republic of indonesia the project for promotion of clean ... · republic of indonesia the project...

Republic of Indonesia

Ministry of Energy and Mineral Resources

PT PLN（Persero）

Republic of Indonesia

The Project for Promotion of Clean Coal Technology (CCT)

in Indonesia

FINAL REPORT

October 2012

Japan International Cooperation Agency (JICA)

Chubu Electric Power Co., Inc. Electric Power Development Co., Ltd.

Japan Coal Energy Center

IL

JR

12-098

The Project for Promotion of Clean Coal Technology (CCT) in Indonesia

Final Report i

TABLE OF CONTENTS

Chapter 1 Introduction ............................................................................................................... 1-1

1.1 Backgrounds for the implementation of the study ............................................................. 1-1 1.2 Study schedule ................................................................................................................... 1-3 1.3 JICA study team and counterpart ...................................................................................... 1-5

Chapter 2 Present Situation and Challenges Concerning the Energy policies ...................... 2-1

2.1 Energy policy .................................................................................................................... 2-1 2.2 Climate Change policies .................................................................................................... 2-32

Chapter 3 Environmental and social considerations ............................................................... 3-1

3.1 Regulations of guidelines on environmental management and assessment ...................... 3-1 3.2 Trend and Challenge of Environmental and Social Considerations .................................. 3-8

Chapter 4 Electricity business - current status and issues ...................................................... 4-1

4.1 Outline of the power generation business .......................................................................... 4-1 4.2 Present situation and challenges concerning coal-fired power plants ............................... 4-3 4.3 Present situation and challenges concerning the Java-Bali power transmission

system ................................................................................................................................ 4-5 4.4 The current situation and issues to finance power supply ................................................. 4-16

Chapter 5 Introduction of CCT roadmap ................................................................................. 5-1

5.1 Policy on the CCT Introduction Roadmap ........................................................................ 5-1 5.2 Characteristic of the high efficiency coal thermal power plant technology to

make study on introduction ............................................................................................... 5-2 5.3 The Outlook for Coal Resources ....................................................................................... 5-14 5.4 CO2 Reduction Effect and Prospect for the Use of Various Systems ................................ 5-22 5.5 Economical evaluation of CCT ......................................................................................... 5-28 5.6 CCT Introduction Roadmap .............................................................................................. 5-49

Chapter 6 Study for model coal-fired power plant .................................................................. 6-1

6.1 Selection of Pre-FS site for model power plant ................................................................. 6-1 6.2 Outline of the Pre-FS ......................................................................................................... 6-22 6.3 New Candidate Site Proposed for Coal-Fired Power Plant ............................................... 6-66


Final Report ii

LIST OF FIGURES

Figure 1.2-1 Schedule ................................................................................................................... 1-3

Figure 1.2-2 Overall composition of the study ............................................................................. 1-4

Figure 1.3-1 Study-Related Organizations .................................................................................... 1-5

Figure 2.1-1 Scenario for optimization of the national energy mix in 2025 ................................. 2-2

Figure 2.1-2 Targets for the primary energy mix in 2025 ............................................................. 2-3

Figure 2.1-3 Electricity-related organizations in Indonesia .......................................................... 2-6

Figure 2.1-4 Organization of Ministry of Energy and Mineral Resources (MEMR) .................... 2-7

Figure 2.1-5 Organization chart of PT PLN (Persero) Head Office.............................................. 2-8

Figure 2.1-6 Location of power development planning sites ........................................................ 2-14

Figure 2.1-7 Power development scheme ..................................................................................... 2-15

Figure 2.1-8 Investment required for electricity (nationwide) ...................................................... 2-15

Figure 2.1-9 Power Plant Plan Location Map (First crash program) ............................................ 2-19

Figure 2.1-10 Mining area, License permission, term etc. in New Mining Law .......................... 2-24

Figure 2.1-11 Taxes and other Levies on Mining ......................................................................... 2-25

Figure 2.2-1 Overview of Climate Change-Related Organizations in Indonesia .......................... 2-34

Figure 2.2-2 Relationship between RAN-GRK and Long-Term Development Plan .................... 2-36

Figure 2.2-3 Structure of Energy Working Group ........................................................................ 2-39

Figure 3.1-1 EIA procedure in Indonesia ...................................................................................... 3-7

Figure 4.1-1 Changes in Installed Capacity .................................................................................. 4-2

Figure 4.1-2 Changes in production of electricity ........................................................................ 4-2

Figure 4.3-1 JAWA- BALI 500kV transmission development plan (RUPTL 2011) ..................... 4-11

Figure 4.3-2 Actual power flow at night peak load (Feb. 27, Thu., 2011, 7p.m.) ......................... 4-12

Figure 4.3-3 Trend of power flow direction (500 kV system) ...................................................... 4-13

Figure 4.3-4 Trend of power flow direction (500kV system) in 2025 .......................................... 4-14

Figure 4.3-5 JAWA- BALI 500kV power system in 2025 by JICA Study Team Study Team .................................................................................................................... 4-15

Figure 4.4-1 Electricity price, generation cost and the subsidy for PLN ...................................... 4-16

Figure 4.4-2 Capacity expansion plan ........................................................................................... 4-18

Figure 5.2-1 The change of the steam condition of the coal-fired thermal power plant in the World.............................................................................................................. 5-3

Figure 5.2-2 Change of the steam condition of the coal-fired thermal power plant in Japan .................................................................................................................... 5-3

Figure 5.2-3 Deferent point of drum type and one through type of Boiler ................................... 5-5


Final Report iii

Figure 5.2-4 (a) An operating USC Power Plants in major countries ........................................... 5-5

Figure 5.2-4 (b) Number of operating USC Power Plants in major countries .............................. 5-6

Figure 5.2-5 Outline Diagram of IGCC ........................................................................................ 5-8

Figure 5.2-6 Image of the CCS ..................................................................................................... 5-11

Figure 5.2-7 Image of the underground storage system ................................................................ 5-11

Figure 5.2-8 CO2 Image of the separation Technology ................................................................. 5-12

Figure 5.2-9 CCS application promising point at Indonesia ......................................................... 5-13

Figure 5.3-1 Indonesian coal resources and reserves .................................................................... 5-15

Figure 5.3-2 Change in Indonesian coal resources (2004-2020) .................................................. 5-15

Figure 5.3-3 Properties of Low rank coal for Power Plant fuel .................................................... 5-16

Figure 5.3-4 Outlook of OECD and Non-OECD total GDP ......................................................... 5-17

Figure 5.3-5 Coal Consumption of OECD and Non- OECD ASIA .............................................. 5-17

Figure 5.3-6 Estimation of Indonesian domestic coal demand ..................................................... 5-18

Figure 5.3-7 Realization and Estimation of Indonesian coal production, Export and Domestic sales ..................................................................................................... 5-19

Figure 5.3-8 Change in Coal price index (New Castle FOB） ..................................................... 5-20

Figure 5.3-9 Change in ICI and HBA ........................................................................................... 5-21

Figure 5.3-10 Trend of Low rank coal price index (ICI-4) ........................................................... 5-22

Figure 5.4-1 GHG emissions forecast for Indonesia (source: DNPI) ........................................... 5-23

Figure 5.4-2 Power generation capacity by source and GHG emissions growth from fossil fuel ............................................................................................................. 5-23

Figure 5.4-3 CO2 reduction volume by introduction of CCT ....................................................... 5-24

Figure 5.5-1 Comparison of economical efficiency ...................................................................... 5-30

Figure 5.5-2 Comparison of the Cost for USC and SC ................................................................. 5-31

Figure 5.5-3 Impact for 1kwf of Generation cost ......................................................................... 5-31

Figure 5.5-4 Thermal Efficiency of Coal-Fired Power Plants in Indonesia and of CEPCO ................................................................................................................ 5-33

Figure 5.5-5 Boiler structure differences by unit type .................................................................. 5-33

Figure 5.5-6 Scale attached to a heat transfer tube ....................................................................... 5-34

Figure 5.5-7 Heat transfer tube damaged by overheating ............................................................. 5-34

Figure 5.5-8 Water management points and chemicals injection points of the drum unit ............ 5-35

Figure 5.5-9 Water quality management points and chemicals injection points of the one-through unit .................................................................................................. 5-36

Figure 5.5-10 Conceptual diagram of Plant condition monitoring system ................................... 5-38

Figure 5.5-11 low of monitoring operations conducted using Plant condition monitoring


Final Report iv

system .................................................................................................................. 5-39

Figure 5.5-12 Equipment of the training center ............................................................................ 5-41

Figure 5.5-13 Outline of the tube thickness management system ................................................ 5-44

Figure 5.5-14 Outline of the measurement data ............................................................................ 5-45

Figure 5.5-15 CEPCO’s performance management system .......................................................... 5-46

Figure 5.5-16 Coal Fired TPP construction and training schedule ............................................... 5-48

Figure 5.6-1 Conclusion for Roadmap .......................................................................................... 5-50

Figure 5.6-2 Finalized CCT Roadmap .......................................................................................... 5-51

Figure 6.1-1(1) Preliminary research on candidate site ................................................................ 6-2

Figure 6.1-1(2) Screening and site selection process flow ........................................................... 6-3

Figure 6.1-2 Model power plant sites ........................................................................................... 6-7

Figure 6.1-3 Schematic of USC Coal-Fired Thermal Power Plant (1,000 MW × 2u) .................. 6-11

Figure 6.2-1 Site Location Map .................................................................................................... 6-23

Figure 6.2-2 General Plant Area layout ........................................................................................ 6-33

Figure 6.2-3 Bojonegara Power Plant Site and Study Case of Transmission................................ 6-34

Figure 6.2-4 Present Land Use of Serang District, Banten Province ............................................ 6-40

Figure 6.2-5 Environmental and Social Considerations Process after the Pre-FS and IEE study ........... 6-54

Figure 6.2-6 1,000 MW Coal Fired TPP Planning Schedule ........................................................ 6-56

Figure 6.2-7 1,000 MW Coal Fired TPP Construction Schedule .................................................. 6-57

Figure 6.3-1 Range of Study Area ................................................................................................ 6-66

Figure 6.3-2 Consensus Study Zone ............................................................................................. 6-67


Final Report v

LIST OF TABLES

Table 1.3-1 Counterpart Team Members ....................................................................................... 1-6

Table 2.1-1 Outline of the National Energy Policy (KEN) ........................................................... 2-2

Table 2.1.2 PLN purchasing prices for renewable energy (minimum) ......................................... 2-4

Table 2.1-3 PLN supply cost (2008) (unit: Rp/kWh) ................................................................... 2-5

Table 2.1-4 Comparison of old and new Electricity Laws (amendment items) ............................ 2-9

Table 2.1-5 RUKN (2008 edition) and RUPTL (2010 edition) .................................................... 2-10

Table 2.1-6 Power development plan for the Java-Bali system .................................................... 2-12

Table 2.1-7 Power supply-demand balance in the Java-Bali system ............................................ 2-13

Table 2.1-8 Comparison of the first and second crash programs .................................................. 2-16

Table 2.1-9 Development under the first crash program ............................................................... 2-18

Table 2.1-10 Calculation conditions ............................................................................................. 2-20

Table 2.1-11 Estimated optimal power source in Java-Bali system (2021-2025) ......................... 2-21

Table 2.1-12 Quality and Prices of HBP ....................................................................................... 2-28

Table 2.2-1 NAMA categories by Copenhagen Accord Table II submissions (36 countries) ............................................................................................................. 2-35

Table 2.2-2 GHG reduction targets by 2020 by sector (partial excerpt from RAN-GRK) ........... 2-36

Table 2.2-3 Energy sector major reduction action list (RAN-GRK) ............................................. 2-37

Table 3.1-1 Primary Indonesian regulations and guidelines regarding environmental management and EIA .......................................................................................... 3-2

Table 3.1-2 Primary Indonesian regulations regarding spatial planning ....................................... 3-3

Table 3.1-3 Primary Indonesian regulations on general environmental pollution control and on environmental measures for business activities of coal-fired power plants ......................................................................................................... 3-4

Table 4.1-1 Installed Capacity of the Java-Bali System by Power Source ................................... 4-1

Table 4.1-2 Installed Capacity of the Java-Bali System by Electric Utility .................................. 4-1

Table 4.2-1 PLN coal-fired power plants (Java-Bali system) ....................................................... 4-3

Table 4.3-1 Transmission line length ............................................................................................ 4-6

Table 4.3-2 Substation transformer capacity ................................................................................. 4-6

Table 4.3-3 Projection of transmission line length ........................................................................ 4-6

Table 4.3-4 Projection of substation transformer capacity ............................................................ 4-6

Table 4.3-5 500 kV Transmission line development plan ............................................................. 4-8

Table 4.3-6 500kV Substation development plan ......................................................................... 4-9

Table 4.3-7 Voltage analysis result ................................................................................................ 4-13


Final Report vi

Table 4.3-8 Voltage analysis result ................................................................................................ 4-14

Table 4.4-1 PLN’s financial situation and subsidy from the government ..................................... 4-16

Table 4.4-2 Electricity sales .......................................................................................................... 4-17

Table 4.4-3 Generation volume ..................................................................................................... 4-17

Table 5.2-1 Relations of steam condition and plant efficiency ..................................................... 5-4

Table 5.2-2 Technical characteristic .............................................................................................. 5-7

Table 5.2-3 Current situation of IGCC in the World ..................................................................... 5-9

Table 5.3-1 Properties of Indonesian Low rank coal .................................................................... 5-16

Table 5.5-1 Prerequisite of Comparison for economical efficiency. ............................................. 5-29

Table 5.5-2 Cost impact Analysis by the decline of the plant load factor/ plant thermal efficiency. ............................................................................................................. 5-32

Table 5.5-3 Supplied water quality management criteria applied in the drum unit operation .............................................................................................................. 5-37

Table 5.5-4 Supply water quality management criteria applied in the drum-type boiler operation .............................................................................................................. 5-37

Table 5.5-5 Role-sharing for water quality management in a power generation plant ................. 5-38

Table 5.5-6 Training items (examples) ......................................................................................... 5-41

Table 5.5-7 Outline of the qualification system ............................................................................ 5-42

Table 6.1-1 1st screening criteria .................................................................................................. 6-4

Table 6.1-2 2nd screening criteria ................................................................................................. 6-4

Table 6.1-3 Environmental and Social Screening format for comparison of candidate sites ...................................................................................................................... 6-5

Table 6.1-4 3rd Screening in Construction cost ............................................................................ 6-6

Table 6.1-5 List of model power plant sites .................................................................................. 6-7

Table 6.1-6 1st screening result .................................................................................................... 6-8

Table 6.1-7 2nd screening result ................................................................................................... 6-8

Table 6.1-8 Legend of the result of evaluation in environmental and social aspect ..................... 6-8

