in all electric power projects and put together a database. A database on environmental costs would enable the following: comparisons of environmental costs in different types of electric power facilities; distinction between environmental equipment costs included in initial investment and environmental management costs needed for operations; and more precise estimates of internal and external environmental costs.

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Chapter 7 Investment Promotion in Power Sector 7.1 Total Investment Necessary for the Power Sector Development in Sumatra

Table 7.1.1 shows the estimated investment amount necessary for the development of power generation and transmission facilities in Sumatra from 2006 to 2020. This table excludes the projects that have contracts and/or determined investment. The estimates also exclude investment in power distribution.

Table 7.1.1 Total Investment Necessary for Development of Power Generation and Transmission Facilities in Sumatra during 2006-2020

(Unit: US$ million)

Total Breakdown Total Breakdown Total Breakdown Total Breakdown

PLN (including 221 (1) 0 1,561 (1) 0 585 (1) 0 2,367 (1) 0 ODA) (2) 113 (2) 0 (2) 0 (2) 113

(3) 0 (3) 0 (3) 0 (3) 0(4) 0 (4) 896 (4) 560 (4) 1,456(5) 0 (5) 0 (5) 0 (5) 0(6) 108 (6) 665 (6) 25 (6) 798

IPP 845 (1) 500 963 (1) 700 400 (1) 400 2,208 (1) 1,600(2) 0 (2) 0 (2) 0 (2) 0(3) 90 (3) 0 (3) 0 (3) 90(4) 0 (4) 263 (4) 0 (4) 263(5) 255 (5) 0 (5) 0 (5) 255(6) 0 (6) 0 (6) 0 (6) 0

Unknown 0 (1) 0 0 (1) 0 1,060 (1) 700 1,060 (1) 700(2) 0 (2) 0 (2) 0 (2) 0(3) 0 (3) 0 (3) 360 (3) 360(4) 0 (4) 0 (4) 0 (4) 0(5) 0 (5) 0 (5) 0 (5) 0(6) 0 (6) 0 (6) 0 (6) 0

Total 1,066 (1) 500 2,524 (1) 700 2,045 (1) 1,100 5,635 (1) 2,300(2) 113 (2) 0 (2) 0 (2) 113(3) 90 (3) 0 (3) 360 (3) 450(4) 0 (4) 1,159 (4) 560 (4) 1,719(5) 255 (5) 0 (5) 0 (5) 255(6) 108 (6) 665 (6) 25 (6) 798

① 2006-2010 ② 2011-2015 ③ 2016-2020 ①-③ 2006-2020FinancingSources

Notes: (1) Coal-fired, (2) Gas turbine, (3) Combined-cycle, (4) Hydropower, (5) Geothermal, and (6)

Transmission/substation.

Source: Estimated by JICA Study Team

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According to Table 7.1.1, the total investment cost in Sumatra during 2006-2020 is estimated at US$5.635 billion, of which US$2.3 billion (40.8%) is for coal-fired power plants, US$113 million (2.0%) for gas turbine power plants, US$450 million (8.0%) for combined-cycle power plants, US$1.719 billion (30.5 %) for hydraulic power plants, US$255 million (4.5%) for geothermal power plants, and US$798 million (14.2%) for main transmission and substation facilities. In light of the background and characteristics of each investment project, it is expected that, of US$5.6 billion, US$2.36 billion (42.0%) is financed by PLN including its own funds, the Indonesian government budget and ODA (official development assistance) and US$2.21 billion (39.2%) is funded by IPP. The financial sources of the remaining US$1.06 billion (18.8%) are not clarified.

The Study Team reviewed the financial situation of PLN from 1966 to confirm the ability of

self-financing for the investment shown in Table 7.1.1. Since 1998, PLN’s operational cost has never been lower than the operational income causing a chronic deficit in their operations as shown in Figure 7.1.1. In fact, this means that PLN has covered almost all of its investment costs through loans since 1998. This is also explained by Figure 7.1.2, which shows that the increase of total fixed assets is followed by an increase in liabilities.

0

10

20

30

40

50

60

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

trillio

n ru

piah

)

Operational Income Operational Cost

Figure 7.1.1 PLN Operational Income vs. Operational Cost

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Reliance on Liability

0

50

100

150

200

250

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

Trilli

on R

upia

h

EquityTotal Fixed AssetTotal Liability

Asset Revaluationand Debt-Equity

Figure 7.1.2 Reliance on Liability

This chronic deficit was caused by an expansion of US$-denominated expenses on the heels of a

decline in the value of the rupiah, increases in fuel cost and expenditures for electricity purchases from IPP, a rise in interest payments and others. Though the Indonesian government and PLN have taken such measures as 1) revision of the electricity purchase contract with IPP, 2) debt-equity swap, 3) phased raise of tariff, 4) reevaluation of assets, and 5) financial restructuring for PLN in order to improve this situation, the financial situation is not going to improve immediately unless PLN changes its business structure in terms of exchange risks. Consequently, it would appear that PLN will be dependent on loans for the duration, however, it is unrealistic to rely on loans for almost all of its investments and so the power sector in Sumatra needs IPPs to realize the power development.

PLN seems to continuously rely on ODA to finance most of the investment projects, in consideration of its financial position. In the second period (2011-2015), the construction of several hydraulic power plants and large-scale expansion of transmission/substation facilities are scheduled to be undertaken. An intensive financing due to this capital demand during 2011-2015 requires Indonesia not only to ensure ODA but also to expand PLN’s own financial resources through the improvement of its financial situation.

After 2016, financing sources for many coal-fired power plants and combined-cycle power plants are not decided yet. These power development projects will have to depend on IPP investment to a large extent. This requires the immediate improvement of investment climate. The repeal of Law 20/2002 may possibly put the brakes on IPP financing that would otherwise cover a large part of the total investment in the Sumatra’s power sector up to 2020.

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7.2 Recommendations for Investment Promotion in Power Sector 7.2.1 Recommendations: Indonesian Government

To attract electric power investment with private sector participation, the Indonesia government is required to tackle the following challenges that the economy in general and the power sector in particular are facing. (1) Strong government commitment and support

Without a clear expression of the government’s commitment and support to IPP business, private investors will hesitate to invest in long-term and large-scale projects in Indonesia. While the Indonesian government has shown its willingness to attract electric power investors, it has not demonstrated its strong commitment and support to IPP investment. This has discouraged electric power investment with private sector participation. Resumption of the issuance of letter of guarantees (L/G) or support letters, one of the obvious and substantial commitments from the government, may stimulate potential investors to come into the Indonesian electricity market. In addition, the government can indicate its strong commitment and support to IPPs by, for example, accelerating the development of a legal framework, and promoting the institutional and human development necessary for the effective receiving and utilization of IPP investment. Of course, investors do not want government interference but hope for adequate commitment and support from the government. (2) Availability and enforceability of laws and contracts

A clear and enforceable legal framework favorable to foreign private investment is one of the top priorities for investors. Based on reliable rules, they need to make investment decisions at present and also formulate the business strategy for the future Indonesian market. (i) Establishment of new investment law

The establishment of the New Investment Law has been far behind the original schedule of December 2003, which was established in the Economic Policy Package Pre and Post-IMF (White Paper) announced in September 2003. The delay has accelerated the exodus of foreign investors from Indonesia. This affects not only the manufacturing sector, but also the power sector. It is necessary to promptly enact the New Investment Law to create a favorable investment environment. (ii) Development of New Legal Framework after Repeal of New Electricity Law

It is essential to prepare a new legal framework (including decrees and regulations) in place of the New Electricity Law (Law No. 20 of 2002). Under the framework, important issues such as the role of PLN in electricity business, the formulation of joint venture projects between PLN and IPPs, the handling of IPP investment (e.g. tax on IPPs), and the relationships between power development and decentralization should be clarified and stipulated.