Table 6.1-9 3rd screening result .................................................................................................... 6-9

Table 6.1-10 Compiled result........................................................................................................ 6-10

Table 6.1-11 Scoping for determination of the IEE study scope at the Pre-FS study ...................... 6-12

Table 6.2-1 Stratigraphy of the Study Site .................................................................................... 6-26

Table 6.2-2 Design Requirements for Model Power Plant ........................................................... 6-28

Table 6.2-3 Steam conditions at rated condition ........................................................................... 6-28

Table 6.2-4 Environmental Standard of Coal Fired Power Plant for Flue Gas Discharge ............ 6-29

Table 6.2-5 Standard Limit of Liquid/Waste Water for Central Processing Unit of


Final Report vii

Thermal Power Plant ........................................................................................... 6-29

Table 6.2-6 Standard Limit of Liquid/Waste Water for Cooling Water ......................................... 6-29

Table 6.2-7 Standard Limit of Liquid/ Waste Water for Desalination ........................................... 6-29

Table 6.2-8 Standard Limed of Liquid/Waste Water for FGD System ......................................... 6-29

Table 6.2-9 Standard Limit for Noise ........................................................................................... 6-30

Table 6.2-10 Parameters of Design coal ....................................................................................... 6-31

Table 6.2-11 Comparison Between Transmission Study Cases For Bojonegara Power Plant ..................................................................................................................... 6-36

Table 6.2-12 Emission Gas Standards of Thermal Power Plant Fix Sources (with CEMS) ......... 6-41

Table 6.2-13 Effluent Standards for CPU of Thermal Power Plant .............................................. 6-41

Table 6.2-14 Effluent Standards for Boiler Blow-Down of CPU of Thermal Power Plant .......... 6-41

Table 6.2-15 Effluent Standards for Cooling Tower Blow-Down of CPU of Thermal Power Plant .......................................................................................................... 6-41

Table 6.2-16 Effluent Standards for Demineralization of Water Treatment Plant of CPU ........... 6-42

Table 6.2-17 Effluent Standards for Cooling Water ...................................................................... 6-42

Table 6.2-18 Effluent Standards for Desalination ......................................................................... 6-42

Table 6.2-19 Effluent Standards for FGD System (Sea Water Wet Scrubber) .............................. 6-42

Table 6.2-20 Effluent Standards for Coal Stockpile ...................................................................... 6-42

Table 6.2-21 Effluent Standards for Oily Water ............................................................................ 6-42

Table 6.2-22 Mitigation Measures for Environmental and Social Impacts of the Project (Evaluation with the IEE study) .......................................................................... 6-50

Table 6.2-23 Confirmations and detailed assessments to be conducted in the FS/EIA study ..................................................................................................................... 6-52

Table 6.2-24 Monitoring to be conducted for the Project ............................................................. 6-52

Table 6.2-25 Project Preparation and Bid Stage ........................................................................... 6-54

Table 6.3-26 Project Execution Stage ........................................................................................... 6-55

Table 6.2-27 Project cost estimate ................................................................................................ 6-58

Table 6.2-28 Assumption for financial Analysis (Base case) ........................................................ 6-59

Table 6.2-29 Results of Financial Analysis: Base case ................................................................. 6-60

Table 6.2-30 Impact of Initial Tariff as of 2017 ............................................................................ 6-60

Table 6.2-31 Impact of Tariff Increase Rate .................................................................................. 6-61

Table 6.2-32 Impact of Change in Construction Cost (Case 1) .................................................... 6-61

Table 6.2-33 Impact of Change in Construction Cost (Case 2) .................................................... 6-61

Table 6.2-34 Impact of Fuel Cost Increase Rate ........................................................................... 6-62

Table 6.2-35 Economic analysis, Base case .................................................................................. 6-63


Final Report viii

Table 6.2-36 Change of construction cost: (10% increase) ........................................................... 6-64

Table 6.2-37 Change in fuel cost (5% increase) ........................................................................... 6-64


Final Report ix

Abbreviations ADB Asian Development Bank

AMDAL Analisis Mengenai Dampak Lingkungan (Environmental Impact Assessment) APP Asia-Pacific Partnership for Clean Development and Climate ASEAN Association of Southeast Asian Nations

AWG-KP Ad Hoc Working Group on Further Commitments for Annex I Parties under the Kyoto Protocol

AWG-LCA Ad Hoc Working Group on Long-term Cooperative Action under the Convention BAKOREN Badan Koordinasi Energi Nasional (National Energy Adjustment Committee) BAPEDAL Badan Pengendalian Dampak Lingkungan (Emvironmental Impact Management Agency) BAPPEDA Badan Perencana Pembangunan Daerah (Regional Planning and Development Agency)

BAPPENAS Badan Perenchanaan Pembanguan Nasional (National Developmnet Planning Agency)

BAU Business as usual

BPPT Badan Pengkajian dan Penerapan Teknologi (Agency for the Assessment and Application of Technology)

CACR Compound Annual Growth Rate CBM Coalbed Methane CCPL Climate Change Program Loan CCS Carbon Dioxide Capture and Storage CCT Clean Coal Technology CCX Chicago Climate Exchange CDM Clean Development Mechanism CER Certified Emission Reduction CFPP Coal-Fired Power Plant COP Conference of the Parties CMP Conference of the parties serving as the Meeting of the Parties to the Kyoto Protocol CoW Contract of Work CCoW Coal Contract of Work DAC Development Assistance Committee DEN Dewan Energi Nasional (National Energy Council) DGE Directorate General of Electricity DMO Domestic Market Obligation DNA Designated National Authority

DNPI Dewan Nasional Perubahan Iklim (National Council for Climate Change)

DOE Designated Operational Entity DSCR Debt Service Coverage Ratio Economic IRR Economic Internal Rate of Return EIA Environmental Impact Assessment

ESDM Kementerian Energi dan Sumber Daya Mineral (Ministry of Energy and Mineral Resources)

FIRR Financial Internal Rate of Return GHG Greenhouse Gas GIS Green Investment Scheme GREEN Global action for Reconciling Economic growth and Environmental preservation

http://www.google.co.jp/url?q=http://www.dnpi.go.id/&sa=U&ei=dnXATs6cAYT5mAWm_6XKBA&ved=0CA8QFjAA&usg=AFQjCNHT6jzmH2VamUWCH8vEOKZGpn-j_Q


Final Report x

GIZ Gesellschaft für Internationale Zusammenarbeit

GTZ Gesellschaft für Technishe Zusammenarbeit HBA Harga Batubara Acuan (Coal Price Refence) HPB Harga Patokan Batubara (Benchmark Coal Price) IBRD International Bank for Reconstruction and Development ICAP International Carbon Action Partnership ICCSR Indonesia Climate Change Sectoral Roadmap ICI Indonesian Coal Index ICMA Indonesia Coal Mining Asociation ICPR Indonesia Coal Price Reference IEA International Energy Agency IET International Emission Trading IFC International Finance Corporation IGCC Integrated Coal Gasification Combined Cycle

IMF International Monetary Fund

IPCC Intergovernmental Panel on Climate Change IPP Independent Power Producer

IPR Izin Pertambangan Rakyat (Traditional (or People) Mining License)

IUP Izin Usaha Pertambangan (Mining Business License)

IUPK IUP Khusus (Special Mining Business License)

JI Joint Implementation

JICA Japan International Cooperation Agency

LIBOR London Interbank Offered Rate LLDC Least among Less Developed Countries LNG Liquefied Natural Gas LUCF Land Use Change and Forestry LULUCF Land Use, Land Use Change and Forestry MEF Major Economies Forum

MEMR Ministry of Energy and Mineral Resources

mil US$ million US dollar

MOE Ministry of the Environment

MOFo Ministry of Forestry MOP Meeting of the Parties MRV Measurable, Reportable and Verifiable NAMAs Nationally Appropriate Mitigation Actions NAMAC Nationally Appropriate Mitigation Actions and Commitments by Annex I NCIC Nature Conservation Information Center NGO Non-Governmental Organization NPP Nuclear Power Plant NPV Net Present Value OECD Organisation for Economic Co-operation and Development O&M Operation and Maintenance PDD Project Design Document


Final Report xi

PERPRES Peraturan Presiden Republik Indonesia (Presidential Regulation of the Republic of Indonesia）

PJB PT Pembangkitan Jawa Bali (Jawa Bali Power Generation Company) PLN PT Perusahaan Listrik Negara (State Electricity Company')

PLTU Pembangkit Listrik Tenaga Uap (Steam Power Plant)

PLTP Pembangkit Listrik Tenaga Panas Bumi (Geothermal Power Plant) PLTGU Pembangkit Listrik Tenaga Gas Uap (Gas Combined cycle Power Plant) PLTG Pembangkit Listrik Tenaga Gas (Gas turbine Power Plant) PLTA Pembangkit Listrik Tenaga Air (Hydroelectric Power Plant) PoA CDM Programme of Activities CDM PPA Power Purchase Agreement PPP Public Private Partnership PRSP Poverty Reduction Strategy Paper

RAN-GRK Rencana Aksi Nasional Penurunan Emisi Gas Rumah Kaca (National Action Plan for Greenhouse Gas Emission Reduction)

RAD-GRK Rencana Aksi Daerah Penurunan Emisi Gas Rumah Kaca (Regional Action Plan for Greenhouse Gas Emission Reduction)

REDD Reducing Emissions from Deforestation and Forest Degradation Rp Indonesian Rupiah RTRW Rencana Tata Ruang Wilayah (Sapcial Plan) RPJM Rencana Pembangunan Jangka Menengah (Medium-term Development Plan) RPJP Rencana Pembangunan Jangka Panjang (Long-term Development Plan) RUEN Rencana Umum Energi Nasional (National Energy Plan) RUKN Rencana Umum Ketenagalistrikan Nasional (General National Power Plan) RUPTL Rencana Umum Penyediaan Tenaga Listrik (Electrical Power Supply Plan) SC Super Critical SCM Sectoral Crediting Mechanism SEA Strategic Environmental Assessment SNC Second National Communication UNDP United Nations Development Programme UNFCCC United Nations Framework Convention on Climate Change USC Ultra Super Critical US$ US dollar WACC Weighted Average Cost of Capital WALHI Wahana Lingkungan Hidup Indonesia (Indonesia Forum for Environment) WASP Wien Automatic System Planning WB The World Bank WWF World Wide Fund for Nature

http://www.scouting.org.za/westerncape/pltu/


Final Report 1-1

Chapter 1 Introduction 1.1 Backgrounds for the implementation of the study

Indonesia was rich in natural resources, including oil, coal, gas, geothermal and hydropower. In light of the abundance of energy resources, the country thought it was possible to acquire foreign currency by exporting fossil fuel resources while meeting domestic demand for the resources in the past. As for oil, however, due to increases in domestic demand and the stagnant growth of the output, Indonesia became a net-importer in 2004. In response, the country focused on the policy to reduce dependence on oil as a core of its energy policies, and announced to promote the diversification of energy sources in its policies on energy promulgated in the same year. Also in the presidential order on national energy policies issued in 2006, coal was deemed to become the greatest energy source in 2025, because the country had much reserve of coal, which is available at low cost.

The demand for electrical power is rapidly rising. In response, the government formulated a fast track coal-fired power development plan, i.e. the first Crash Program under the policy for alleviation of dependence on oil in 2006 and decided to develop a total of 10,000 MW worth of coal-fired power generation capacity by 2009. This was followed by formulation of the Second Crash Program under the policy for energy diversification in 2009, which targeted the development of an additional 10,000 MW in installed capacity by 2014. While the target capacity expansion includes renewable energies such as geothermal and hydropower, coal-fired power accounts for 36 percent of it. Coal-fired power remains to be actively promoted over the coming years in view of the aforementioned situation as well as the advantage of coal in terms of cost and availability. According to the Rencana Umum Ketenagalistrikan Nasional (RUKN; General National Power Plan), the share of coal in all primary energies for power generation is anticipated to increase from 45 percent in 2008 to 63 percent in 2018.

Meanwhile, the 13th Conference of Parties to the Framework Convention on Climate Change (COP 13) held on the island of Bali in 2007 adopted the Bali Action Plan, which encouraged efforts for reduction of emissions of carbon dioxide (CO2) in developing countries. In September 2009, Indonesian President Susilio Bambang Yudohoyono announced that the country was targeting its greenhouse gas (GHG) emissions reduction by 26 percent in the business-as-usual (BAU) case, and 41 percent with assistance from the international community by 2020. To achieve this target, it was decided to have action plans for GHG emission reduction prepared in each industrial sector. In light of the high share of coal in the energy source mix in the power sector, efficiency increase in the country’s coal-fired power generation could make a great contribution to GHG emissions reduction.

According to World Energy Outlook 2011 issued by the International Energy Agency (IEA), almost half of the world’s energy demand has been met by coal for recent 10 years, and if the current policies continue to be implemented, the consumption of coal will increase by about 65% and account for the largest percentage in the energy source composition of the world, replacing oil. Coal is distributed evenly across regions and rich in the amount of reserve. It is therefore utilized around the world, and the coal producing countries attribute importance to make effective use of this valuable national


Final Report 1-2

resource also from the aspect of energy security. As for the output by power source (as of 2009), coal-fired power generation accounts for the largest percentage at 40.9%, followed by natural gas (21.3%), hydropower (15.9%), and nuclear power (13.5%). IEA predicts that the percentage that coal-fired power generation accounts for in the composition will decrease by about 7% by 2035 but will continue to be the largest energy source toward the future.

In 2010, coal production in Indonesia reached 306 million tons and was ranked as No. 6 in the world’s coal production1 while the export totaled 298 million tons and was ranked as No. 2 in the world’s coal export, following Australia. As for steam coal, Indonesia is the world’s No. 1 exporter, while Japan is the world’s largest importer of coal2. For Indonesia, Japan was the No.1 coal importer of Indonesian coal until 2008 and has been the No. 4 since 2009, next to China, India and South Korea. Japan has been building multi-layered relations of cooperation with Indonesia through a range of coal-related projects, with a view to ensuring the stable supply of coal from the country. Based on the recognition that coal is the largest energy source for Indonesia, Japan has been supporting the country in the multi-purpose use of low-rank coal for the more efficient use of coal and for low-carbon coal-fired power generation. In particular for coal-fired power generation, from which a large amount of CO2 is emitted, the introduction of Japan’s CCT, which represents the highly efficient technology for coal-fired power plants, will help curb demand for coal and greenhouse gas emissions by making it possible to increase the output of power generation without increasing the use of the resource.

The Japan International Cooperation Agency (JICA) deems that it is significant to boost GHG emissions reduction efforts through the introduction of high efficiency clean coal technology (CCT) for coal-fired power plants in close coordination with the on-going Climate Change Program Loan by Japan. There is a strong need to mount approaches for more efficient energy utilization along with the increasing development of coal-fired thermal power. This point to the necessity of pursuing the input of high efficiency coal-fired generation facilities applying CCT while preserving conformance with the Climate Change Program Loan provisions.

This situation constituted the background for a request by the Indonesian government for assistance with the input of CCT high efficiency coal-fired generation facilities for the purpose of reducing GHG emissions as well as upgrading energy utilization efficiency and mitigating environmental effect incurred by the power sector.

(1) Objective of the Study

1 BP statics 2011 2 Statics Yearbook of Indonesia, Statics Indonesia

Objective 1: Formulate a roadmap of Clean Coal Technology(CCT) to promote CCT to achieve higher power generation efficiency and GHG emissions reduction

Objective 2: Study a CCT coal-fired model power plant (implementation of a pre-FS)

Objective 3: Transfer Japanese CCT and develop human resources


Final Report 1-3

(2) Study Area Java-Bali system and Sumatra system

(3) Counterparts MEMR: Directorate General of Electricity (DGE), Ministry of Energy and Mineral Resources

PT PLN (Persero): State Owned Electric Power Company

1.2 Study schedule

The study was conducted for 16 months from April 2011 to July 2012, being divided into the following three phases. In the first phase, basic data were collected and study plan was formulated. In the second phase, the CCT introduction roadmap was created. In the third phase, candidates for the construction site of the CCT introduction model plant were selected and preparatory feasibility study was carried out.

During the study period, a total of four steering committee meetings were held for discussions on the study policies and for progress reporting, two seminars were held for briefing on the study details to those concerned, and three stakeholder meetings were also held. The counterpart training was provided in November 2011. The following shows the entire schedule for the study.

Figure 1.2-1 Schedule

Source: JICA Study Team

Period2011 2012

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

Study stage

Work in IndonesiaSteering Committee

Seminar・Site Reconnaissance Study・Environmental and Social ConsiderationStudy・Potential Study

CP Training

Outcome

Period2011 2012

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

Study stage

Work in IndonesiaSteering Committee

Seminar・Site Reconnaissance Study・Environmental and Social ConsiderationStudy・Potential Study

CP Training

Outcome Inception Draft Final (June 2012)2012)

Site Site Reconnaissance StudyStudy

Final (July 2012)2012)

IEE study

Interim

Contract

Contract

Roadmap Pre-FS

Potential StudyContract

Basic Study Pre-FS for CCT Model Power Plant

CCT Roadmap

1st Steering Committee1st Seminar

1st SHM 2nd SHM2nd 2nd Steering Committee

3rd 3rd Steering Committee2nd Seminar

3rd SHM

Inception Draft Final (June 2012)2012)



IEE study

Interim

Contract

Contract

Roadmap Pre-FS


Inception Draft Final (June 2012)2012)



IEE study

Interim

Contract

Contract

Roadmap Pre-FS



CCT Roadmap


CCT Roadmap




3rd SHM




3rd SHM


Final Report 1-4

・・

Figure 1.2-2 Overall composition of the study


< Overall Composition of the Study>

・Second steering committee meeting ・First seminar ・Interim report ・Second stakeholder meeting

・Third steering committee meeting ・Second seminar ・Third stakeholder meeting ・Final report

・・Possibility of introducing CCT-based highly efficient power

generation facilities ・Coal Demand and Supply Planning ・Potential CO2emission reduction ・Economical evaluation of CCT ・ Human resource development and system for CCT

introduction ・CCT Roadmap

Phase 2: Creation of the CCT introduction roadmap

・Inception report ・First and second steering

committee meetings ・First stakeholder meeting

Making examinations

on the financial scheme

Selecting the location for the model power plant ・Examining the project ・Making examinations about environmental measures ・Initial Environmental Examination (IEE) ・Examining the related infrastructure equipment ・Making investigations on the candidate sites for the development project

Third phase: Examination about the model coal-fired power plant

・Transformation of the CCT introduction roadmap into regulatory and legal criteria

・Implementation of the CCT-based highly efficient coal-fired power generation project

Discussions on the study policy and method

Basic information ・Energy policy ・Prediction and plan regarding the demand for coal ・Present situation of the existing power generation facilities

Assessment of the potentials of CCT-based highly efficient power generation facilities

Review of the development plan ・Power source

development plan ・Transmission facility

development plan

Phase 1: Basic study

・Incorporation into the national power source development plan (CCT)


Final Report 1-5

1.3 JICA study team and counterpart

In the implementation of the study, the MEMR’s DGE and PLN will be the study team’s counterparts in terms of policies and technologies, respectively. The MEMR’s Directorate General of Minerals, Coal and Geothermal, DEN and BPPT are in charge of formulating a coal supply plan, energy policies, and R&D, respectively, and will be the related authorities. It is also important for the study team to cooperate with BAPPENAS to ensure consistency with the national development plan. At the meetings of the Steering Committee held on a regular basis, information will be shared with participating stakeholders for the formulation of the plan.

MEMR

Energy

（ DGE

PLN Subsidiaries for Generation （

DGMC, DGNRE

Power

PLN IPP

MOE ICMA

Coal Companies

Main counterpart

Tech Devloment

Environmental policy

Development Planning

Energy Policy

CO2reduction DEN

PLN

BAPPENAS

BPPT

Figure 1.3-1 Study-Related Organizations


For the smooth and efficient implementation of the study, counterpart teams are formed by expert field, and members of the teams, as shown below, are working on the study.


Final Report 1-6

Table 1.3-1 Counterpart Team Members

As of August 22, 2011

Subject JICA Study Team Counterpart

Power development plan Mr.Yoshitaka SAITO

DGE : Mr. Zaenul PLN : Mr. Arief Sugiyanto,

Assistant Engineer, System Planning Div.

Coal-fired power Development plan

Mr.Minoru YASUI, Mr. Masanori DATE,

Mr.Toshiaki TOYAMA, Mr.Akihiro OSAJIMA

DGE : Mr. Chrisnawan Anditya, Section Head of the Preparation

Program of Electrical Power Supply PLN : Mr. Suroso Isnandar,

Senior Engineer, System Planning Div.

Coal utilization policy and plan Mr.Yasuo OTAKA

Directorate General Mineral and Coal: Ms. Lydia Hardiani, Subdirector of Programing, Directorate of Mineral

and Coal Program Supervision PLN: Ms. Chairani Rahmatullah,

Carbon Credit Ms.Fumiko YAMADA Mr.Tsuyoshi SASAKA

DGE : Ms. Ellydar Baher PLN : Ms. Kamia Hardayani,

Human Resources Development Ms.Fumiko YAMADA

DGE : Mr. HS Bayu Anggoro, Primary Energy Analyst, Directorate of Electricity program Supervision

PLN: Mr. Arief Sugiyanto Assistant Engineer,

System Planning Div. Economic,

finance/Investment plan Ms. Yukiko UCHIYAMA DGE : Ms. Enita R Nainggolan PLN : Mr. M.Ikbal Nur

Environmental and Social Considerations Mr..Tsuyoshi SASAKA

DGE : Mr. Ilham Budi Sriutomo, Inspector of Electricity

PLN : Ms. Marina Kurniati,

Power System Planning Mr.Masahito SHIMAZAKI

PLN: Ms.Andi Darmawati,System Planning Div.



Final Report 2-1

Chapter 2 Present Situation and Challenges Concerning the Energy policies

2.1 Energy policy

(1) Policy on power development In light of the abundance of energy resources, such as oil, coal, gas, geothermal and hydropower,

Indonesia thought it possible to acquire foreign currency by exporting fossil fuel resources while meeting domestic demand for the resources. As for oil, however, in response to an increase in domestic demand and the stagnant growth of the output, Indonesia changed its past idea and began to regard it as a limited fossil fuel resource to be exported and to be used as essential raw material in the domestic production of industrial products. Accordingly, the country decided to diversify energy resources for the optimal and efficient use of energy and to reduce the depletion of fossil fuels.

The development of energy sources replacing oil is being promoted focusing on coal, which is available in a large amount at a low cost and expected to help the country obtain foreign currency through export while meeting domestic demand for the resource. As for fossil fuels, Indonesia is also rich in natural gas, but the supply area is far from the demand area and most of the resource is exported in the form of LNG.

Indonesia is also proactively introducing renewable energy based on its power source diversification policy, as described in the national energy policy (2004) and the president’s order (2006). In line with the policy, the development of geothermal energy and hydropower has been promoted, but the use of these power sources has not been fostered compared with the use of coal for thermal power generation, because of the smaller resource reserve, higher development cost and problems concerning locations.

As for the policies to decrease dependence on oil and diversify energy sources, the Indonesian government enacted the National Energy Policy in 2004, National Energy Management Blueprint in 2005, and the Executive Order on National Energy Policy in 2006. In August 2007, it enacted the Energy Law in order to legislate these policies and carry out a comprehensive energy administration.

1) National Energy Policy (KEN) (Ministerial ordinance, National Energy Policy 2003-2020: KEN, No. 0983, K/16/MEM/2004)

The National Energy Policy envisions assurance of the supply of energy sufficient to assure the national interest. Its main components are increase in the energy supply capacity, optimization of energy production, and energy conservation. It posts targets for the year 2020.


Final Report 2-2

Table 2.1-1 Outline of the National Energy Policy (KEN)

Targets - Electrification rate of 90% by 2020 - Increase in the share of the total energy supply occupied by renewable energy (excluding

large-scale hydropower) to at least 5% by 2020 - Decrease in energy consumption per GDP unit (i.e., energy intensity) by 1% annually - Reduction of dependence on overseas energy sources through expanded use of domestic

resources and effective use of domestic human resources Major measures

- Reinforcement of energy supply commensurate with national development and population growth

- Diversification of energy to achieve the best and most economical energy mix - Promotion of energy conservation

Source: National Energy Policy 2003-2020, 2004

2) National Energy Management Blueprint, 2005 – 2025 The National Energy Management Blueprint is based on the National Energy Policy. It presents

forecasts for primary energy supply and sets forth the evolution (roadmap etc.) of constituent energy technology to 2025. Figure 2.1-1 shows the targets for primary energy mix in 2025.

Oil, 26.2%

Gas, 30.6%

Coal, 32.7%

Hydropower2.4%

Geothermal3.8%

Micro hydropower0.216%

Bio fuel, 1.335%

Solar power, 0.020%

Wind power, 0.028%

Bio mass, 0.766%

Nuclear, 1.993%

Others4.4%

Figure 2.1-1 Scenario for optimization of the national energy mix in 2025

Source: National Energy Management Blueprint, 2005 – 2025

3) Executive Order on National Energy Policy (No. 5, 2006) The aforementioned National Energy Policy and National Energy Management Blueprint were

ordinances issued by the Ministry of Minerals and Energy Resources (MEMR). The purpose of promulgation as an executive order was to heighten their legal grounding. Numerical targets were revised upward with a view to promoting use of oil-alternative energy and renewable energy.


Final Report 2-3

Natural Gas 19%

Renewable Energy

7%

Oil53%

Coal21%

2004 Energy Mix

Natural gas30%

Oil20%

Coal33%

Liquiefied coal, 2%

, 0%Bio fuel

5%

Geothermal 5%

Others5%

Renewable Energy

15%

2025 Energy Mix

Figure 2.1-2 Targets for the primary energy mix in 2025

Source: Executive Order on National Energy Policy (No. 5, 2006)

4) Energy Law The Energy Law was enacted in August 2007. Laws and regulations had been enacted for

different types of energy separately (including oil and gas taken together, electrical power, and geothermal energy), but there was a need for enactment of a law to cover and interrelate all types, and to govern energy policy as a whole.

The Energy Law provided for institution of the National Energy Council (Dewan Energi Nasional; DEN). Formerly, national energy policy had been formulated by the National Energy Adjustment Committee (BAKOREN). DEN took over and expanded the functions of BAKOREN (BAKOREN was chaired by the MEMR minister, but DEN is headed by the president).

The National Energy Plan (RUEN) is drafted by the Ministry of Energy and Mineral Resources and enacted by DEN. The Energy Law shows the basic policies on the implementation of energy measures, and the details are stipulated by governmental ordinances and ministerial orders. In November 2009, the ordinance on energy conservation was enacted.

5) Policy regarding development of renewable energy Policy on renewable energy is stipulated in the National Energy Policy and the Executive Order on

National Energy Policy (No. 5, 2006). Subsequently, provisions were made for promotion of development by MEMR ministerial ordinance.

Under these provisions, the state electrical power enterprise Perusahaan Listrik Negara (PLN) buys power (including surplus power) from renewable energy power generation projects conducted by private enterprises, cooperatives, or other such entities. In 2006, the subject scale was expanded from the previous 1 MW to 10 MW. In 2009, the purchasing price was stipulated (by ministerial ordinance No. 31 of that year). For example, the price applied in the case of connection at low voltage on the island of Sumatra is (at least) Rp. 1,004 * 1.2 = Rp. 1,204.8 per kWh.


Final Report 2-4

Table 2.1.2 PLN purchasing prices for renewable energy (minimum)

Purchasing price (calculation formula) F: Incentive coefficient

Rp.656/kWh*F(Connection to the grid at medium

voltage)

Rp.1,004/kWh*F(Connection to the grid at low voltage)

Here, F (the incentive coefficient) is set separately for

each region.

F=1.0 Java-Bali

F=1.2 Sumatra, Sulawesi

F=1.3 Kalimantan, NTT, NTB

F=1.5 Maluku, Papua

Note: 1 yen = about 100 rupiah Source: MEMR ministerial ordinance No. 31, 2009

These provisions have the following advantages: 1) a standard power purchasing agreement (PPA)

is provided and has a simple content, and 2) the selling price is comparatively high. However, the following have been cited as problems: 3) the agreement term is not stipulated, and 4) PPAs are concluded with the local PLN office, and the procedures take considerable time.

The power sources covered by these provisions are mini or micro hydropower, geothermal energy, biomass, wind power, photovoltaic (PV) systems, and other types of renewable energy. As viewed from the standpoint of economic merit, the most promising are mini- and micro-hydro. In many locations, procedures are being performed for development by private firms. Power generation fueled with waste is also covered, and plans are being made for a plant utilizing gas derived from a waste disposal site (on the island of Java; arrangements are being made for purchase at Rp. 820 per kWh). The government is hoping for investment from other countries, but almost all investors are domestic. In addition to the drawbacks noted in 3) and 4) above, the main reason is thought to be the exchange rate risks.

The PLN supply cost varies with the region. In bigger systems, the cost is generally lower because of the bigger power sources and higher demand density. It also tends to be lower in southern Sumatra and northern Sulawesi, where there are many hydropower plants. Conversely, in smaller systems, cost is generally higher because there are more diesel generation systems and fuel costs are soaring. As a reflection of supply costs, too, purchasing prices are also higher in rural areas.