7-5

(iii) Reconsideration of Sector Reform and Design of Market Liberalization The New Electricity Law (Law No. 20 of 2002) presented a blueprint for sector reform based on

market mechanisms. However, while many foreign investors and parties concerned have understood the basic direction of this vision, they have had anxieties about the reality of such ambitious attempts at sector reform and market liberalization including a multi-seller/multi-buyer system, IPP-oriented power development and unbundling of vertically integrated structures. Along with the cancellation of Law 20/2002, it has become necessary to take into account several factors such as growing power demand, power supply shortages, industrial structures and income levels of consumers and to indicate revised plans for sector reform and market design with adequate speed, reasonable sequence and feasible targets. (3) Ensuring adequate cash flows

Reasonable tariff levels and collection discipline are of the highest priorities for private investors. IPPs are not willing to consider making investments in Indonesia unless these conditions are satisfied. In connection with these issues, firmly adhering to power purchase agreement (PPA) is important to ensure adequate cash flows. The introduction of an automatic tariff adjustment (ATA) system should also be reconsidered in this context. In addition, the Indonesian government is required to attempt to reduce and eliminate disparities between power sales prices and production costs. However, at the same time, the government has to carefully take into account the income levels of power consumers (particularly low-income earners) in each region, when it sets the prices of electricity. (4) Improvement of responsiveness to investor needs

International investors tend to consider the administrative efficiency of a host government as one of the key factors in their decisions to invest in a country. It is necessary for the Indonesian government to avoid being unresponsive to the investors’ needs and time frames. 7.2.2 Recommendations: External Parties (1) Promotion of investment coordination (i) Coordination between ODA and non-ODA projects

ODA (official development assistance) can trigger private investment. Through the utilization of this ODA’s pump-priming effect, it is possible to attract IPP projects. For example, if ODA builds public-natured or unprofitable infrastructure such as input fuel facilities, roads and ports for power facilities, IPPs will be more likely to consider electric power investments, because they can avoid such infrastructure development necessary for power generation plants and thus reduce their investment costs. Positive coordination between ODA and non-ODA projects can promote IPP investment.

7-6

(ii) Establishment of investment coordination meeting Currently, JBIC (Japan Bank for International Cooperation), in collaboration with the World Bank

and ADB, organizes a stakeholder consultation meeting (SCM), whose participants are from the Indonesian central government, JBIC, the World Bank, ADB, potential IPPs, banks/financial companies, NEXI (Nippon Export and Investment Insurance) and others. It is important to exchange and acquire information on electricity investment in Indonesia among stakeholders. This Study proposes the following institutional arrangements for investment coordination and promotion in the power sector. For this coordination meeting, the Study takes advantage of the existing SCM with some minor adjustments in terms of regional aspects.

Under this structure, the Indonesian central government and PLN in collaboration with local governments and local parties concerned formulate REPISTRAT (Regional Power-sector Investment Strategy) in each region (i.e. Sumatra, Java, Kalimantan and Sulawesi) for the realization of the power development plan based on RUKN (① in Figure 7.2.1). REPISTRAT proposes various kinds of investment projects in the form of PSP (Private Sector Participation)-type projects and traditional GOVEX (Government Expenditure)-type projects, which range from the construction of new power generation facilities to the maintenance, repair and transfer of existing facilities.

The central government, PLN and local governments jointly hold PICOM (Power-sector Investment Coordination Meetings) on a periodic basis and invite IPPs as main players of PSP, domestic and foreign financial institutions, ECA (Export Credit Agencies), potential contractors, international development institutions such as the World Bank and ADB, and bilateral aid organizations such as JICA and JBIC (② in Figure 7.2.1). The establishment of PICOM is aimed at forming a close relationship with those participants and selling them investment projects proposed in REPISTRAT as well as RUKN.

7-7

Figure 7.2.1 Institutional Arrangement for Investment Coordination and Promotion in the Indonesian Power Sector (Proposal)

(2) Promotion of flexible donor/financial support activities

On-lending, which transfers from the first and original lending between a donor agency and a central government to the second lending between the central government and a local government, can help a country distribute money for electric power investment at the local level. These kinds of flexible support activities by donor/financial agencies are useful in financing local electric power projects. (3) Promotion of institutional and human resource development

Through the provision of technical cooperation and/or program loans, donor agencies can assist the development of institutional and financial capabilities of PLN. This support improves the creditworthiness of PLN, which may lead to the facilitation of investment in the Indonesian power sector. Similarly, donor agencies can also help local governments promote human resource development necessary to handle IPP investment at the local level.

②REPISTRAT (Regional Power-sector Investment Strategy)

Local Governments

North Sumatra (Provincial governments, Kabupaten’s/Kota’s governments, local PLNs, universities, NGOs, etc.)

South Sumatra West Sumatra

Lampung

PSP Projects

GOVEXProjects

REPISTRAT for Sumatra

REPISTRAT for Java

REPISTRAT for Kalimantan REPISTRAT for Sulawesi

Central Government

(MEMR, PLN, MOF, MENKO, BAPPENAS, etc.)

RUKN (National Electricity Plan)

PICOM (Power-sector Investment Coordination Meetings)

Organizers: Indonesian central/local governments, PLN Participants: IPPs, Financial Institutions, ECA, potentialcontractors, International/Foreign Aid Agencies,

①

①

7-8

7.2.3 Inventive Investment Models (1) Establishment of risk reduction models for investment in PLN

As an investment model, this study proposes the establishment of a PLN-funded SPC (Special Purpose Company) which has sales contracts with trusted electricity buyers. This formation may reduce the risks of PLN defaulting and improve the credibility of securities investment in it (or other PLN-related firms). (2) Investment in power generation for non-PLN market

The Study considers a possibility of investment in an electricity generation business for the non-PLN market. In addition to the existing IPP investment exclusive to the PLN market, a new investment model in which a large part of the produced electricity is supplied directly to foreign-affiliated industrial estates and the remaining part to the PLN is also feasible. This approach is a useful way to attract private investment in the power sector. In fact, North Sumatra has adopted and formulated this model for its industrial estate (KIM, Medan Industrial Estate). As of August 2004, four domestic IPPs have expressed their interests in the KIM coal-fired power generation project. (3) Attraction of investment through CDM

CDM (Clean Development Mechanism) for the reduction of GHG (Green House Gases) under UNFCCC (UN Framework Convention on Climate Change) can be used as one of the effective incentives to attract foreign investment in the power generation business. (4) Formulation of Public-Private Partnership Projects

In the case where IPP formulates a joint project with a public company (e.g. PLN), the project can avoid the process of bidding. This is the advantage of a Public-Private Partnership (PPP) project. (5) Establishment of fund by donor agencies

Donor agencies (e.g. JBIC) can promote private investment in the power sector, by establishing a special fund for IPP business. JBIC has such experience in the establishment of the Global Asian Clean Energy Fund. 7.2.4 Special Considerations for Investment Promotion in Sumatra

A major attempt to attract IPPs to Sumatra is beneficial and important. The improvement of fundamental conditions at the national level favorable to private investment as described above is a necessary requirement for the facilitation of IPP projects in Sumatra. Supplementary infrastructure projects in Sumatra through ODA may encourage private investors to make electric power investments in Sumatra. PICOM (Power-sector Investment Coordination Meetings) may be effective in promoting IPP investment in Sumatra. However, in consideration of several factors such as the repeal of the New

7-9

Electricity Law (Law No. 20 of 2002), growing power demand, power supply shortages, industrial structure, industrial location and income levels of power consumers, the development of electric power facilities in Sumatra still needs to rely on government budget including ODA financing to a certain extent. Attracting ODA funds in Sumatra and expanding PLN’s own investment funds through, for example, a review of the levels of electric power charges and reconsideration of electric rate structure, are required.

8-1

Chapter 8 Future Direction of Assistance for the Realization of the Optimal Electric Power Development in Sumatra

The following proposals regarding the future assistance for the realization of the optimal electric

power development in Sumatra are set out in this chapter.

(1) Generation development plan (2) Formulating a system operation plan (3) Human resource development (4) Interconnection of the Sumatra system with other systems

8.1 Assistance for the Generation Development Plan

The Study team conducted a case study involving the ESC weighted Case, which focuses on the impact of generation development on the environment and society as well as the economic development and operation of the power system, in recognition of the importance and necessity of environmental and social considerations for the development and operation of the power system and proposed the optimal generation development plan up until 2020 with environmental and social considerations. In addition, the Study team allocated the required development capacities to each region so that each region will keep its

demand-supply balance from the viewpoint of reducing the cost for transmission development and the

transmission losses in selecting candidate sites for development. As a result, the coal-fired steam turbine plants and hydropower plants are planned for the North Sumatra system, and the gas-fired combined cycle power plants for the South-West Sumatra system (See Table 4.7.1).