Final Report 2-5

Table 2.1-3 PLN supply cost (2008) (unit: Rp/kWh)

System BPP-TT （High-voltage）

BPP-TM （medium-voltage）

BPP-TR （low-voltage）

1 Northern Sumatra 1,891 1,984～2,158 2,308～2,603 2 Southern Sumatra 565 667～1,164 860～1,433 3 Bangka Belitung - 2,476 2,919 4 Western Kalimantan 2,315 2,546 3,145

5 Central and southern Kalimantan 1,148 1,611 1,998

6 Eastern Kalimantan 1,732 1,965 2,260 7 Northern Sulawesi 974 1,676 2,063 8 Southern Sulawesi 1,103 1,249 1,505 9 Maluku - 2,320 2,919 10 Papua - 2,526 3,192 11 NTB - 2,289 2,743 12 NTT - 2,433 3,072 13 Java-Bali 783 849～859 1,005～1,030

Source: MEMR data

(Circular by the Director of the Electrical Energy Utilization Bureau No. 269-12/26/600.3/2008)

(2) Policy on power development 1) Outline of the electricity sector

The Directorate General of Electricity at the Ministry of Energy and Mineral Resources takes charge of electricity-related matters in general and regulates and supervises the electric power industry. Other related governmental organizations include DEN, which is in charge of energy policies, the National Development Planning Agency (BAPPENAS), which formulates national development policies and promotes coordination between related governmental agencies, the State Ministry of State-Owned Companies, which manages and supervises state-owned companies, and the Ministry of Finance, which is engaged in budget management.

PLN supplies electricity across Indonesia except for some areas, as the state-owned electric power company, together with its subsidiaries including PT Indonesia Power (IP) and PT Pembangkit Java Bali (PJB), which were spun off from the power generation department of PLN, while also receiving power supply from independent power producers (IPPs). Figure 2.1-3 shows the electricity business-related organizations in Indonesia.


Final Report 2-6

Figure 2.1-3 Electricity-related organizations in Indonesia



Final Report 2-7

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Final Report 2-8

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Final Report 2-9

2) Electricity The Electricity Law was enacted in 2002. In the law, the principle of competition was adopted by

separating generation, transmission and distribution in competitive area (Java-Bali area). However, the "introduction of the principle of competition" was found to infringe Section 2 of Article 33 of the Constitution, which provides that "the national government will operate and manage those industrial sectors that exert useful effects of lives of peoples" and the Constitutional Court ruled that the Law was invalid. It abolition was followed by deliberation over a new such law, and a bill to this effect passed the national assembly on September 8, 2009.

The New Electricity Law basically follows the 1985 Electricity Law (No. 15, 1985) predating the 2002 Law. While having responsibility for power supply rest with the national government, it delegates a certain amount of authority to local governments, with consideration of policy for decentralization. There are also procedural differences. Formerly, the MEMR minister had the authority to approve the General National Power Plan (RUKN). Under the new law, however, the RUKN must be approved by the national assembly. Similarly, the national assembly's approval (or that of the local assembly for areas at local discretion) is now also required for power tariff revisions, which formerly only needed to be approved by the president.

Table 2.1-4 presents a comparison with the former law.

Table 2.1-4 Comparison of old and new Electricity Laws (amendment items)

Electricity Law No.15/1985 (old law)

Electricity Law No. 30/2009 (new law)

Power development plans

Formulation of the RUKN by the national government

Formulation of the RUKN by the national government, subject to approval by the national assembly. Formulation of RUKDs (local power development plans) based on the RUKN by local governments.

Project responsibility

Execution by the PLN under the control of the national government

Execution under the supervision of the national government, but division of responsibilities between national and local governments.

Project authorization

National government National goverment (except in provinces where grids do not span two or more provinces or regencies where grids do not span two or more regencies -- virtually national authorization in fact)

Project execution Execution by the PLN, but exceptional permission for execution by cooperatives in areas not reached by a PLN grid

Permission for execution by public corporations (such as those operated by the regency business bureau), private enterprises, cooperatives, and citizen groups as well as the PLN, but the PLN takes priority

Rural electrification

Execution by the PLN as a general rule, on the responsibility of the national government

Obligation for execution by the PLN when execution by public corporations, private enterprises, cooperatives etc. is impossible

Power tariffs Uniform nationwide, national (presidential) authorization

Setting of power tariffs by the national government upon approval by the national assembly; local governments may set power tariffs for their locale upon approval by the local assembly (i.e., power tariffs may differ depending on the area)

Source: JICA Study Team (based on the materials provided by the JICA expert to the MEMR)


Final Report 2-10

3) Outline of power development plans Power development plans consist of the aforementioned RUKN and RUPTL. Whereas the RUKN

is a master plan for power development based on national energy policy, the RUPTL is a plan for power supply by the PLN reflecting individual projects.

As a result of the 2009 amendment of the Electrical Power Law, the RUKN became subject to approval by the national assembly. As a result, the RUKN must undergo time-consuming deliberation in the national assembly, and has not been revised since 2008. The RUPTL, on the other hand, is a plan for PLN facilities and is prepared on a yearly basis. However, it is formulated in response to revision of the RUKN, and there have been years when new RUPTL editions could not be released because the RUKN was not revised. In September 2010, the PLN announced the 2010 edition of the RUPTL prepared by using the 2008 RUKN as a reference. Table 2.1-5 profiles the latest RUKN and RUPTL editions.

Table 2.1-5 RUKN (2008 edition) and RUPTL (2010 edition)

RUKN (General National Power Plan)

RUPTL (Electrical Power Supply Business Plan)

Formulating institution

Ministry of Energy and Mineral Resources (MEMR)

State power enterprise (PLN)

Outline of the plan The master plan for power development prepared by the national government, containing demand forecasts, primary energy outlooks, power plans, requisite funding, etc.; has a term of 20 years

The power supply plan prepared by the PLN based on the RUKN; has a term of 10 years

Updating Revised periodically (every year), but the last revision was in June 2006

After revision of the RUKN (prepared on the basis of the RUKN)

Latest revision Oct. 13, 2008 (officially promulgated on Dec. 23, 2008)

June 17, 2010 (officially promulgated on Sept. 6, 2010) Draft already created for RUPTL 2011

Source: JICA Study Team (based on the materials provided by the JICA expert to the MEMR)

4) Features of the 2008 edition of the RUKN (a) The forecast for demand growth is fairly high (annual average of 10.1 percent in the Java-Bali

system and 8.3 percent in other regions). As compared to the previous edition (2006), the forecast for power sold by the PLN in 2027 (in the Java-Bali system) is about 40 percent higher.

(b) Because of this high demand forecast, it is thought that power source development will be unable to keep pace with the demand, and that demand (new or expanded) unable to be connected to the grid because of this lag will total 6,000 MW. The RUKN also assumes that development will not proceed as planned.

(c) In the aspect of power development, the items of change from the 2006 edition are an active promotion of geothermal energy development and first-ever mention of utilization of liquefied natural gas (LNG). The geothermal share of the energy mix is to increase from 7 percent in 2008 to 12 percent in 2018. There are plans for utilization of LNG for middle- and peak-load sources.


Final Report 2-11

(d) The 2008 edition no longer makes mention of nuclear power development. This is presumably because it was decided that the year of start-up was no longer clear.

(e) Overall, it has become difficult to prepare power development plans encompassing the power mix due to the stipulations of the crash programs (for coal development by executive order) and the dependence of independent power producer (IPP) source development on investor inclinations (judgments).

(f) As a result, in the RUKN, the national role centers around demand forecasting and confirmation of resources. The plan sets forth the orientation for power development; the detailed plans for this development are left to the developers(PLN+IPPs).

5) Features of the 2011 edition of the RUPTL (a) The edition shows an electric power supply business plan for the period from 2011 to 2020,

including the first and second crash programs. Table 2.1-6 outlines the new power development plan for the Java-Bali system.

(b) As in the case of the RUKN, the demand forecast figures are on the high side. The RUPTL foresees demand growth averaging 8.5 percent annually (7.8 percent in the Java-Bali system) over the ten-year period ending in 2020. It predicts that the 2020 demand will reach 328 TWh, for a 2.25-fold increase from 2010, when it amounted to 145.7 TWh (actual figure).

(c) The RUPTL also calls for active promotion of rural electrification. It targets an increase in the electrification ratio from 66.5 percent in 2010 to 94.4 percent in 2020.

(d) This will require the development of 55.4 GW in additional capacity over the ten-year period toward 2020. (This is equivalent to 1.85 times the installed capacity of 30 MW in 2010.) Of the additional output, coal-fired power plants will account for 35.6 GW (64%). In the Java-Bali system, the additional output will be 32.1 GW, of which 22.6 GW or 70% will be provided by coal-fired power plants. Table 2.1-6 shows the power development plan for the Java-Bali system and Table 2.1-7 shows the supply-demand balance in the region. Of the output, 60% will be provided by PLN and the remaining 40% by IPPs (see Figure 2.1-7).

(e) In the second crash program, the development of renewable energy is planned, but as for the development of geothermal, it took longer time than expected for the resource survey, FS and fundraising. Accordingly, compared with the RUPTL of last year, the schedule is far behind. In hydropower development, focus will be placed on pumped-storage generation.

(f) The total amount of investment (PLN + IPPs) over the ten-year planning term is put at 96.2 billion dollars (for an average of 9.6 billion dollars per year). In the Java-Bali system, the ten-year investment will total 49.8 billion dollars for PLN and IPPs and amount to 33.6 billion dollars for PLN alone.


Final Report 2-12

Table 2.1-6 Power development plan for the Java-Bali system

unit：MW

Source: RUPTL 2011- 2020


Final Report 2-13

Table 2.1-7 Power supply-demand balance in the Java-Bali system

Source:RUPTL2011-2020


Final Report 2-14

Figu

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Final Report 2-15

Figure 2.1-7 Power development scheme

Source:RUPTL 2011-2020

Figure 2.1-8 Investment required for electricity (nationwide)

Source:RUPTL 2011-2020


Final Report 2-16

6) Outline of crash programs Crash programs are aimed at accelerating development of power stations not fueled with oil, in

order to relieve the tightness in the power supply. The first crash program was announced in 2007 by executive order. It was to run until 2009, but the terminal year was changed to 2014, and plant construction is still continuing.

The second crash program was prepared on the heels of the first. The size of power source development is the same as that of the first program at 10,000 MW, but the second crash program focuses on the introduction of renewable energy, in particular on the development of geothermal and hydropower. Nonetheless, coal-fired power generation will continue to be an important power source both in terms of the power generation cost and the development size and will account for 34% of the total. The second program is also different from the first one in that a half of the amount will be developed by IPPs.

The two programs likewise differ from each other in respect of formulation background, types of source, and development method. Table 2.1-8 compares the two.

Table 2.1-8 Comparison of the first and second crash programs

First crash program Second crash program Planning term 2006-2009(2014) 2010-2014 Development method

PLN 100% PLN 50.4%（47.8%） IPP 49.6%（52.2%）,Figures in () are revised

Amount of capacity to be developed

About 10,000 MW (Java-Bali: 6,900 MW, Other regions: 3,100 MW)

10,153 MW (9,522 MW) (Java-Bali: 5,770 MW (5,515 MW), Other regions: 4,383 MW (5,007 MW)

Background (purpose)

Urgent power source development Reduction of dependence on oil

Urgent power source development Power source diversification Expanded input of renewable energy

Types of power source

Coal 100% Renewable energy: 51% (54%) (geothermal 39%(42%), hydro 12%(13%)) Fossil fuel breakdown：49% (46%) (coal 33%(36%)、gas 16%(10%）)

Legal grounding

Executive order (No.71 /2006) Executive order（No.4/2010） MEMR ministerial ordinance (No.2/2010) Revision based on MEMR ministerial ordinance (No.15/2010)

Requisite funding

Power sources: USD 8 billion Power sources: USD 16 billion Transmission facilities: USD 400 million

Source: JICA Study Team (based on the materials provided by the JICA expert to MEMR)

7) Development under the First Crash Program According to the first crash program, about a total of 10,000 MW coal-fired power plants were

planned to be newly established by 2009, with EPC contractors raising 85% of the fund through export credit and the remaining 15% provided by PLN. Because of various factors, however, such as delays in fund raising and local situations, the plan is behind the schedule. Against the planned completion in 2009, the No.1 unit (300MW) of the Labuan power plant started operation in 2009 and the No.2 unit (300MW) of the same plant started operation in 2010. Subsequently in 2011, the


Final Report 2-17

No. 8 unit of the Suralaya power plant（625MW）, the No.1 unit of the Lontar power plant (315 MW), the No.1 to No. 3 units of the Indramayu power plant (990MW in total) and the No.1 and No.2 units of the Rembang power plant (630MW in total）started operation. Table 2-1-9 shows the progress with the development.


Final Report 2-18

Table 2.1-9 Development under the first crash program

Project Name Capacity (MW) Operation Year

PLTU 2 in Banten (Labuan) 2x315 2009-2010

PLTU in North Jabar (Indramayu) 3x330 2010

PLTU 1 in Banten (Suralaya Unit 8) 1x625 2010

PLTU 3 in Banten (Lontar) 3x315 2010-2011

PLTU in South Jabar (Pelabuhan Ratu) 3x350 2011

PLTU 1 in Central Java (Rembang) 2x315 2010

PLTU 2 in Central Java (PLTU Adipala) 1x600 2014

PLTU 1 in East Java (Pacitan) 2x315 2010-2011

PLTU 2 in East Java (Paiton Unit) 1x660 2010

PLTU 3 in East Java (Tanjung Awar-Awar) 2x300 2013

PLTU in NAD (Meulaboh) 2x110 2012

PLTU 2 in North Sumatra (Pangkalan Susu) 2x220 2011-2012

PLTU 1 in Riau (Bengkalis) 2x7 2012

PLTU 2 in Riau (Selat Panjang) 2x5 2012

PLTU in Kepulauan Riau (Tanjung Balai) 2x7 2010

PLTU 4 in Bangka Belitung (Belitung) 2x16.5 2011

PLTU 3 in Bangka Belitung (Air Anyer) 2x300 2010-2011

PLTU in West Sumatra ( Teluk Sirih) 2x112 2011-2012

PLTU in Lampung (Tarahan Baru) 2x110 2011-2012

PLTU 1 in West Kalimantan (Parit Baru) 2x50 2012

PLTU 2 in West Kalimantan (Pantai Kura-Kura) 2x27,5 2012

PLTU 1 in Central Kalimantan (Pulang Pisau) 2x60 Retender

PLTU in South Kalimantan (Asam-Asam) 2x65 2011

PLTU 2 in North Sulawesi (Amurang) 2x25 2010-2011

PLTU in Gorontalo 2x25 2011

PLTU in North Maluku (Tidore) 2x27 2011

PLTU 2 in Papua (Jayapura) 2x10 2011

PLTU 1 in Papua (Timika) 2x7 Retender

PLTU in Maluku (Ambon) 2x15 Retender

PLTU in Sulawesi Tenggara (Kendari) 2x10 2010

PLTU in South Sulawesi (Barru) 2x50 2011

PLTU 2 in NTB (Lombok) 2x25 2011

PLTU 1 in NTT (Ende) 2x7 2010

PLTU 2 in NTT (Kupang) 2x15 2011

PLTU 1 in NTB (Bima) 2x10 2011 Source: RUPTL 2010 - 2019


Final Report 2-19

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Pla

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Final Report 2-20

8) Optimal power source mix to 2025 (Java-Bali system) By utilizing the WASP-IV simulation tool, which is also used for RUPTL preparation, an

optimal power source mix is studied for the period from 2021 to 2025 in Java-Bali system examination to determine the optimal plan for power source makeup up to 2025 in the Java-Bali system. The optimal plan is one which holds the total cost, including the fuel cost and operating cost, to the minimum while taking account of the generation facility operating cost characteristics, unplanned outage rate, and other factors related to the anticipated value for output (i.e., the least cost method). It should be noted, however, that the study also considered the need for development of geothermal sources in line with policy for promotion of renewable energy. Table 2.2.8 shows the conditions applied in the simulation.