Especially during the period between 2012 and 2018, the development of many hydropower projects will be planned for economical expansion and operation of the system. Consequently, to achieve the economic generation development, it is desirable to support the implementation of hydropower projects steadily for which feasibility studies have already been conducted and to upgrade the study phase of the projects for which pre-feasibility studies or reconnaissance studies have already been conducted.

The Study team identified that a severe shortage in supply capacity will occur in Riau province in 2008 and in Jambi and Lampung provinces in 201522. Therefore, gas-fired combined cycle power plants will be planned in these provinces. Especially for Riau province which will have severe demand-supply situation in a few years, necessary assistance will be expected for developing gas-fired combined cycle power plants.

22 See Table 5.10.4 in Final Report (Volume 1).

8-2

After installation of the Renun hydropower plant and Labuhan Angin coal-fired thermal power plant to the North system in 2005 and in 2007, respectively, the condition of power supply in the North system will be improved. However, the condition of power supply will become extremely severe in the Aceh regional system because it is very far from these new power plants. To improve such situation in the Aceh system, there is an urgent assistance to develop oil-fired gas turbine power units for the system. Incidentally, since the present situation of the Aceh system is very complicated because of generation shortage caused by demand increase, overload of the existing 150kV transmission lines with a one-circuit fault, transient and steady-state stability problems and others, it is desirable to improve the protection and control system or to install an SVC (Static Var Compensator) to maintain the system stability for the gas turbines at Banda Aceh as short-term measures and to construct 275kV transmission lines from Medan to Banda Aceh in line with the power development in Aceh to drastically solve the stability problem as a middle to long-term measure. Therefore, coordination between the generation and transmission development plans is necessary when assisting the Aceh system power development 8.2 Assistance for Formulating a System Operation Plan

According to PLN, an interconnection between the North Sumatra system and the West Sumatra system is planned for 200923, which is the earliest timing determined by the construction schedule. With the completion of the North-West Sumatra interconnection, all the main systems in Sumatra will be interconnected and will be operated as one system, except some isolated small systems. Therefore, the assignment of daily generator operation planning and frequency control should be discussed as it was done individually by Palembang, Padang and Medan UPB. In addition, the replacement of the SCADA system and the communication system will be also needed according to the change of the Sumatra system.

Therefore, it is necessary for the Sumatra system to formulate a master plan on its system operation

for addressing the issues on congestion of PLC including the introduction of OPGW and introducing the coordination of the communication system with the SCADA system and the protection relay system. Assistance for this master plan is needed. 8.3 Support for Human Resource Development

The Study team transferred technologies on power demand forecasting methodology (Simple E), power development planning (WASP-IV) and power system analysis (PSS/E) through the workshops (Padang, Palembang and Medan) and the technical seminars (Palembang) to the provincial level staffs related to power development in Sumatra. In light of the stream of decentralization in Indonesia, such

23 The Study team identified that the earlier both systems interconnects, the more benefit is expected (See Section 4.4.3).

8-3

kind of capacity building activities should be expanded into the entire Indonesia. MEMR and PLN have recognized the importance of the capacity building for the provincial levels and their efforts are in progress now.

Capacity building on ESC or power sector investment promotion is, however, less enough. Therefore, the power sector in Sumatra needs supports for strengthening human resources and organizational structure to proceed with the process of environmental management standards and the environmental management and for promoting human resource development necessary to handle IPP investment at the local level. 8.4 Support for Interconnection of the Sumatra System with other Systems

The interconnection plan of the Sumatra system with the Java system or the Malaysia system has not taken shape at present instead of the completion of the technical studies on the interconnections. However, more and detailed studies such as a feasibility study will be needed based on the recent information for realizing the plan because the Sumatra system is changing.

Regarding the interconnection with the Malaysia system, especially, a comprehensive discussion including organizational and institutional arrangements as well as technical aspects will be needed because the project needs governmental coordination and new operational codes for power exchange or trade. In this connection, Japan already has the established schemes for power exchange or trade between regional utilities and also has the technologies for power interconnection with the HVDC. Therefore, assistance with these experiences for the realization of the interconnection will be useful.

Appendix I

Appendix I

Sim

ulat

ion

Res

ults

(NA

D)

Appendix I

Sim

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Res

ults

(Nor

th S

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ra)

Appendix I

Sim

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Res

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(Ria

u)

Appendix I

Sim

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Res

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(Wes

t Sum

atra

)

Appendix I

Sim

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ion

Res

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(Jam

bi)

Appendix I

Sim

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Res

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(Sou

th S

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Appendix I

Sim

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Res

ults

(Ben

gkul

u)

Appendix I

Sim

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Res

ults

(Lam

pung

)

Appendix II

Appendix II

Power Plants in North Sumatra System (as of April 2004)

PLTAPLTMH PLTD PLTG PLTU PLTGU Total

Belawan (PLTU) 1 PLTU MFO 65.000 60.000 5.000 7.7% 1984 202 PLTU MFO 65.000 50.000 15.000 23.1% 1984 203 PLTU MFO/GAS 65.000 45.000 20.000 30.8% 1989 154 PLTU MFO/GAS 65.000 45.000 20.000 30.8% 1989 15

Belawan (PLTGU) 1-1 PLTG GAS/HSD 117.500 108.000 9.500 8.1% 1993 111-2 PLTG GAS/HSD 128.800 128.000 0.800 0.6% 1988 161-0 PLTU - 149.000 127.000 22.000 14.8% 1995 92-1 PLTG GAS/HSD 130.000 122.000 8.000 6.2% 1995 92-2 PLTG GAS/HSD 130.000 125.000 5.000 3.8% 1994 102-0 PLTU - 162.580 132.000 30.580 18.8% 1994 10

Paya Pasir 1 PLTG HSD 14.466 0.000 14.466 100.0% 1976 282 PLTG HSD 14.466 12.000 2.466 17.0% 1976 283 PLTG HSD 20.100 15.000 5.100 25.4% 1978 264 PLTG HSD 20.100 0.000 20.100 100.0% 1978 265 PLTG HSD 21.350 16.000 5.350 25.1% 1983 21

Glugur 1 PLTG HSD 19.850 15.000 4.850 24.4% 1975 292 PLTG HSD 12.800 0.000 12.800 100.0% 1967 37

Titi Kuning 1 PLTD HSD 4.141 3.600 0.541 13.1% 1976 282 PLTD HSD 4.141 3.600 0.541 13.1% 1976 283 PLTD HSD 4.141 3.600 0.541 13.1% 1976 284 PLTD HSD 4.141 3.600 0.541 13.1% 1976 285 PLTD HSD 4.141 3.600 0.541 13.1% 1976 286 PLTD HSD 4.141 0.000 4.141 100.0% 1976 28

Batang Gadis 1 PLTMH - 0.450 0.450 0.000 0.0% 1994 102 PLTMH - 0.450 0.450 0.000 0.0% 1994 10

Aek Raisan 1 PLTMH - 0.750 0.750 0.000 0.0% 1989 152 PLTMH - 0.750 0.750 0.000 0.0% 1987 17

Aek Silang 0.750 0.750 1 PLTMH - 0.750 0.750 0.000 0.0% 1988 16Aek Sibundong 0.750 0.750 1 PLTMH - 0.750 0.750 0.000 0.0% 1987 17Tonduhan 1 PLTMH - 0.200 0.200 0.000 0.0% 1987 17

2 PLTMH - 0.200 0.200 0.000 0.0% 1988 16Boho 0.200 0.200 1 PLTMH - 0.200 0.200 0.000 0.0% 1989 15Kombin-I 1 PLTMH - 0.750 0.750 0.000 0.0% 1987 17