Table 2.1-10 Calculation conditions

Type of Primary Energy Price Calorofic Value

Coal - Sub Bituminous USD 80/Ton 5.100 kcal/kg

Coal - Lignite USD 50/Ton 4.200 kcal/kg

Coal - Lignite at Mine Mouth USD 35/Ton 4.200 kcal/kg

Natural Gas USD 6/MMBTU 252.000 kcal/Mscf

LNG USD 10/MMBTU 252.000 kcal/Mscf

HSD( HighSpeed Diesel) USD 0,62/Liter 9.070 kcal/l

MFO(Marine Fuel Oil) USD 0,48/Liter 9.370 kcal/l

Geothermal Steam (does not affect the result of planning simulationas these plant are treated as fixed plants )

Source: PLN data

Coal-fired plants account for 86.7 percent of the 15,000 MW in newly added capacity required over the five-year period from 2021. Together with geothermal capacity, this coal-fired capacity will handle the base-load and part of the middle-load supply. The peak-power and rest of the middle-load supply will be provided by gas-fired plants, pumped storage hydropower plants, and conventional hydropower plants.


Final Report 2-21

Table 2.1-11 Estimated optimal power source in Java-Bali system (2021-2025)

unit：MW Generation Year 2021 2022 2023 2024 2025 2020-2025

Development 3,000 2,000 3,000 2,000 3,000 13,000

Total 28,171 30,171 33,171 35,171 38,171 86.70%

Development 0 0 0 0 -170 -170

Total 12,551 12,551 12,551 12,551 12,381 -1.1%

Development 0 0 0 0 0 0

Total 229 229 229 229 229 0%

Development 330 330 330 330 330 1,650

Total 4,351 4,681 5,011 5,341 5,671 11.00%


Total 2,597 2,597 2,597 2,597 2,597 0%


Total 2,968 2,968 2,968 2,968 2,968 3.50%

Development 3,850 2,330 3,330 2,330 3160 15,000

Total 50,867 53,197 56,527 58,857 62,017 100%

Hydropower

PompedStorage

Total

Coal

Gas

Diesel

Geothermal


(3) Coal policy As of 2010, the recoverable coal reserves in Indonesia is confirmed to be 5,530 million tons, which

is approx. 0.6% of the world's total volume. It produces 306 million tons of coal and is ranked sixth among the world's largest coal producing nations. With an export volume of 298 million tons, Indonesia is the second largest coal exporter and the No.1 steam coal exporter in the world. Up until 2008, Japan was the largest importer of Indonesian coals. However, due to the increase in exports to India, China, and South Korea, Japan has moved to the fourth place since 2009. Still, Indonesia is the No. 2 coal exporter to Japan following Australia, and accounts for 20% of Japan's total coal import. Coal import from Indonesia to Japan has doubled over the last decade. Currently, 97% of all coal produced in Indonesia is exported to overseas countries. However, as the Indonesian government implemented coal-centered energy policies and plans to construct more coal-fired power generation plants to meet growing domestic demand for electricity, an increasing volume of Indonesian coal will flow into the domestic market. Therefore, it will become more important to ensure an effective use of coal resources.

The 1945 Constitution of the Republic of Indonesia provides for the nation's mineral resources (including coal), in Article 33, item 3. The provision states as follows: "The land and the waters as well as the natural riches therein are to be controlled by the state to be exploited to the greatest benefit of the people." To implement the provision, the "Law Number 11/1967 on the Basic Provisions of Mining" (Mining Law) was promulgated. For the following period of approx. 40 years, coal and other mineral mines were developed and operated under the Law, until the "Law No. 22/1999 Regarding


Final Report 2-22

Regional Governance" was enforced to promote decentralization of power. The Mining Law, which was based on centralized government power, needed to be amended. Moreover, two laws enforced after the Regional Governance Law, i.e. the Forestry Law (No. 41, 1999) and the Investment Law (No. 25, 2007), contained provisions pertaining to the development and operation of mineral mines. In addition, the "Presidential Order No. 5 of 2006 about National Energy Policy" stated that, by 2025, coal should become the primary source of energy and account for 33% of the nation's total energy supply. The new Mining Law was enacted as the Law No.4 of 2009 (officially, Law No.4 of 2009 on Mineral and Coal Mining) to ensure alignment with these relevant laws and regulations and to cope with domestic/international issues and changes. The new Law represented a significant shift in Indonesia's coal policy, from the previous contract of work system (Contract of Work: CoW, for mineral mining, and Coal Contract of Work: CCoW for coal mining) to the license system. Currently, the nation's coal policies are implemented under the new Law.

The following sections describe the outline of the new Mining Law and key coal policies.

1) Background of the New Mining Law (a) There were increasingly strident voices calling for an amendment of the Mining Law among

those who argued that the nation's resource riches were being transferred to foreign capital rather than its people;

(b) There were discrepancies between the concept of the Regional Governance Law of 1999, and that of the still-centralistic former Mining Law.

(c) The former Mining Law lacked provisions addressing socially-controversial issues, such as post-mining environmental restoration, co-existence between protected forests and mining sites, and sanctions against unauthorized mining.

(d) In the face of dramatically decreasing mining investments since 1998, Indonesia was urgently required to improve its investment environment.

2) Features of the New Mining Law (a) Mining Areas and Licenses

(i) The CCoW (contract of work between the Indonesian Government and a company) was abolished and the "Mining Business License" (Izin Usaha Pertambangan: IUP) was introduced for companies and individuals. This represented a shift from the contract system to the license system. At the same time, the "Special Mining Business License" (IUP Khusus: IUPK) was also introduced to protect certain resources that benefit the national interest. State- and region-owned companies are prioritized for IUPKs.

(ii) The Traditional Mining License (Izin Pertambangan Rakyat: IPR) was newly established to allow residents living near a mining area to run mining businesses with simple equipment. IPR is similar to former cooperatives and may be considered a measure responding to illegal mining.

(iii) A mining license is granted in two phases, one for exploration and the other for production-operation.


Final Report 2-23

Exploration License (IU Eksplorasi): Performance of general survey and exploration including FS. Maximum license term for coal: 7 years. Exploration of 5,000 ha–50,000 ha.

Production-operation License (IU Produksi): Construction, mining, processing, refining, hauling, and selling. The license term for coal is 20 years and extendable twice, each for 10 years. Mining area for production: max.15,000 ha.

As a result of decentralization, license is granted not only by the Minister but also by governors, regents, and mayors.

Exploration License: License is issued by the Minister, governor, regent, or mayor. However, if the impact of the mining business on the environment is expected to:

be nationwide — the grantor must be the Minister; be regional — the regent or mayor; cover more than one regency — the governor; cover more than one province — the Minister.

Production-Operation License: The grantor must be the Minister, the governor, regent, or mayor. It should be in line with the exploration license.

Foreign investment companies wishing to apply for a mining license application can do so by establishing an Indonesian legal entity (a PT PMA).

Figure 2.4-1 below illustrates relationships between mining areas and licenses.


Final Report 2-24

Classific

ation

IUP

Mining Business License

IUPK

Special Mining Business

License

IPR

Traditional Mining License

License Permit

IUP Exploration / IUP Production-Operation

IUPK Exploration / IUPK Production-Operation

Licensee Indonesian legal entity, Natural person

Indonesian legal entity, State- and Region owned companies

Individuals, Residents Group, Cooperative

Licenser Local Government (in principle) Central Government Governor of prefecture or

City mayor

Term Exploration 7 years, Production-Operation 20 years (can be prolonged 2 ×10years)

5 years

Area (Max) Exploration 100,000ha, Production-Operation 25,000ha

Individuals: 1ha Residents group: 5ha Cooperation: 10ha

Figure 2.1-10 Mining area, License permission, term etc. in New Mining Law

(b) Operator's Obligations

Mining business operators are obliged, in the course their mining business, to perform: A) related community development, B) environmental measures, C) filing of reports with the government, D) adding value to the mining products, and E) the divestment of capital.

(i) A reclamation and post-mining plan must be prepared and submitted before obtaining an IUP/IUPK.

(ii) An operator must give priority to hiring local workers and local employment.

(iii) An operator must submit its working plan, all information derived from the production activities, and a performance report to the relevant authority (the Minister, governor, regent, etc.) on a periodic basis.

WUP (Mining Business Zone) WPN (Small Scale Reserve Zone)

WUPK (Special Mining Business Zone)

IUP (Mining Business License)

IUPK (Special Mining Business License)

WPR (State Reserve Zone)

IPR (Traditional Mining

License)




IUPK (Special Mining Business License)

IPR (Traditional Mining

License)

WP (Mining Area)


Final Report 2-25

(iv) An operator must add value to its mineral and coal products by carrying out in-country refining and processing.

(v) After 5 years of production, a foreign shareholder (if any) of an IUP/IUPK holder must divest part of its shareholding to the government, regional government, state-, region-, or private-owned business entity.

(c) Sanctions

Investigative authority is given to the police and public officers in charge of the mining industry. Penal provisions responding to the degree of violation are provided and are applied also to business entities. The penal provisions of the former Mining Law were not strictly applied because the provisions did not suit the actual situation. The new Mining Law has detailed penal provisions.

(d) Taxation

Under the former bill, taxation was fixed once it was determined, similar to the CoW/CCoW system. Under the new bill, the current Law is applied from time to time.

The taxes and other payments that license holders are required to pay includes, as shown in Figure 2-4-2 below, state taxes (corporate income tax, customs duty, indirect taxes), non-tax state levies (fees and royalties), and regional taxes. Additionally, IUPK holders are subject to profit sharing at the rate of 10% of net profit once production starts. This payment will be allotted to the central government (4%) and local governments (6%) including the provincial government (1%), the regency where the mining area is located (2.5%), and other regencies within the same province (2.5%).

Taxes under the government's authorityTaxes

Import and customs dutyState revenue

Dead rentExploration royalty (levy)

Contributions to state/regional revenues

Otherlevies Production royalty (levy)

Funds from mineral & coal profits(if specified under CoW)Compensation for information/data(if specified by CoW)Profit (product) sharing

Regional taxRegional revenue Retribution

Other valid revenues in accordancewith laws and regulations

Figure 2.1-11 Taxes and other Levies on Mining


Final Report 2-26

(e) Production and Export Controls

For the sake of maximum public and national interest, the central government is authorized to control production and export of mining products by kind and by province and thereby is able to prioritize supply to the domestic market.

The New Mining Law was enacted to reflect decentralization under the Regional Governance Law and the environmental protection and mining area restrictions under the Forestry Law and the Investment Law. Despite several issues remaining to be solved, the Law forms the basis of Indonesia's coal policy the purpose of which is to control coal resources as a national asset and maximize the various benefits available to the state from the mineral. The Law aims to foster sustainable mining by ensuring: A) stable supply of coal (the nation's primary source of energy) to the domestic market, B) increased tax and other national revenues, C) environmental control, D) development of neighboring local community, E) creation of job opportunities, and F) transfer of resources to the next generation. It states that the above is to be achieved by: A) shifting the coal production framework from the contract of work system to the license system, and B) exerting control over the data and information concerning exploration activities, production performance, and work plan.

After the enforcement of the New Mining Law, government regulations and ministerial regulations on details of mining business activities, designation of mining areas, domestic market obligations, coal benchmark price, etc. were issued during the 2009–2010 period implementing the coal policies based on the New Mining Law.

3) Domestic Market Obligation (DMO) One of the most heatedly argued coal policies among those implemented pursuant to the new

Mining Law were the DMO regulations (Regulation of the Minister of Energy and Mineral Resources, No. 34 of 2010). Under the DMO regulations, coal producers are required to prioritize the domestic market with regard to the supply of coal.

The time the bill of the new Mining Law was presented and deliberated was when Indonesia's coal export increased because of a sharp rise in the oil price and increasing coal demand from China and other Asian countries. Meanwhile, in Indonesia, the government had introduced its new energy policy that aimed to shift its future energy source from oil to coal; and plans to build new coal-fired power plants were underway also as a crash program to meet the increasing domestic electricity demand. Indonesia's existing coal-fired power plants sometimes faced insufficient coal supply because their purchase prices were lower than the export prices. The DMO policy was adopted to ensure that the coal-fired power plants, the largest consumers of domestic coal, are supplied with a sufficient volume of coal also in the future.

Under the DMO regulations, coal companies are obligated to assist the stable domestic supply of coal and are entitled to export coal only when it has met the domestic coal demand. The DMO procedures are performed in the following manner:

(a) The domestic coal demand and production volume are determined.


Final Report 2-27

(b) The Minister of Energy and Mineral Resources develops DMO policies and determines the Minimum Percentage of Domestic Coal Sales (MPDCS), which is called, in Indonesian, "Prosentase Minimal Penjualan Batubara Dalam Negeri (PMPBDN)" and issues a decree. Each coal company is obligated to comply with its MPDCS.

(c) Coal companies supply coal in accordance with their MPDCS on a quarterly basis and the government monitors their execution.

(d) If a coal company fails to meet its MPDCS in any particular quarter, it is required to make up any shortfall in the following quarter. If the company is unable to fulfill its MPDCS obligation for the year, it will be subjected to sanction.

For 2009, the DMO was set at 68 million tons (17.02 million tons average per quarter) based on the projections obtained from coal users in such industries as power generation and cement. It was allocated to each coal company, according to its business size, at the time of approval of its budget and work program.

The quality of coal supplied by a coal company based on DMO varies depending on the mine and may differ from the quality required by PLN (state electricity firm). Accordingly, a company producing high quality coal that does not meet PLN's quality requirement may ask another coal company that has the required quality coal to substitute for it. If electric consumption increases and coal production reaches its limit, all coal exports could be stopped and diverted to domestic use because of domestic prioritization through DMO.

4) Coal Price Reference In addition to the DMO, a new coal policy called Indonesian Coal Price Reference (ICPR), or in

Indonesian, Harga Batubara Acuan (HBA), was introduced under Regulation of the Minister of Energy and Mineral Resources, No. 17/2010.

HBA's purposes are:

(i) optimizing the state revenue from coal,

(ii) providing a reference for producer and consumers, especially domestic consumers, and

(iii) supporting a secure supply of coal to the domestic market

As a higher degree of unification of coal prices (relative to their quality) is achieved through HBA, supplying coal domestically is to become as attractive as exports for coal companies. By setting a de facto standard price common to the domestic and export markets, HBA allows the Indonesian government to prevent the decrease of state revenue collected as royalty (typically, 13.5% of coal sales price) due to dumping. Thus, the main purposes of HBA for the government are (i) and (iii) above.

(a) HBA Setting Procedures

HBA is determined monthly, based on a simple average of the four international price indices, ICI-1 (Indonesia Coal Index-1), Platts-1, and two Australian indexes (the Global coal Newcastle index and the Newcastle Export Index). First, the price is calculated for primary coal with a gross


Final Report 2-28

calorific value (GCV) of 6,322 kcal/kg (gross as received: gar), total moisture content of 8%, sulfur content of 0.8%, and ash content of 15%. Then, using the primary coal price, prices of eight brands of benchmark coal (differing in calorific value) are derived. These benchmark coals are called HBP (Harga Patokan Batubara). The HBA prices are announced monthly by the Ministry of Energy and Mineral Resources.

Table 2.4-1 shows the eight benchmark coal brands with their properties and prices as of February 2012.

The price of primary coal (HBA) as of February 2012 was US$119.03/t. The prices of benchmark coal (HBP) No.1–No.7 are calculated using the following formula: Benchmark coal (HBP) price ＝ (Primary coal price × K × A) − (B + U) K: HBP calorific value/6322* A: (100 − HBP total moisture content) / (100 − 8*) B: (HBP total sulfur content − 0.8*) × 3 U: (HBP ash content − 15*) × 0.3 *Values indicate properties of HBA coal. "A" in the formula above is changed as follows for HBP No. 8: A: (100 − HBP total moisture content) / (100 − 8/FKA) FKA: (((100 − 8)/(100 − HBP total moisture content)) × 100 – HBP total moisture content) ＋ (100 - 8))/100

Prices of other types of coal are calculated based on the HBP price that correspond to their calorific value and adjusted by a formula that uses calorific value, total moisture content, total sulfur content, and ash content as coefficients. Currently, prices are calculated for 64 brands of Indonesian coal. The formula is to be reviewed on an annual basis. Initially, HBP was set for coal that had a calorific value of at least 3,750 kcal/kg (moisture content: 42%). However, as lower grade coal were increasingly traded in the market, additional HBP prices were introduced in April 2010 for coal with 3,500 kcal/kg (moisture content: 43.4%) and 2,995 kcal/kg (moisture content: 50%).

Table 2.1-12 Quality and Prices of HBP

No Coal Brand Calorific Value (Kcal/kg, GAR)

Total moisture (%, AR)

Total sulfur (%, AR)

Ash (%, AR)

Price (Feb. 2012) (US$/ton)

1 Gunung Bayan 1 7,000 10.0 1.0 15.0 128.13 2 Prima Coal 6,700 12.0 0.6 5.0 125.46 3 Pinang 6150 6,200 14.5 0.6 5.5 113.09 4 Indominco IM East 5,700 17.5 1.6 4.8 97.0 5 Melawan Coal 5,400 22.5 0.4 5.0 91.25 6 Eivirocoal 5,000 26.0 0.1 1.2 84.04 7 Jorong J-1 4,400 32.0 0.3 4.2 67.77 8 Ecocoal 4,200 35.0 0.2 3.9 61.40


Final Report 2-29

(b) Application of HBP (Royalty Calculation)

One of the objectives of the HBA system is to prevent the decrease in royalty, which is collected as state revenue and typically set at 13.5% of coal sales price, because of dumping.

For prices contracted with users, HBP is used as a reference; but it does not have binding power over prices contracted in the market. However, HBP serves as the floor price for government’s royalty calculation. For example, if the actual sales price is below HBP, the royalty is calculated based on HBP. If the actual sales price is higher than HBP, the royalty is calculated based on the actual sales price. In contrast, taxes are calculated based on the contract price.

To monitor coal companies' compliance with the HBA system, the government makes them submit monthly reports detailing sales price, sales volume, buyers, etc., together with underlying contracts and other supporting documents.

If a company fails to meet the HBA standard, it will be subjected to sanctions in the form of:

(i) written warnings (up to three times),

(ii) temporary suspension of shipment and selling activity of up to three months (in case of receipt of three or more written warnings), and

(iii) revocation of license (if it fails to correct within a temporary shipment and selling suspension period of three months or more).

5) Requirement for High Added-Value Based on the New Mining Law, the Indonesian government enforced various government

decrees and regulations. It is now preparing to release another important regulation on the requirements for high value-added minerals and coal products. Article 102 and 103 of the New Mining Law state that a mining business license holder shall be required to increase the added value of mineral and/or coal resources and carry out processing and refining of the mining product inside the country, and that further provisions shall be stipulated by government regulations. Article 170 of the Law provides for that the processing and refining shall be performed no later than 5 years from the promulgation of the Law (i.e., by 2014).

According to the provisions above, the Ministry of Energy and Mineral Resources developed a regulation to require high value-added mineral resources. On February 6, 2012, a ministerial decree (Regulation of the Minister of Energy and Mineral Resources, No. 7/2012) was issued regarding an increase in the added-value of mineral resources. Under the ministerial regulation, mineral resources must be refined and processed so as to possess a certain level of purity, and are prohibited from being exported on and after May 6, 2012, unless such level of purity is satisfied. However, in light of the limited availability of refining facilities, the Ministry indicated that mining business license holders who have satisfied certain conditions (e.g. filing of a refinery facility construction plan) would be allowed to export on condition of a 20% export tax.

Originally, coal was included in the scope of minerals subject to the decree. However, because of the difficulties in determining a calorific value that can be used as a benchmark and the absence of commercially-available calorific value enhancing technologies, the Ministry is considering the


Final Report 2-30

establishment of a special decree for coal, separately from other minerals. The benchmark calorific value under consideration is in the range of 5,100 – 5,700 kcal/kg (air-dry basis). In the case of not satisfying the benchmark, such coal is prohibited from being exported unless its calorific value is increased by the use of upgrading technologies, etc. The Ministry is also considering introducing an export duty, similarly to other minerals, at 25% for exports in 2012 and 50% for those in 2013.

In 2007–2008, coal demand from India and China started to increase. As a result, exports from Indonesia to India and China increased sharply by 200% and 500%, respectively, during the period from 2008 to 2010. As the increase was observed mainly in the low calorific-value coal, Indonesia is currently working to increase the production of low-rank coal and accelerating the development of low-rank coal mines. If the regulation bans export of low calorific-value coal, such type of coal will be diverted to the domestic market. However, most of the low calorific-value coal does not satisfy the criteria set by PLN's power generating stations, and therefore can be used only to a limited extent at such existing stations. To avoid this, it would be necessary to introduce drying technologies to existing stations and Clean Coal Technologies (CCTs) to newly built stations. The application of CCTs will make it possible to utilize low-rank coal. In addition, if India and China hope to replace low-rank coal with high calorific-value coal (i.e. sub-bituminous coal and bituminous coal), it will cause steam coal market turmoil and price hike problems, which may affect steam coal importers including Japan and South Korea. On the other hand, in an attempt to meet increasing demand for low calorific-value coal, coal companies and financial institutions are actively investing in the development of new mines and production capacity enhancements. However, if the regulation imposes an export ban on the low-rank coal, it will discourage new developments and investments and thereby drag down Indonesian coal production as a whole. The regulation will therefore have an impact on a range of sectors.

6) Export Potentiality of Coal The New Mining Law states that the national interest should be given the highest priority with

respect to the use of coal and other mineral products. To comply with the Law, the Indonesian government implemented policies that prioritize domestic use, such as the aforementioned DMO, HBA, and requirement for the high added-value coal. As a result, Indonesian coal exports became susceptible to the balance between the coal production volume and domestic coal demand. At present, domestic demand remains at a low level, allowing a large volume of coal exports. However, in the future, the construction of new coal-fired power stations will boost domestic demand, and consequently reduce the volume of coal exports. Some expect that domestic coal demand will exceed exports by 2020 to 2025. If this expectation materializes, it will have a significant impact on Japan, which is a large importer of Indonesian coal.

With regard to the domestic market, the Indonesian government implemented a policy to promote effective use of the low-rank coal, which accounts for a major part of the country's coal resources. On the other hand, Japan has a policy to ensure stable coal supply by encouraging high-efficiency coal-fired power generation, promoting the CCT technologies across the world for further reduction in carbon dioxide emissions, and establishing a better balance between energy


Final Report 2-31

supply and demand through the multipurpose utilization of lesser-used low-rank coal. Based on this policy, Japan has developed advanced CCTs such as Ultra Super Critical (USC) technology, as well as high value-adding technologies to gasify and improve the quality of low-rank coal. If Japan offers such technologies to Indonesia and cooperates in developing the county's infrastructure, it will contribute to the improvement of coal utilization efficiency, which is expected to result in curbing coal consumption and increasing coal production capacity, and consequently prevent Indonesia's coal export potential from being undermined and thereby provide a basis for stable coal supply to Japan.

7) Environmental Measures in Coal Development and Production Indonesia's Environmental Protection and Management Law (Law No. 32/2009), Government

Regulation No. 27/1999 on Environmental Impact Assessment, and the Regulation of Ministry of Environment No.11/2006 on the Type of Business and/or Activities that Require AMDAL require mining license holders to carry out an environmental impact assessment (AMDAL: Analysis Mengenai Dampak Lingkungan) and obtain approval before executing the development and production of coal. Details of the environmental impact assessment process based on the AMDAL and major laws pertaining to the process and space planning are described in the subsequent Chapter 3 "Environmental and Social Considerations". The environmental impact assessment includes development of an environmental impact assessment report, environmental management plan, and an environmental monitoring plan. The Indonesian government also released, as a guideline concerning coalmines, the Regulation of the Minister of Energy and Mineral Resources (No. 1453 and 1457/2000).

Furthermore, the government enacted legislation concerning air (Government Regulation No. 41/1999 on Preventing Air Pollution), water quality (Government Regulation No. 82/2001 on Controlling Water Quality and Preventing Water Quality Degradation), and noise (Decree of Ministry of Environment No. 48/1996 on Noise Standard). Legislation enacted by provinces and regencies governing particular mine areas should also be adhered to.

In addition, coal mines are subject to the Decree of Ministry of Environment No. 113/2003 on Effluent from Coal Mining Activities, which is designed to prevent possible impact on general society as a result of disposal of wastewater into rivers and other waterways. (Coal mining has less serious impact on air and noise quality because of its method of production and distance between mining areas and residential districts.)

The Decree requires coal mine operators to: a) check the level of pH in the wastewater; b) record the volume of wastewater on a daily basis; c) analyze the wastewater quality on a monthly basis, d) record these data on a quarterly basis; and e) file a report on the results of analyses. Water quality audits are conducted by the Regional Environmental Impact Agency or other state government bodies. Wastewater sampling points for the monthly wastewater analysis are designated by the Agency, and the sampling process is observed in person by the Agency's inspector. (Inspectors from the Ministry of Environment also witness the process on an irregular basis.) The samples


Final Report 2-32

collected are analyzed by institutions designated by an independent organization (National Accreditation Body of Indonesia) or institutions authorized by the governor.

Coal mines are also subject to the Government Regulation No. 78/2010 on reclamation and mine closure, and required to carry out environmental restoration procedures.

2.2 Climate Change policies

(1) Climate change policies of the Indonesian government Indonesia ratified the Kyoto Protocol in December 2004, and established the National Commission

for Clean Development Mechanism (CDM) as the Designated National Authority (DNA) under the Ministry of Environment (MOE). The Commission later came to be under the National Council for Climate Change (DNPI), which was established under the direct supervision of the President.

Its commitment was accelerated prior to the COP13 held in Bali sponsored by the Indonesian government, and 75 out of total of 4,008 registered CDM schemes have been UN approved (7th in the world, accounting for 1.87% of total)3.

In 2007, the Ministry of Environment announced the "National Action Plan Addressing Climate Change." The plan warned that the CO2 emissions by the energy sector will reach 1.2 billion tons by 2025 in BAU scenario, and stated that reduction in CO2 emissions through energy conservation, introduction of new energy sources such as nuclear and geothermal power generation, as well as CCS (Carbon Capture and Storage) was urgently needed. In the Action Plan, mid-term (2012-2015) goal of reduction of 30% against BAU, and long-term (2025-2050) goal of 50% against BAU have been set for the energy sector.

At the G20 Pittsburgh Summit held in September 2009, President Yudhoyono announced a goal of reducing GHG emissions by 26% against BAU by 2020, and 41% with support from the international community. Following this statement by the President, the Government of Indonesia submitted to the UNFCCC in January 2010 a document announcing a voluntary target of 26% reduction in relation to NAMAs4.

Since the figure of 26% came up first before it went through a comprehensive expert reviews, the government took swift action by conducting such reviews to ensure the forthcoming reduction actions toward materialization of the announced target5. . In March 2010, the "Indonesia Climate Change Sectoral Roadmap (ICCSR)" was announced as an input for the Medium-term Development Plan (RPJM) 2010-2014 concerning climate change. The ICCSR indicated four scenarios, i.e. “base case”, “RUPTIL”, “without nuclear power”, and “with nuclear power”. While it was highlighted that the coal fired power generation is one of the major source of GHG emissionss, the efficiency of coal-fired power generation was yet to be discussed.

The government submitted the Second National Communication to UNFCCC in November 2010,

3 Baseed on UNFCCC Secretariat data as of April 16. 4 Nationally Appropriate Mitigation Action for developing countries. 5 Information gathered from interviews with various Indonesian officials in charge of climate change.


Final Report 2-33

reflecting the result of these reviews. Based on the document, BAPPENAS initiated preparation of the National Action Plan for Green House Gas Emissions Reduction; RAN-GRK, which was enacted and became effective as Presidential Regulation No 61/2011 as of September 20, 2011. RAN-GRK is defined as the basic law for Indonesia’s NAMAs while RAD-GRK (“D” stands for region while “N” stands for nation) that is in preparation is the basic law for regional mitigation actions in compliance with the directives in RAN-GRK. BAPPENAS has been in close communication with the relevant local governments and promoting support for preparation of specific plans based on the RAD-GRK Preparation Guideline6 which had been prepared prior to the enactment of the regulation.