2 PLTMH - 0.750 0.750 0.000 0.0% 1988 16Kombin-II 1 PLTMH - 0.750 0.750 0.000 0.0% 1987 17

2 PLTMH - 0.750 0.750 0.000 0.0% 1988 16Lueng Bata (Rental) 1 PLTD HSD 1.000 1.000 0.000 0.0% 1978 26

2 PLTD HSD 1.000 1.000 0.000 0.0% 1978 263 PLTD HSD 4.040 4.040 0.000 0.0% 1981 234 PLTD HSD 2.296 2.296 0.000 0.0% 1984 205 PLTD HSD 3.280 3.280 0.000 0.0% 1985 196 PLTD HSD 6.368 6.368 0.000 0.0% 1986 187 PLTD HSD 6.368 6.368 0.000 0.0% 1986 188 PLTD HSD 6.368 6.368 0.000 0.0% 1986 189 PLTD HSD 6.368 6.368 0.000 0.0% 1986 18

10 PLTD HSD 6.368 6.368 0.000 0.0% 1986 1811 PLTD HSD 6.368 6.368 0.000 0.0% 1998 6

Sipansihaporas 17.000 17.000 1 PLTA - 17.000 17.000 0.000 0.0% 2002 2Inalm 45.000 45.000 1 PLTA - 45.000 45.000 0.000 0.0% 1982 22

69.500 74.670 123.132 260.000 817.880 1,345.182 49 1,345.182 1,137.324 207.858 Ave. Age= 14.45.2% 5.6% 9.2% 19.3% 60.8% 100.0% 100.0% 84.5% 15.5%

North SumatraSystem Total

0.4000.400

0.900

1.5001.500

1.500

0.900

817.880

32.650

90.482

260.000

49.824

1.500

24.846

1.500

49.824

260.000

90.482

817.880

1.500

24.846

32.650


Plant Name UnitNo.

PlantType

C/A(%)

OperatingYear

Age in2004

(years)

FuelType

InstalledCapacity

(MW)A

DependableCapacity

(MW)B

CapacityDerating

(MW)C=A-B

Power Plants in West Sumatra System (as of April 2004)

PLTA PLTD PLTG PLTU Total

Ombilin 1 PLTU Coal 100.000 80.000 20.000 20.0% 1996 82 PLTU Coal 100.000 53.000 47.000 47.0% 1996 8

Pauh Limo 1 PLTG Gas 21.350 0.000 21.350 100.0% 1983 212 PLTG Gas 21.350 20.000 1.350 6.3% 1983 213 PLTG Gas 21.350 17.000 4.350 20.4% 1995 9

Maningau 1 PLTA - 17.000 17.000 0.000 0.0% 1983 21 (Reservoir Type) 2 PLTA - 17.000 17.000 0.000 0.0% 1983 21 (Natural Lake) 3 PLTA - 17.000 17.000 0.000 0.0% 1983 21

4 PLTA - 17.000 17.000 0.000 0.0% 1983 21Singkarak 1 PLTA - 43.750 43.750 0.000 0.0% 1998 6 (Reservoir Type) 2 PLTA - 43.750 43.750 0.000 0.0% 1998 6 (Natural Lake) 3 PLTA - 43.750 43.750 0.000 0.0% 1998 6

4 PLTA - 43.750 43.750 0.000 0.0% 1998 6Kotopanjang 1 PLTA - 38.000 38.000 0.000 0.0% 1998 6 (Reservoir Type) 2 PLTA - 38.000 38.000 0.000 0.0% 1998 6

3 PLTA - 38.000 38.000 0.000 0.0% 1998 6Bukit Agam 1 PLTA - 3.500 3.500 0.000 0.0% 1976 28 (Run-off-River) 2 PLTA - 3.500 3.500 0.000 0.0% 1976 28

3 PLTA - 3.500 3.500 0.000 0.0% 1976 28Teluk Lembu 1 PLTG Gas 21.600 16.000 5.600 25.9% 1974 30

2 PLTG Gas 21.600 0.000 21.600 100.0% 1976 28B. Besar (Mak 1) 5.100 5.100 1 PLTD HSD 1.500 1.500 0.000 0.0% - - (Mak 2) 2 PLTD HSD 1.800 1.800 0.000 0.0% - - (Mak 3) 3 PLTD HSD 1.800 1.800 0.000 0.0% - -

367.500 5.100 107.250 200.000 679.850 24 679.850 558.600 121.250 Ave. Age= 11.054.1% 0.8% 15.8% 29.4% 100.0% 100.0% 82.2% 17.8%

43.200

114.000

10.500

43.200

West Sumatra SystemTotal

175.000

68.000

10.500

68.000

175.000


114.000

200.000

64.050

200.000

64.050

OperatingYear

Age in2004

(years)Plant Name Unit

No.PlantType

FuelType

InstalledCapacity

(MW)A

DependableCapacity

(MW)B

CapacityDerating

(MW)C=A-B

C/A(%)

Appendix II

Power Plants in South Sumatra System (as of April 2004)

Appendix III

Appendix III

List of Retirement and Relocation Generation Units for Simulation

System Year Unit Type Unit Name Installed Capacity Fuel Remarks

North 2007 Diesel Mesin Sewa #1-#12 7.700 MW HSD Rental Unit Sumatra 2009 Steam Turbine Belawan #1-#4 260.000 MW MFO High Generation Cost System 2009 Gas Turbine Paya Pasir #1-#4 69.966 MW HSD Aging Unit 2009 Gas Turbine Glugur #1,2 32.650 MW HSD Aging Unit 2009 Diesel Titi Kuning #1-#6 24.850 MW HSD High Generation Cost 2009 Diesel Lueng bata #1-#11 49.830 MW HSD High Generation Cost South-West 2005 Diesel Sukame Rindu #4 1.100 MW HSD Transferring to WilayahSumatra 2007 Diesel Teluk Lembu 6.370 MW HSD High Generation Cost System 2007 Diesel Bagan Besar #1-#6 9.900 MW HSD High Generation Cost 2007 Diesel Sungai Juaro #1,2 25.200 MW HSD High Generation Cost 2007 Diesel Kesang #5,7 5.000 MW HSD High Generation Cost 2007 Diesel Payo Se'lincah #1,2,4,5,6,7 26.090 MW HSD High Generation Cost 2007 Diesel Sukame Rindu #5,6,7 15.650 MW HSD High Generation Cost 2007 Diesel Pulau Baai #1-5 21.580 MW HSD High Generation Cost 2007 Diesel Tanjung Enim #1,2 12.740 MW HSD High Generation Cost 2007 Diesel Tarahan #1,4,5,7 33.370 MW HSD High Generation Cost 2007 Diesel Teluk Betung #3,4,5,8,10 14.200 MW HSD High Generation Cost 2007 Diesel Metro #3,6,9 3.750 MW HSD High Generation Cost 2007 Diesel Talang Padang #1-#8 5.390 MW HSD High Generation Cost 2007 Diesel Tegineneng #1-#3 28.200 MW HSD High Generation Cost

Appendix III

Output of WASP-IV Simulation (Sensitivity Analysis on Fuel Price, Low Demand Case)

Output of WASP-IV Simulation (Sensitivity Analysis on Supply Reliability, High Demand Case)

( Unit : MW )Peak

Demand(MW)

2003 2,111.82004 2,286.82005 2,454.02006 2,671.82007 2,911.42008 3,164.42009 3,461.62010 3,760.42011 4,064.72012 4,400.22013 4,752.52014 5,056.32015 5,373.72016 5,707.22017 6,058.92018 6,431.02019 6,825.52020 7,244.0

*1 : Substitution unit of coal-fired thermal power plant taking into consideration the lack of supply capacity in Pekanbaru in the near future.*2 : Asahan I*3 : Run-of-River Type 100MW*4 : Merangin*5 : Reservoir Type 100MW x 2 units*6 : Reservoir Type 400MW*7 : Reservoir Type 100MW

500150 400

400

300

150*1

6

2,300

Year

300

250

300

400200

200

Number of Units

23 5

Capacity (MW) Total 4,530 MW250

Total 4,530 MW2,900 250 150 1,2301,230 Developed

5

750

150*1

150

300

Total 39 units

400*6

200*5

200

180*2

400

200*5450*3*4

300

400400*6

300400

450*3*4

180*2

100300

100

400

29 5 1Total 41 units

6

180*2

450*3*4

100*7

100*7

400400*6

50029 5 1 6

2,900 250 150 1,230Total 4,530 MW

250

180*2

200*5

400

Total 41 units

200 150 200 150

450*3*4

100*7

300 100 100*7

100300 200 15050

400*6

500

300 400*6

150 300 150

22 6 5 6 17 5 9 6

1,700 250 1,350 1,230Total 4,530 MW

Least-cost Case Gas Price Increase Case : G1 Gas Price Increase Case : G2 Coal Price Increase Case : C1 Coal Price Increase Case : C2