While setting of voluntary reduction targets have been initiated by BAPPENAS and completed through RAN-GRK and forthcoming RAD-GRK, implementation of actual coal power projects is with PLN under supervision by DGE. PLN now plans to implement such coal power projects with CO2 emissions reduction efforts in scope, especially those on large scale. Such efforts are to be supported by the relevant government institutions through their policy instruments.

(2) Measures against climate change by the Indonesian government and policy related organizations

In Indonesia, Ministry of Environment has long played a key role on measures against climate change until mid-2000's. In July 2008 the National Council for Climate Change (DNPI) was established under the direct supervision by the President and National Commission for Clean Development Mechanism (Komnas MPB) for screening CDM Project, the jurisdiction of which was transferred from Ministry of Environment to DNPI. It is observed that this reorganization came concurrently with the shifting of the focal point of climate change policy from Ministry of Environment to BAPPENAS, while Ministry of Environment remains active in making national GHG Inventory and is supposed to contribute to the establishment of MRV in cooperation with Economic Coordination Minister's Office (EKON) and the rest of the relevant government institutions.

DPNI has continued to organize workshops regarding MRV technologies (explained below. About eight workshops have been held, but not on the energy sector due to the relationship with REDD+). Preparation of MRV requires cooperation with responsible government agencies or private sector experts, and the workshops are deemed to be aimed at creating a shared awareness on the procedures necessary for preparing the MRVs.

6 BAPPENAS, “Pedoman Penyusunan Rencana Aksi Daerah Penurunan Emisi Gas Rumah Kaca”, December 2011.


Final Report 2-34

Figure 2.2-1 Overview of Climate Change-Related Organizations in Indonesia (Prepared by the survey team based on interviews with relevant parties)

(3) Formulation of NAMAs in the international sphere and its development in Indonesia NAMAs was proposed at Copenhagen COP15 in 2009, and establishment of MRV including those

with international support is required for their implementation. In addition, under the Agreements of Cancun reached at the Cancun COP16, establishment of MRV in accordance with international guidelines under UNFCCC is required for implementation of NAMAs, and the guideline is to be prepared through future international negotiations.

To enable voluntary actions by Non-Annex I countries to implement NAMAs to establish future climate change framework, Copenhagen Accord Table II requires that the Non-Annex I countries submit a report on their NAMAs by January 31, 2010. As of September 2011, 44 countries have submitted their NAMAs7.

Below table shows sample categorization of NAMAs as of May 2010.

7 Aggregated by the survey team based on the submission record on UNFCCC website.

Economic Coordination

Minister's Office (EKON)

Overall climate change policies, implement

policies based on RAN-GRK, support state

governments’ preparation/implementati

on of RAD-GRK

President's Delivery Unit for Development Monitoring and Oversight (UKP4)

Responsible for REDD+ only

Ministry of Environment

(KLH)

National Council for Climate Change (DNPI)

Create MRV

system構築

Prepare RAD-GRK

Ministries in charge of sectors

National Commission for Clean Development Mechanism (Komnas=MPB)

Special Envoy to President

Create GHG

inventory

BAPPENAS

Provincial governments


Final Report 2-35

Table 2.2-1 NAMA categories by Copenhagen Accord Table II submissions (36 countries)

Category 1 Category 2 Category 3 Category 4 Build basic foundation

Sector-based measures

Carbon-neutral

Quantitative targets Units (GDP)

Total Volume vs base year vs BAU

Afghanistan Botswana Georgia

Armenia Benin Central African Republic Congo Côte d'Ivoire Etiopia Eritrea Gabón Ghana Jordan Madagascar Mauritania Mongolia Morocco San Marino Sierra Leone Macedonia Togo

Bhutan Costa Rica Maldives

China India

Marshall Islands (2009) Moldova (1990)

Brazil Indonesia Israel Mexico (Papua New Guinea) Korea Singapore South Africa

Source:"Study on Nationally Appropriate Mitigation Actions of Non-Annex I Parties of UNFCCC for the Future Climate Regime" by Koji Fukuda, Kentaro Tamura

Emerging economies including China, India and Indonesia have set quantitative targets, whereas African nations and smaller economies have set sector-based measures, and there are countries such as Morocco that have set specific reduction project name and volume.

This variation is likely to be the result of some emerging economies consciously setting quantitative targets to prove themselves as leaders of Non-Annex I countries, but requiring time for review of individual implementation due to the size of their economy. This was the case for Indonesia. Indonesia submitted its NAMAs relatively early (January 30, 2010, thirteenth of all countries that submitted NAMAs8 ), and have been keen in policies to implement specific mitigation actions, with RAN-GRK (NAMAs Basic Law) to establishment of RAD-GRK (regional NAMAs plans). In January 2012, Indonesia announced its position on NAMAs9 , and is expected to take initiative as one of the key countries among the Non-Annex I countries to implement NAMAs.

(4) Relationship between Indonesia's Mitigation Actions and National Plans RAN-GRK (RAN-GRK 2010-2020) was established under the on-going National Medium-Term

Development Plan (2010-2014) and National Long-Term Development Plan (2005-2025; Law No 27/2007), applicable to the period between 2010 and 2020 (see below figure). It is clear that the RAN-GRK is prepared as a climate change policy that has a much closer linkage than ever with the National Development Plan under the initiative of BAPPENAS.

8 Excluding Mongolia and Sierra Leone, which did not state the UN submission date. 9 DNPI, “Pandangan Indonesia mengenai NAMASs”, January 2012. Distributed to relevant parties as a position paper by

the DNPI as DNA.


Final Report 2-36

Figure 2.2-2 Relationship between RAN-GRK and Long-Term Development Plan (from RAN-GRK law-related documents)

(5) Indonesia's GHG reduction target and specific reduction plans Energy sector (including transport sector) is targeting 0.038 GT against overall reduction of 26%,

and 0.056 GT against 41%, adhering to the NAMAs document submitted to the UNFCCC (see table below).

Table 2.2-2 GHG reduction targets by 2020 by sector (partial excerpt from RAN-GRK)

Specific reduction plans for each sector comprise of major reduction actions and supplementary reduction actions. For the energy sector, they are as follows:

RAN-GRK

2010 2020

Rencana Pembangunan (Development Plan)

RPJP (Long-term Development Plan) 2005 2025

RPJM 1 RPJM 2 RPJM 3 RPJM

2004 2009 2014 2019 2025


Final Report 2-37

Table 2.2-3 Energy sector major reduction action list (RAN-GRK)

No. Reduction Action Description of Action Timing Location

Reduction Unit:

MilTonCO2 1 Energy

Management Energy management by 200 companies

2010-2014 All provinces 2.24

Energy management by 200 companies


2 Energy saving partnership programs

Save energy in 1,003 targets (buildings/industries) in cooperation with companies and regional communities


Save energy in 300 targets (buildings/industries) in cooperation with companies and regional communities


3 Improve efficiency of household goods

Adopt energy-saving technologies to achieve energy savings of 790 million kWh


Adopt energy saving technologies to achieve energy savings of 135.3 million kWh


4 New energy and energy saving supplies management

Micro hydroelectric power generation development: 46.17MW Small hydroelectric power generation development: 182 MW Solar power plant development: 21.67 MW Biomass power generation development: 0.4 MW Power generation for village vitalization: 250 villages

2010-2014 All provinces 1.27 Micro hydroelectric: 0.21 Small hydroelectric: 0.85 Solar: 0.11 Biomass: 0.02 Village vitalization: 0.06

Micro hydroelectric power generation development: 84.23 MW Small hydroelectric power generation development: 510 MW Solar power generation development: 224.68 MW Biomass power generation development: 16.50

2015-2020 All provinces 3.13 Micro hydroelectric: 0.40 Small hydroelectric: 2.40 Solar: 0.18 Biomass: 0.04 Village vitalization: 0.12


Final Report 2-38

No. Reduction Action Description of Action Timing Location

Reduction Unit:

MilTonCO2 MW Power generation for village vitalization: 450 villages

5 Biogas utilization

Production/use of 10,000 biogas production equipments


Production/use of 21,400 biogas production equipments


6 Natural gas use by public transportation10

Use of natural gas in 3 cities 9.33 MMSCFD, Use of LNG for LGV in Denpasar 10.56 ton/day (2013-2014)

2010-2014 Palembang, Surabaya, Denpasar

0.13

Use of natural gas in 3 cities 628.50MMSCFD, LNG use for LGV in Balikpapan 10.58 ton/day

2015-2020 Medan, Metropolitan Jakarta, Cilegon, Cirebon, Balikpapan, Sunkan

2.94

7 Promotion of city gas in households

2010-2014 24 cities: Lhoksemawe, Pekanbaru, Palembang, Lampung, Semarang, Metropolitan Jakarta, Sidoarjo, Bontang, Balikpapan, Samarinda, etc.

0.15

8 Construction of small LPG plant

Build one plant with 2.2MMSCFD capacity

2010-2014 Musi/Banyuasin, Sumatera Selatan

0.03

9 Filling and greening of mines

Forestation 31,400 ha 2010-2014 all provinces 1.18

Forestation 41,400ha 2015-2020 all provinces 1.55

(6) Actions towards specific reduction The report "Development of the Indonesian NAMA framework11" assisted by GIZ12, which had

been providing overall policy advise to BAPPENAS on environment/climate change including NAMAs establishment, provides detailed review on the approach towards BAU setting and specific measures on data collection for energy, electricity, industry, transportation, waste, and land use sectors 10 MEMR is held responsible, although it seems to be an item for the transportation sector. 11 Development of Indonesia NAMASs Framework Report II, July 2011, 12 PAKLIM (Policy Advice for Environment and Climate Change). In addition to providing policy advice and supporting

framework establishment, it engages in implementation of specific projects in pilot cities/regions. GIZ (formerly GTZ) had provided climate change-related advice to the Ministry of Environment over the years and implemented environmental projects, while also contributing significantly to DNA establishment, and is now fully committed to policy supports with BAPPENAS as its main counterpart.


Final Report 2-39

by project. For the electricity sector, it proposes a comprehensive modeling method comprising of system analysis, database creation, establishment of appropriate BAU scenario, as well as implementation of low carbon technology and improvement of efficiency, and review of reduction scenario through introduction of new energy sources, etc., based on RUPTIL and suggests that the result should be reflected in the relevant policies and strategies.

The report was submitted to BAPPENAS in July 2011, and is expected to be reflected in the future policies and measures. In particular, the Energy Working Group that was proposed by the report (see below figure) and currently is in preparation, once established, is expected to support implementation of RAN-GRK and RAD-GRK which is being prepared targeting establishment a year after the implementation of RAN-GRK.

The Energy Working Group is expected to be leading the preparation work of MRV with full knowledge of the policies and project plans for the relevant sector, in support of the policy initiatives by EKON and MOE.

Figure 2.2-3 Structure of Energy Working Group (Source: "Development of the Indonesian NAMA framework")

(7) Indonesia's climate change policies after COP17/CMP7 Main components of the Durban Package, agreed at COP17/CMP7 held in Durban, South Africa,

are as follows:

(i) Establishment of second commitment period for the Kyoto Protocol Extension of the second commitment period was officially adopted. However, amendment including statement of official quantitative target and length of commitment period was postponed until 2012. In addition, there may be a blank period after the conclusion of the first commitment period at the end of 2012.

Senior Energy Specialist from ESDM

Energy Modeling Staff (4-5 persons）

Senior Energy Simulation Specialist

Prominent Energy &Climate Change Specialist (Coordinator) INTEGRATED

NATIONAL ENERGY AND CLIMATE

CHANGE MODELING (INECCM)

Transport Sector

Modeling Specialist of

Transport Sector

Power Sector

Modeling Specialist of

Power Sector

Industry Sector Modeling Specialist

of Industrialized Sector

Transport Sector Representatives

Power Sector Representatives

Industrial Sector Representatives


Final Report 2-40

(ii) Establishment of Durban Platform Establish a new working group (AWG) to agree on the new framework by 2015.

(iii) Establishment and launch of Green Climate Fund (GCF)

Discussion on establishment/operation of GCF, agreed at the Cancun conference (COP16/CMP6) in 2010. Organization and directionality were finalized, but source of funding was not clearly secured.

(iv) Deepening of Cancun Agreement Establishment of MRV13 system.

In addition, agreement on individual areas were reached, including establishment of specific requirements for the Adaptation Committee, preparation of action plans to consider long-term funding towards 2020 to support developing countries, commencement of work towards establishment of the new market mechanism.

Impact of Durban Agreement on the climate change policy of Indonesia has been quite limited. Government of Indonesia set a good example for the emerging countries by establishing a national target and made preparation of regional targets ahead of these agreements. Progress of the policy efforts and mitigation actions initiated by the Government of Indonesia commands attention of the international community and will have a great impact on the commitment by other Non-Annex I countries as well as the negotiations at COP18/CMP8. The following view indicated by DNPI to the relevant domestic players tells that Indonesia is proud to be a forerunner with its own principle.

(8) Indonesian government's position on NAMAs DNPI called a meeting with relevant parties in domestic sectors on January 12, 2012, after the

COP17/MOP7. The agenda was not the Durban Package; but rather, the enactment and implementation of RAN-GRK, and Indonesia's position on NAMAs. Although there remain some issues that need to be clarified, it could be seen as a statement of the shared awareness by most of the Non-Annex I countries based on the negotiations, as one of the emergng counties with forward-looking policies. Summary of the official views14 distributed at the meeting is as follows15:

NAMAs was proposed in view of the opinion by IPCC that reduction efforts by Annex I countries alone would not suffice to curb the temperature increase below 2 degrees Celsius. Non-Annex I developing countries are taking voluntary actions to achieve the goal of preventing global warming through joint action, which is a different position from the industrialized countries who are required to reduce GHG emissions (NAMAC).

Discussions on how to proceed with the Bali Action Plan were held at AWG-LCA, but even after the COP17/CMP7, no agreement has been reached between the two groups on negotiation concerning NAMAC and NAMAs.

13 Industrial countries are required to submit reports every two years and receive international assessment and review

(IAR), and developing countries are required to submit updated reports every two years and receive international consultation and analysis (ICA).

14 DNPI, “Pandangan Indonesia mengenai NAMAs”, Kertas Posisi Dewan Perubahan Iklim 15 Summary translation by the survey team.


Final Report 2-41

One of the reasons for prolonged discussions on NAMAs is the requirement of international standard MRV. On this issue, Indonesia's position can be summarized as follows16:

(i) If international standard MRV is required for implementation of NAMAs, Indonesia will refuse it.