Total 39 units Total 37 units2,200 300

Total 4,480 MW750 1,230

300 150300

100400

100

250

200

250150*1

100400

100

100

150*1

200 150 150*1

250

100200 150

180*2

450*3*4

150150

ST GT CC Hydro ST GT CC Hydro ST GT CC Hydro ST GT CC HydroHydro ST GT CC

( Unit : MW)Peak

Demand(MW)

2003 2,111.82004 2,286.82005 2,454.02006 2,671.82007 2,911.42008 3,164.42009 3,461.62010 3,760.42011 4,064.72012 4,400.22013 4,752.52014 5,056.32015 5,373.72016 5,707.22017 6,058.92018 6,431.02019 6,825.52020 7,244.0


180*2

450*3*4

300100300

150*1250

150*1

100

250400

Total 4,480 MW

Total 39 units2,400 250 600 1,230

300 15024 5 4 6

400*6

300 150

200 150

300400

200*5200

23 5 5

150

Total 39 units6

300

200 150

100300

200*5

400*6

450*3*4 180*2 180*2

200*5 450*3*4

400*6

150*1

Total 44 units

400

500



Number of Units

29

400

400

300

100

100200

6

2,900

500

8 1

150

200300

300400

400

Year LOLP 1day / year Case LOLP 3days / year Case LOLP 5days / year Case(Least-cost Case)ST GT CC Hydro ST GT CC HydroGT CC Hydro ST

Appendix III

Output of WASP-IV Simulation (Sensitivity Analysis on Discount Rate, High Demand Case)

Output of WASP-IV Simulation (Sensitivity Analysis on ENS Cost, High Demand Case)

( Unit : MW )Peak

Demand(MW)

2003 2,111.82004 2,286.82005 2,454.02006 2,671.82007 2,911.42008 3,164.42009 3,461.62010 3,760.42011 4,064.72012 4,400.22013 4,752.52014 5,056.32015 5,373.72016 5,707.22017 6,058.92018 6,431.02019 6,825.52020 7,244.0

*1 : Substitution unit of coal-fired thermal power plant taking into consideration the lack of supply capacity in Pekanbaru in the near future.*2 : Asahan I*3 : Run-of-River Type 100MW*4 : Merangin*5 : Reservoir Type 100MW x 2 units*6 : Reservoir Type 400MW*7 : Reservoir Type 100MW

Total 4,530 MW

1 6Total 41 units

2,900 250 150 1,230

400400400400

600*5*6

350*4280*2*3

300100400

150*1250

ST GT CC Hydro

50

300

180*2

100200 150

150*1250

100

150*1

400

300

100400

250150*1

100

250

100

100400

HydroHydro ST GT CCHydro ST GT CCHydro ST GT CC

Total 4,530 MW Total 4,480 MW

Discount Rate 12% Case

ST GT CC Hydro ST GT CC

Total 39 units Total 39 units2,300 250 750 1,230 2,200 300 750 1,230

15023 5 5 6 22 6 5 6200 300 300

150300 150 400*6

400*6 300100 150 100*7 100 200*5

100*7 400300 300

450*3*4 450*3*4

300 200 150

Total 4,530 MW

250

180*2

300

Total 39 units2,300 250 750 1,230

200 30023 5 5 6

400*6

150

200 150

450*3*4

200*5

180*2

23 5 5Total 39 units

6300

200 150150

300

100

100

180*2

300

300400

400*6

300

180*2

400

200*5450*3*4

300

400*6

5

750

150*1

300

Total 39 units



200 Number of Units

23 550029 5 6

2,300

Year

100

250

300

400

150*1

400

300200*5450*3*4

Discount Rate 3% Case

200300 300

400

Discount Rate 15% Case Discount Rate 18% CaseDiscount Rate 6% Case Discount Rate 9% Case (Least-cost Case)

( Unit : MW )Peak

Demand(MW)

2003 2,111.82004 2,286.82005 2,454.02006 2,671.82007 2,911.42008 3,164.42009 3,461.62010 3,760.42011 4,064.72012 4,400.22013 4,752.52014 5,056.32015 5,373.72016 5,707.22017 6,058.92018 6,431.02019 6,825.52020 7,244.0


200150 300

300400

400

300

150*1

6

2,300

Year

300

250

300

400200

200 Number of Units

23 5



5

750

150*1

150

300

Total 39 units

400*6 400*6

180*2

200*5450*3*4450*3*4

180*2

100300

200*5

Total 39 units6

300

200 150

23 5 5

150

200*5100300400200 150

400*6

300 150

250 750 1,230

200 30023 5 5 6

Total 4,530 MW

Medium ENS Cost Case

ST GT CC Hydro ST GT

Total 39 units2,300

CC Hydro ST GT CC Hydro

100400

100

250

100

150*1250

100400

180*2

450*3*4

300

High ENS Cost Case0.8 US$/kWh0.5 US$/kWh (Least-cost Case)

Low ENS Cost Case0.2 US$/kWh

Appendix III

Transition of Installed Capacity (Proposed Case)

Transition of Component Ratio of Installed Capacity (Proposed Case)

Transition of Annual Generation (Proposed Case)

(Low Demand Case) (High Demand Case)



0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020Year

Inst

alle

d C

apac

ity (

MW

)

Special SupplyDieselGas TurbineCombined CycleSteam TurbineGeothermalHydropowerPeak Demand

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020Year

Inst

alle

d C

apac

ity (

MW

)

Special SupplyDieselGas TurbineCombined CycleSteam TurbineGeothermalHydropowerPeak Demand

18.1 21.1

33.3 33.3

24.0

22.7

23.333.026.3

29.7

23.0

17.820.1

17.013.1 10.29.4

6.8

5.3 4.1

2.11.6

2.72.1

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2004 2010 2015 2020Year

Com

pone

nt R

atio

of I

nsta

lled

Cap

acity

(%

)

Special SupplyDieselGas TurbineCombined CycleSteam TurbineGeothermalHydropower

18.1 18.6

29.3 26.7

24.0

30.8

33.7 38.4

26.3

26.1

19.121.520.1

16.011.7 8.89.4

6.0

4.43.3

1.81.32.42.1

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2004 2010 2015 2020Year

Com

pone

nt R

atio

of I

nsta

lled

Cap

acity

(%

)


0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020Year

Ann

ual G

ener

atio

n (G

Wh)


0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020Year

Ann

ual G

ener

atio

n (G

Wh)


Appendix III

Transition of Component Ratio of Annual Generation (Proposed Case)

Transition of Capacity Factor in the Whole Sumatra System (Proposed Case)

Transition of Fuel Consumption (Proposed Case)



13.4 15.9

31.8 29.1

26.9

29.4

28.8 41.235.7

32.6

22.917.119.2

10.7 7.7 5.93.9

10.7

8.26.3

0.60.5

0.80.9

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2004 2010 2015 2020Year

Com

pone

nt R

atio

of A

nnua

l Gen

erat

ion

(%)


13.3 14.1

27.122.8

26.9

39.6

41.045.2

35.6

26.5

18.1 21.919.3

9.7 6.7 4.94.0

9.5

6.6

4.9

0.50.4

0.71.0

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2004 2010 2015 2020Year

Com

pone

nt R

atio

of A

nnua

l Gen

erat

ion

(%)


0

10

20

30

40

50

60

70

80

90

100

2004 2010 2015 2020Year

Cap

acity

Fac

tor

(%)

Hydropower

Geothermal

Steam Turbine

Combined Cycle

Gas Turbine

Diesel

Special Supply

0

10

20

30

40

50

60

70

80

90

100

2004 2010 2015 2020Year

Cap

acity

Fac

tor

(%)

HydropowerGeothermalSteam TurbineCombined CycleGas TurbineDieselSpecial Supply

Low Demand Case

2004 2010 2015 2020Coal (kiro-ton) 1,174 2,492 3,202 5,955Gas (million-scf) 58,290 61,220 56,430 54,700HSD (kiro-litter) 404,049 276,683 269,695 265,463MFO (kiro-litter) 265,280 0 0 0

High Demand Case

2004 2010 2015 2020Coal (kiro-ton) 1,182 3,790 5,609 8,333Gas (million-scf) 58,680 56,320 55,350 81,380HSD (kiro-litter) 406,756 307,366 301,866 301,988MFO (kiro-litter) 267,387 0 0 0

Fuel

Fuel

Year

Year

Appendix III

Transition of Daily Gas Consumption (Proposed Case)

Transition of CO2 and SO2 Emission Intensity (Proposed Case)

Necessary Investment Cost (Proposed Case)

System Cost (Proposed Case)

（CO2）（SO2）

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

2004 2010 2015 2020

Year

Dai

ly G

as C

onsu

mpt

ion

(MM

BTU

/day

) Low Demand Case

High Demand Case

0.000

0.100

0.200

0.300

0.400

0.500

0.600

0.700

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020Year

CO

2 Em

issi

on In

tens

ity (

kg-C

O2/k

Wh)

Low Demand Case

High Demand Case

0.000

1.000

2.000

3.000

4.000

5.000

6.000

7.000

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020Year

SO2 E

mis

sion

Inte

nsity

(g-

SO2/k

Wh)

Low Demand Case

High Demand Case



Total 435.0 1,309.0 1,710.0 3,454.0



Total 957.5 1,859.0 2,020.0 4,836.5

Total

Total

Year

Year


Low High(1) Construction Cost 1,193 1,804(2) Salvage Value 224 285(3) Operation Cost 4,246 4,679(4) ENS Cost 33 39System Cost(1) - (2) + (3) + (4) 5,248 6,237

Item Demand Case

Demand-Supply Balance at Peak Demand by System (Proposed Case, High Demand Case)

System 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

North 973.1 1,080.7 1,148.4 1,243.5 1,347.3 1,448.0 1,572.6 1,704.0 1,829.6 1,963.9 2,108.0 2,235.7 2,370.9 2,514.2 2,666.1 2,827.4 2,998.8 3,180.9

System Installed Capacity (MW) 1,352.9 1,385.9 1,532.9 1,532.9 1,725.2 1,955.2 1,827.9 1,882.9 2,082.9 2,416.9 2,516.9 2,616.9 2,716.9 2,916.9 2,916.9 3,316.9 3,516.9 3,616.9

Existing Plant (MW) 1,352.9 1,352.9 1,352.9 1,352.9 1,345.2 1,345.2 907.9 907.9 907.9 907.9 907.9 907.9 907.9 907.9 907.9 907.9 907.9 907.9

Fixed Project (MW) 0.0 33.0 147.0 0.0 0.0 230.0 110.0 55.0 0.0 154.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Candidate Project (MW) 0.0 0.0 0.0 0.0 200.0 0.0 200.0 0.0 200.0 180.0 100.0 100.0 100.0 200.0 0.0 400.0 200.0 100.0

Coal-fired Steam Turbine (MW) 0.0 0.0 0.0 0.0 0.0 0.0 200.0 0.0 200.0 0.0 0.0 100.0 100.0 200.0 0.0 0.0 200.0 100.0

Gas Turbine (MW) 0.0 0.0 0.0 0.0 200.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Hydropower (MW) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 180.0 100.0 0.0 0.0 0.0 0.0 400.0 0.0 0.0

Reserve (%) 39.0 28.2 33.5 23.3 28.0 35.0 16.2 10.5 13.8 23.1 19.4 17.0 14.6 16.0 9.4 17.3 17.3 13.7

South-West 1,138.7 1,206.1 1,305.6 1,428.3 1,564.1 1,716.4 1,889.0 2,056.4 2,235.1 2,436.3 2,644.5 2,820.6 3,002.8 3,193.0 3,392.8 3,603.6 3,826.7 4,063.1

System Installed Capacity (MW) 1,525.1 1,720.1 1,818.0 2,028.0 2,065.3 2,215.3 2,415.3 2,707.3 2,807.3 2,807.3 3,157.3 3,357.3 3,557.3 3,757.3 4,107.3 4,107.3 4,357.3 4,757.3

Existing Plant (MW) 1,525.1 1,525.1 1,522.0 1,522.0 1,309.3 1,309.3 1,309.3 1,309.3 1,309.3 1,309.3 1,309.3 1,309.3 1,309.3 1,309.3 1,309.3 1,309.3 1,309.3 1,309.3

Fixed Project (MW) 0.0 195.0 101.0 210.0 200.0 0.0 0.0 192.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Candidate Project (MW) 0.0 0.0 0.0 0.0 50.0 150.0 200.0 100.0 100.0 0.0 350.0 200.0 200.0 200.0 350.0 0.0 250.0 400.0

Coal-fired Steam Turbine (MW) 0.0 0.0 0.0 0.0 0.0 0.0 200.0 100.0 100.0 0.0 0.0 0.0 200.0 200.0 200.0 0.0 100.0 100.0

Gas-fired Combined Cycle (MW) 0.0 0.0 0.0 0.0 0.0 150.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 150.0 0.0 150.0 300.0

Gas Turbine (MW) 0.0 0.0 0.0 0.0 50.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Hydropower (MW) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 350.0 200.0 0.0 0.0 0.0 0.0 0.0 0.0

Reserve (%) 33.9 42.6 39.2 42.0 32.0 29.1 27.9 31.7 25.6 15.2 19.4 19.0 18.5 17.7 21.1 14.0 13.9 17.1

Item

Peak Demand (MW)

Peak Demand (MW)

（）（）（）（）（）（）（）（）（）（）（）（）（）（）（）（）（）

（）（）（）（）（）（）（）（）（）（）（）（）（）（）（）（）（）

（）

（）

Appendix III

Appendix IV

(i) Scoping format of potential impacts Scoping Format for the Study

Social Environment Natural Environment Pollutions & Public Hazards

Items of Impact Degrees of

Possible Impacts (A - C)





Involuntary Resettlement Protected Area Air Pollution

Minority or weak people of society Geographical

/Geological Features Water Pollution

Inequality and separation in society Sediment &

Hydrology Soil Contamination

Cultural heritage/ Local landscape Ecosystems/ Wildlife Wastes

Economic activities (regional or local) Global warming Noise & Vibration

Water Usage Others

Contagious or Infectious disease

Accidents Accidents

Appendix IV

(ii) Definitions of categories in the scoping format

Definitions of Categories (A - C) in Scoping Format

Category Explanation Category A Projects are classified as Category A if they are likely to have

significant adverse impacts on the environment and society. Projects with complicated impacts or unprecedented impacts, which are difficult to assess or which have a wide range of impacts or irreversible impacts, are also classified as Category A. Projects are also classified as Category A if they require a detailed environmental impact assessment by environmental laws and the standards of the governments. The impacts may affect an area broader than the sites or facilities subject to physical construction. Category A, in principle, includes projects in sensitive sectors (i.e., characteristics that are liable to cause adverse environmental impact) and projects located in or near sensitive areas. An illustrative list of sensitive sectors, characteristics and areas is given in Appendix I.

Category B Projects are classified as Category B if their potential adverse impacts on the environment and society are less adverse than those of Category A projects. Generally they are site-specific; few if any are irreversible; and in most cases normal mitigation measures can be designed more readily.

Category C Projects are classified as Category C if they are likely to have minimal or little adverse impacts on the environment and society.

Appendix-1 Illustrative list

1. Large-scale projects in sensitive sectors:(3) Thermal Power (including geothermal power);(4) Hydropower, dams and reservoirs;(6) Power transmission and distribution lines;etc.

2. Sensitive characteristics:(1) Large-scale involuntary resettlement;(2) Large-scale groundwater pumping;(3) Large-scale land reclamation, land development and land-cleaning; and(4) Large-scale logging.

3. Sensitive areas or their vicinity:(1) National parks, nationally-designated protected areas (coastal areas, wetlands, areasfor ethnic minorities or indigenous peoples and cultural heritage, etc., designated bynational governments) and areas being considered for natural parks or protected areas;(2) Areas the national or local governments believe to require careful considerations.

<Natural Environment> - Primary forests or natural forests in tropical areas; - Habitats with important ecological value (coral reefs, mangrove wetlands and tidal

flats, etc.); - Habitats of rare species requiring protection under domestic legislation, international

treaties, etc.; - Areas in danger of large-scale salt accumulation or soil erosion; and - Areas with a remarkable tendency towards desertification.

<Social Environment> - Areas with unique archeological, historical or cultural value; and - Areas inhabited by ethnic minorities, indigenous peoples or nomadic peoples with

traditional ways of life and other areas with special social value.

Appendix IV

Criteria for Scoping Items (1/6)

HydoPower

ThermalPower

Geo-thermalPower

Trans-mission

LineSocial

EnvironmentInvoluntary

Resettlement(1) Do the prospective projects contain any physical transformation, such as facility construction and landreclamation, which is anticipated to cause involuntary resettlement in project implementation ?

Does it bring a large scale (more than a few hundred families) of resettlement and land expropriation, or thoselimited scale (less than several families) of ?

○ ○ ○ ○

(2) If resettlement is anticipated, is it possible to change the plan to avoid it ? If it is not avoidable, is it possible to make any alternative plans to minimize the impacts ? ○ ○ ○ ○

(3) If resettlement is not avoidable, is it expectable that concerned inhabitants agree to resettlement with the matterexplained properly and rightly to them, including necessary resettlement plans and compensation plans ? Do you anticipate any difficult processes to obtain agreements ?

○ ○ ○ ○

(4) Is it practically possible to carry out socio-economic surveys for anticipated resettlement inhabitants, to holdpublic hearings, to make proper resettlement and compensation plans preserving and restoring their livingstandards, and to prepare and maintain financial measures and implementation structures to realize the plans ? Are these processes guaranteed under the legal system ?

○ ○ ○ ○

(5) Does the resettlement bring any large disadvantages to the socially vulnerable, such as women, children, theelderly, the poor people, ethnic minorities, and indigenous people ?

For instance, hardships related to securing drinking water, educational conditions, medical facilities, jobopportunities, and inevitable changes in lifestyles.

○ ○ ○ ○

(6) Do you observe a political dictatorship in the region that makes it difficult to take proper measures mentionedabove in case of inevitable resettlement ? ○ ○ ○ ○

(7) Is it possible to establish system to monitor the impacts on resettled inhabitants and to take sustainablemeasures for living support to them ? ○ ○ ○ ○

Minority or weakpeople ofsociety

(1) Do the plan (and projects) ignore or have the possibility to ignore lives and benefits of the social minorities andthe weak, such as women, children, the elderly, handicapped people, the poor people, ethnic minorities, indigenouspeople, religious minorities, migrants and veterans, by removing their means of production and living andcompelling them to change their basic lifestyles ? Are there any countermeasures to avoid these ?

○ ○ ○ ○

(2) Does the plan sufficiently take account of basic rights for life of the social minorities and the weak ? ○ ○ ○ ○

(3) Does the plan damage socio-economic infrastructures of the social minorities and the weak, such as a hospital,a school and a road ? ○ ○ ○ ○

(4) Are considerations given to reduce impacts on the culture and lifestyle of ethnic minorities and indigenouspeople ? Is the project planner (the proponent) aware of the need and ready to discuss on the matter with them ? Is this guaranteed under the legal system ?

○ ○ ○ ○

(5) Are considerations given to reduce impacts on the culture and lifestyle of ethnic minorities or indigenouspeople, where they are living in the right-of-way ? Is the project planner (the proponent) aware of the need and ready to discuss on the matter with them ? Is this guaranteed under the legal system ?

○

Category EnvironmentalItems

FacilityCheck Items

Appendix IV


HydoPower

ThermalPower

Geo-thermalPower

Trans-mission

LineSocial

EnvironmentInequality andseparation in

society

(1) Are considerations given to distribute project benefits evenly among concerned society ? Is not there a possibility that adverse impacts converge (or gather) on one part of regions or social groups ? ○ ○ ○ ○

(2) Is it not probable that the plan cause any frictions of different interests in society ? ○ ○ ○ ○

(3) Are there any possibilities of physical separations where those, such as traffics, passing, communications,social exchanges and commutes between residents and work places, are made difficult with blocking of passagesand disconnection of communication means ?

○ ○ ○ ○

Cultural heritage Are there any possibilities that the plan damages the local archeological, historical, cultural, and religious heritagesites ? ○ ○ ○ ○

Local landscape Are there any adverse impacts on the famous aesthetic landscape? Are there any claims of inhabitants that they hope to preserve the landscape ? In this case, is it possible to review the plan and take any necessary countermeasures ?

○ ○ ○ ○

Economicactivities

(regional/local)

(1) Are there any adverse impacts on agriculture, livestock farming and small fishery, such as loss of farmlands andgrassland and blocking of livestock's path, due to construction of large scale facilities, reservoirs, power plantsclose to river mouth or on coastline, transmission lines, and access roads ?

○ ○ ○ ○

(2) Are there any adverse impacts on land use downstream of a dam or an intake ?In particular, does reduction in the supply of fertile soils to downstream areas not adversely affect agricultural

production ?○

(3) Does existence of a dam adversely affect water transport of river vessels or water utilization of local inhabitants ○

Water Usage (1) Do intake of water (both surface and ground) and discharge of used and waste water adversely affect anysources of downstream water supply, due to water flow decrease, ground water level down, and deterioration ofwater quality ?

○ ○ ○

(2) Can the minimum maintained flow be supplied to downstream of a dam or an intake, which is necessary forsecuring water uses ? ○

(3) Does reduction in water flow of downstream (of a dam or an intake) or seawater intrusion adversely affectdownstream water uses and land uses ? ○

(4) Do intake of water (both surface and ground) and discharge of heated cooling water adversely affect the existingconditions of water and river utilization, especially fishery ? ○

(5) Do intake of water (both surface and ground) and discharge of wastewater adversely affect the existingconditions of water and river utilization ? ○

Contagious orInfectiousdisease

(1) Are there any risks that inflow of workers associated with the project should bring in the outbreak of diseasesincluding communicable diseases like HIV? Is it possible to take adequate considerations to public health, if necessary ?

○ ○ ○ ○

(2) Are there any risks that water-borne or water-related diseases, such as schistosomiasis, malaria, filariasis, beintroduced ? ○ ○ ○

Accidents Do the prospective projects include large scale civil works which cause a large amount of traffic of heavyvehicles and equipment ? ○ ○ ○ ○

Category EnvironmentalItems Check Items

Facility

Appendix IV


HydoPower

ThermalPower

Geo-thermalPower

Trans-mission

LineNatural

EnvironmentProtected Area Is it possible to locate the planned facilities to avoid protected areas designated by the national legislation or

international treaties and conventions ? Does the project activities not possibly affect the protected areas ?

○ ○ ○ ○

Geographical/Geological

Features

(1) Is it likely that a large-scale alteration of topographic features and geologic structures are brought about in thesurrounding areas of the planned sites, such as land excavation, dredging and reclamation ? ○ ○ ○ ○

(2) Is it conceivable that the planned facilities be inevitably situated in areas where topographic features andgeologic structures are fragile and may easily result in slope failure, land slide and differential settlement ? In such a case, is there any measure to avoid or mitigate the possible impacts ?

○ ○ ○ ○

(3) Is it possible to avoid the site selection where civil works such as land cutting and filling are frequently used atslopes with possible land failures and landslides ? Is it readily possible to take proper measures to prevent slope failures and landslides?

○ ○ ○ ○

(4) Is there not a good risk that soil runoff occurs at land cutting and filling areas, spoil-banks, or borrowing pits ? Is it readily possible to take proper measures to prevent soil runoff ? ○ ○ ○ ○

Sediment &Hydrology

(1) When a hydropower plant with dam and reservoir is concerned, do they usually make proper surveys and takesufficient mitigation measures over impacts on upstream and downstream riverbeds, and erosion andsedimentation of rivers ?

○

(2) Is it likely that such structures as dams and weirs of the size that may cause changes of a river system orhydrological impacts on the surface-or-ground water flow ? ○

(3) Is there any plan to extract ground water or steam that may affect ground water system or ground water usagein the surrounding area ? ○ ○

Ecosystems/Wildlife

(1) Does the planned project site not extend over primeval forests, tropical natural forests, biological corridors andecologically important habitats such as coral reefs, mangroves, and tidal flats ? ○ ○ ○ ○

(2) Does the planned project site not extend over the protected habitats and biological corridors of precious speciesdesignated by the country's laws or international treaties and conventions? ○ ○ ○ ○

(3) Is it unlikely that the project activities may cause serious impacts on important ecosystems even if the projectsite is outside of those systems ?

For instance, are there not any risks of deforestation and poaching under development activities, scattering orfalling of atmospheric pollutants and oxides, desertification, and dried-up swamps ?

Is not there any risks that non-native species, pests and vectors are carried in with tree-planting and importedsoil ?

○ ○ ○ ○

(4) Do they plan to install any blocking structures in the river where important migratory fish species are sighted tolive ?

If such biological information are insufficient, is it planned to take proper considerations for conducting necessarysurveys and measures ?

○

(5) Is it likely such facilities to be installed as possibly affect river system where rich ecosystems or precious aquaticlives, fauna and flora keep habitats ? ○ ○ ○

Check ItemsFacility

Category EnvironmentalItems

Appendix IV


HydoPower

ThermalPower

Geo-thermalPower

Trans-mission

LineNatural

EnvironmentEcosystems/

Wildlife(6) Do they plan to take surface or ground water, and discharge thermal effluent and seepage water, which mayaffect water volume, temperature and quality of river and surrounding aquatic ecosystem ? ○ ○ ○

(7) In case the project site is located in an undeveloped area, is there a risk that natural environment would beseverely damaged by the local development and unexpected migration of people from outside? Is it in the scope of plan to take proper countermeasures to manage those issues ?

○ ○ ○ ○

Global warming Does the planned power plant emit considerable greenhouse gases? ○

Pollutions &Public

Hazards

Air Pollution (1) In selection of the project, do they employ the design policy to control air pollutants such as sulfur oxides (SOx),nitrogen oxides (NOx), and soot and dust emitted from power plant in operation ? ○

(2) In the case of coal-fired power plants, does the project include countermeasures to avoid air pollution due tofugitive coal dust from coal piles, coal handling facilities, and dust from coal ash disposal sites ? ○

(3) In planning do they take account of multiple and cumulative impacts to the area that are under adverse impactsby fixed and mobile sources of pollutants around the project site? ○

(4) In the case of geothermal power plants, does the project include countermeasures against air pollution due tohydrogen sulfide emitted from the power plant ? ○

Water Pollution (1) When a dam lake or a reservoir is concerned, is it possible to conduct assessment study for water qualitydegradation and to take measures to control water pollution ? is it financially possible to prepare the proper budgetfor such measures ? For instance,

1) Can they prevent the impacts on aquatic lives and fishes due to proliferation of water grass and abnormaloutbreak of animal/plant plankton ? 2) Can they supply the project cost for countermeasures against corrosion of trees in the dam lake or reservoir ?

3) Can they take measures for environmental management of waste water and garbage due to inflow of wastearound the watershed, and activities around the dam lake or reservoir such as tourism and fish farming after thedevelopment ? 4) Can they take measures for controlling water quality of discharged water ? 5) Is it possible to keep environmental standards against decrease of downstream water flow ?

○

(2) Do they include in the plan the cost for treating drain water from the power plant including thermal effluent ? Do they cover the cost enough to meet the effluent standards and environmental standards downstream.? ○

(3) In the case of coal fired power plants, do they include in the plan countermeasures against leachate from coalpiles and coal ash disposal sites ? ○

(4) Do they take measures, in the plan, against treating fuel waste and drain water containing oil and leaked waterfrom the power plant? ○

(5) In the case of geothermal power plants, do they include in the plan the cost of countermeasures against waterpollution by arsenic and mercury in geothermal utilization ? ○

(6) Do they consider the measures against river water pollution due to soil runoff from the bare lands resulting fromactivities such as land cutting and filling ? ○ ○ ○ ○


Facility

Appendix IV


HydoPower

ThermalPower

Geo-thermalPower

Trans-mission

LinePollutions &

PublicHazards

SoilContamination

(1) Is there a risk of pollution of the bottom sludge in a dam lake due to sedimentation of waste and rotted trees ?○

(2) Is there a risk of pollutants concentration in riverbed soil caused by decrease of river flow due to water intakeand so on ? ○ ○

(3) In the case of coal thermal power plants, is there a risk of soil contamination due to leachates from coal pilesand coal ash disposal sites ? ○

(4) In the case of geothermal power plants, is there a risk of soil contamination caused by pollutants such asarsenic and mercury in geothermal utilization ? ○

(5) Is there a risk of hazardous earth and sand problems due to imported earth and sand or exposed undergroundearth and sand in such case as site development, land filling and cutting ? ○ ○ ○ ○

Waste (1) Is there a good outlook of proper treatment and disposal plan for earth and sand generated by excavation ? For instance, the plan for disposal criteria, disposal site and treatment method. ○ ○ ○ ○

(2) Do the plan include a sub-plan for disposal and management of wastes such as debris and driftwood flowing inthe reservoir, especially at intakes or dams ? ○

(3) Do the plan include the management plan for treatment and disposal of wastes such as waste oils andchemicals, coal ash and by-product gypsum from flue gas desulfurization that come out of the power plantoperation ?

○

Noise &Vibration

(1) Do noise and vibrations in operation of power plant comply with ambient environmental standards, andoccupational health and safety standards? ○ ○ ○

(2) Do they plan the boundary of the project site not to be near private houses at present and in the future ?If such arrangement is impossible, do they plan to install silencer walls or vibration protection equipment for

meeting the standards concerned ?○ ○ ○

(3) In the case of coal-fired power plants, do they consider control of noise from the facilities for coal unloading, coalstorage areas and facilities for coal handling in the site plan and the facility plan? ○

Others(Subsidence)

(1) Is there in the plan extraction of a large volume of groundwater that may cause subsidence ?○

(2) Is there a risk of subsidence to be caused by steam extraction in geothermal power generation ? ○

(Odor) Is there a risk of offensive odor due to air pollutants, water pollution, soil contamination and wastes ? ○ ○ ○ ○

(Radiointerference)

Is there a risk of radio interference by transmission line towers and so on ? Is it likely that adequate countermeasures will be taken if significant radio interference is anticipated ? ○


Facility

Appendix IV


HydoPower

ThermalPower

Geo-thermalPower

Trans-mission

LinePollutions &

PublicAccidents (1) In the case of dam construction, have they selected a proper location where emergency discharge is less

frequently required and danger at the downstream are less? ○

(2) In the case of gas fired thermal power plants, have they paid considerations at the planning phase to the safetyof a gas pipeline ?

For instance, have they considered the site and plan to decrease the risk of explosion due to natural, human,facility and material factors, and done site selection to minimize the damages in case of actual explosion?

○

(3) In the case of oil thermal power plants, have they paid considerations at the planning phase to the higher safetyof fuel transportation ?

For instance, have they selected site with consideration to sailing route conditions and ship traffic to decrease therisk of oil spillage due to running aground and collision of a large scale tanker ?

○

(4) In the case of coal fired thermal power plants, have they paid considerations in planning facility and cost toprevent spontaneous combustion at the coal piles ? ○

(5) In the case of geothermal power plants, have they paid considerations at the planning phase to the safety ofsteam pipes ? ○

(6) In the case of transmission lines, have they paid considerations in the site plan of facility to reduce the risk oflocal residents’ accidents due to high voltage transmission lines ? ○


Facility

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August 2003 (2003a), RENCANA PENYEDIAAN TENAGA LISTRIK SUMATERA BAGIAN SELATAN

TAHUN 2004-2013, December 2003 (2003b), RENCANA PENYEDIAAN TENAGA LISTRIK SUMATERA UTARA 2004-2013,

December 2003 (2002), Studi Peluang Investasi di provinsi Sumatra barat, 2002 (2001), Assignment Monitoring for RKL/RPL for 275kV EHVTL LAHAT - TEBING TINGGI –

LUBUKLINGGAU - SAROLANGUN - MUARA BUNGO (386 km) and 150kV HVTL LUBUK LINGGAU - CURUP (69 km), JAMBI - MUARA BUNGO (195 km), Final Report, 2001

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December 2004

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