(ii) While Non-Annex I countries are being rushed to commit to NAMAs, approach of Annex I countries to mandatory reduction and funding has been slow. That the Annex I countries require NAMAs in return for provision of technology and funding is inappropriate, considering that the main cause of global warming was past GHG emission by the industrial countries.

(iii) Indonesia will actively offer information on its commitment to NAMAs and the framework to the international community. In doing so, Indonesia is taking reduction actions that are suitable to its own conditions, needs and capacity in the same manner as other Non-Annex I countries, and will not be obliged to state how individual reduction actions will be funded and implemented.

(iv) Indonesia prepared and enacted RAN-GRK, which is the basic act for NAMAs, while experiencing a solid annual economic growth of 7%. This indicates the significance of contribution by Indonesia against global warming.

(v) In long-term, emissions reduction will secure national interest for Indonesia not only through environmental protection, but also through economic effects.

(vi) At present, the largest issue is how to secure funding and implement individual reduction actions while the international funding framework for climate change is yet to be clear. The Government of Indonesia will support international funding/investment regardless of the funding sources-whether or not the source is a multilateral/bilateral funding agency, a public/private organization or a domestic organization. It should be noted that any loan by a multilateral/bilateral funding agency must be un-tied and no financial burden on national treasury is expected.

(vii) Basically, reduction actions with small cost should be implemented by the Indonesian government and others should be implemented jointly by the government in cooperation with Indonesian private sector, and/or with support from overseas public institutions.

(viii) Funding/investment from Annex I countries for the purpose of off-setting to achieve reduction obligations should be strictly distinguished from pure funding/investment without such pirposes.

16 Major points summarized from the original text.


Final Report 3-1

Chapter 3 Environmental and social considerations 3.1 Regulations of guidelines on environmental management and assessment

(1) Laws, regulations and guidelines of GOI regarding EIA (AMDAL) Law on Environmental Protection and Management

The Law on Environmental Protection and Management stands as the Indonesian basic law concerning the environment. The law first came into force in 1982 and underwent a large revision in 1997. Then, it was amended again in 2009 and promulgated as a new law into effect.

In the new law, the conduct of ‘Strategic Environmental Study’, KLHS in Bahasa Indonesia, is newly required by Article 15 through Article 19. It stipulates that the Government and regional governments shall prepare KLHS to ascertain that the principles of sustainable development should be underlying and integrated in the national and regional development policy, plan and/or program, including layout plans (RTRW), long-term development plans (RPJP), and medium-term development plans (RPJM) of respective levels (Article 15). It lists the following objects as what to be analyzed (Article 16) with participatory analysis involving communities and stakeholders (Article 18).

Supportive and carrying capacity of the environment Environmental impacts and risks

Performance of service/ ecosystem service Efficiency in the utilization of natural resources

Vulnerability and adaptability to climate change Resilience and potential of biological diversity

It says that further provision on procedures for executing KLHS shall be regulated in a government

regulation (Article 18). On this stipulation, the Ministry of Environment (MOE) is currently preparing the pertinent government regulation and concrete guidelines.

Spatial Plan In Indonesia, Spatial Plans are prepared and determined for the utilization, development and

management of land, oceanic and air space. This legal institution started with relevant presidential decrees between 1976 and 1992. Then, the Law No. 26 of 2007 on Spatial Planning was enacted as the pertinent basic law. Under the government regulations and presidential decrees associated with the Law, the Central Government and local governments as province, regency and municipality are obliged and authorized to formulate a respective basic plan for utilization and management of jurisdictional area, by which spatial zoning is laid out according to different purposes such as conservation and development.

The said Law on Environmental Protection and Management requires, with its article on KLHS, the application of ‘strategic environmental study (KLHS)’ in formulation and evaluation of central and local governments’ layout plans (RTRW), with which spatial plans are concerned. With a hearing by the Study Team at the EIA division of MOE, it became clear that the site selection for a model coal-fired power plant must conform with the regional spatial plan from the strategic environmental assessment view, and that the conformity with the pertinent spatial plan will be a precondition for issuing the EIA (AMDAL) certification and the Environmental Permit.


Final Report 3-2

Environmental Impact Assessment (EIA/AMDAL） Environmental impact assessment (EIA) is called AMDAL (Analisis Mengenai Dampak

Lingkungan) in Indonesia. The method for EIA implementation should follow related environmental laws and guidelines in Indonesia.

The EIA system was introduced by ‘Government regulation on environmental impact analysis of 1986 and 1993’, based on the Article 16 of ‘Law on environmental protection and management of 1982 (the old law)’ which said that every business and/or activity bringing substantial impact to the environment shall be obliged to conduct EIA. Currently, ‘Government regulation on EIA (No.27 of 1999)’ is the basic law for the system. Types of business and/or activities required to prepare EIA are defined in MOE Regulation No.11 of 2006. The EIA report preparation in Indonesia needs to be made by the expert consultants registered in MOE.

The table 3.1-1 shows primary Indonesian regulations and guidelines regarding environmental management and EIA. The table 3.1-2 does primary Indonesian regulations regarding spatial planning.

Table 3.1-1 Primary Indonesian regulations and guidelines regarding environmental management and EIA

Category Type of legislation Legislation

Environmental Management Basic law

Law on environmental protection and management (No.32 of 2009) - Enforced with Law No.4 of 1982, and major amendment in Law

No.23 of 1997. It was amended again and promulgated as the new law that took effect on October 3, 2009.

Relevant regulations

Joint circular letter between Minister of Home Affairs and State Minister of Environment concerning reorganization of local government environmental institutions（No.061/163/SJ/2008 AND SE-01/ MENLH/ 2008）

Environmental Impact Assessment

Basic law Government regulation on environmental impact analysis (No.51 of 1993, amendment No.27 of 1999)

Decrees and Regulations

MOE Regulation on the types of business and/or activities required to prepare EIA (No.17 of 2001, amendment No.11 of 2006)

- There are guidelines relevant to the regulation.

MOE Regulation on guidelines for preparing EIA (No.08 of 2006)

- This regulation is the enactment of ‘Decree of the Head of BAPEDAL(No.09 of 2000)’

MOE Regulation on appraisal guidance of EIA document (Decree No.02 of 2000, Regulation No.24 of 2009)

MOE Regulation on guidelines for strategic environmental assessment (No.27 of 2009)

MOE Regulation on environmental management and monitoring measures and statement for environmental management and monitoring capacity (No.13 of 2010)

- MOE Decision on guidelines for environmental management and monitoring measures (No.86 of 2002)


Final Report 3-3


MOE Decision on AMDAL preparation guidelines for development activities in wetland areas (No.05 of 2000)

MOE Decree on guidelines for establishment of EIA evaluation committee of regencies/ municipalities (No.41 of 2000)

Decree of Head of BAPEDAL on public involvement and information disclosure in the process of EIA (No.8/ 2000)

Source: Edited by the Study Team with documents collected at MOE, GOI

Table 3.1-2 Primary Indonesian regulations regarding spatial planning


Spatial Plan Basic law Law on spatial planning (No. 26 of 2007)

Relevant regulations

Government Regulation regarding the national spatial plan (No. 26 of 2008)

Presidential Decree on the coordination team for the national spatial management (No. 57 of 1989)

Presidential Decree on management of protected areas (No. 32 of 1990)

Government Regulation on implementation of the rights and obligations, and forms and procedures for community participation in spatial planning (No. 69 of 1996)


Regarding environmental pollution control in general and regarding environmental measures and standards for business activities of coal-fired power plants among specific business sectors, the primary Indonesian regulations and guidelines are listed on the Table 3.1-3

‘Government Regulation on air pollution control (No. 41 of 1999)’ defined national standards on thirteen (13) atmospheric environmental standards. MOE Decree No. 45 of 1997 introduced Pollution Standard Index.

‘Government Regulation on air pollution control (No. 41 of 1999)’ defined national standards on thirteen (13) atmospheric environmental standards. MOE Decree (No. 45 of 1997) introduced Pollution Standard Index.

‘Government Regulation on water quality management and water pollution control (No. 82 of 2001)’ set environmental standards respective to four categories defined with usage of land surface water. Those of sea water quality are stipulated in MOE Decree (No.51 and No. 179 of 2004). On waste water quality from thermal power plant enterprises and /or activities, concerned environmental standards are lay down by MOE Regulation (No.08 of 2009).

Law on local government (No.22 of 1999) and Law on central-regional fiscal balance (No.25 of 1999) promoted the trend toward decentralization of government. Thereupon, administrative responsibility of environmental management regarding air and water pollutions were relegated to


Final Report 3-4

regencies and municipalities, and their authorities may set a special provision on environmental standards such as on air quality.

Table 3.1-3 Primary Indonesian regulations on general environmental pollution control and on environmental measures for business activities of coal-fired power plants

Category Legislation Air Pollution Control

Government Regulation on air pollution control (No. 41 of 1999) - MOE Decree on air pollution control (1993) - Relevant Guidelines are issued in the MOE Regulations concerned, and

environmental standards are set on this government regulation No.41 of 1999 MOE Decree on environmental standards of emission gases from stationary sources

(No.13 of 1995) MOE Decree on environmental standard index of air pollution (No. 45 of 1997) MOE Regulation on environmental standards of emission gases from stationary

emission sources of Boiler (No. 07 of 2007) MOE Regulation on environmental standards of emission gas from stationary

emission sources of thermal power plant enterprises and / or activities (No. 21 of 2008)

MOE Regulation on implementation of regional air pollution control (No. 12 of 2010)

Water Pollution Control

Government Regulation on water quality management and water pollution control (No. 82 of 2001)

- Relevant Guidelines are issued in the MOE Regulations concerned, and environmental standards are set on this government regulation No.82 of 2001

Government Regulation on control of marine pollution and destruction (No.19 of 1999)

MOE Decree on environmental standards of effluent wastewater quality from industrial activities (No.51 of 1995, amendment No. 122 of 2004)

MOE Decree on environmental criteria for coral reef damage (No. 04 of 2001) MOE Decree on the method of surface water quality analysis and surface water

sampling (No. 37 of 2003) MOE Decree on guidelines for determination of carrying capacity of water pollution

charges in water resources (No.110 of 2003) MOE Decree on sea water quality standard (No.51 of 2004, amendment No. 179 of

2004) MOE Decree on standard criteria and guidelines for determination of mangrove

damage (No. 201 of 2004) MOE Decree on environmental standards of waste water quality from coal mining

enterprises and /or activities (No. 113 of 2003) MOE Regulation on environmental standards of waste water quality from thermal

power plant enterprises and /or activities (No. 08 of 2009) Noise MOE Decree on environmental standards of noise levels (No. 48 of 1996) Vibration MOE Decree about environmental standards of vibration levels (No.49 of 1996) Odor MOE Decree on environmental standards of odor levels (No.50 of 1996) Solid Waste Management

Law on solid waste management (No. 18 of 2008)



Final Report 3-5

(2) Provisions on strategic environmental assessment (SEA) Indonesian legal system on SEA

The SEA that Indonesian legislation requires was mentioned in the preceding section (1) with reference to ‘Law on Environmental Protection and Management’ (See the section concerned). The Article 15 of the Law No.32 of 2009 orders that the central government and regional governments are required to prepare the SEA in the formulation and evaluation of:

a. national, provincial and district/municipal layout plan (Spatial Plan/ RTRW) along with detail thereof. long-term development plan (RPJP) and medium-term development plan (RPJM);

b. polices, plans and/or programs potential to bring about impacts and/or risks to the environment.

However, the methodology and guidelines how to implement it are under preparation and not specifically defined yet.

Provisions on SEA in JICA Guidelines for Environmental and Social Considerations17 The JICA Guidelines define the concept of SEA as follows; “strategic environmental assessment”

means an assessment being implemented at the policy, planning and program level rather than a project-level EIA. (See the section at ‘I. BASIC MATTERS -1.3 Definitions’, p2)

In the clause of basic principle, it states that JICA introduces the concept of Strategic Environmental assessment (SEA) when conducting Master Plan studies, etc., and works with the recipient governments to address a wide range of environmental and social factors from an early stage. JICA makes an effort to include an analysis of alternatives on such occasions. (See the section at ‘I. BASIC MATTERS -1.4 Basic Principles regarding Environmental and Social Considerations -2’, p3)

As to the study stage when the SEA should be applied to, it refers to ‘the Master Plan Study’ of a development study. (See the section at ‘III. Procedures of Environmental and Social Considerations - 3.2 Development Study (Master Plan Study) - 3.2.3 Full-scale Study Stage, p12)

Provisions on SEA of International Authorities 1) OECD/DAC Guideline on SEA

The Development Assistance Committee of OECD defines that SEA refers to a range of “analytical and participatory approaches that aim to integrate environmental considerations into policies, plans and programmers and evaluate the inter linkages with economic and social considerations”, in a guidance book titled as ‘Applying Strategic Environmental Assessment’, DAC Guidelines and Reference Series, OECD, 2006.

2) Provisions of World Bank on SEA In the World Bank Environment Strategy of 2001, the Bank recognized SEA as a key means of

17 The existing JICA Guidelines for Environmental and Social Considerations (ESCs) became effective as of 1 April 2010,

which integrated ‘JBIC Guidelines for confirmation of ESCs’ and ‘Former JICA Guidelines for ESCs of 2004’, following the histological integration of JICA and the former Japan Bank for International Cooperation (JBIC) as of October 2008. However, the assistance to the Project hereto is requested before the publication of the new Guidelines, and so the 2004 Guidelines will be applied to it.

＜See URL: http://www.jica.go.jp/english/operations/social_environmental/index.html＞


Final Report 3-6

integrating environment into the sectoral decision making and planning process at early stages and made a strong commitment to promote the use of SEA as a tool for sustainable development.

The Bank’s policy on development policy lending, OP/BP 8.60., updated in August 2004, emphasized upstream analytical work, such as SEA and country environmental analysis, as a source of information for analyzing the likely significant effects of an operation on the borrowing country’s environment and natural resources, and for assessing the country’s institutional capacity for handling these effects. Currently, the provisions of OP/BP8.60 are the basic ones on SEA in the Bank activities.

(3) Process of environmental impact assessment (EIA) The EIA process in Indonesia is carried out according to the scheme as shown in Figure 3.1-1.

According to the Government Regulation on environmental impact analysis (No.27 of 1999), a proponent (or either government or private sector) must contact the EIA commission in the BAPEDAL (the former Environmental Impact Management Agency, now integrated into the Ministry of Environment; MOE) at the inception of EIA process.

The screening is performed through a prescribed list, which is set by the MOE Regulation No. 3 of 2000 (amended by MOE Regulation No.17 of 2001 and No.11 of 2006).

Following screening, a proponent is directed to prepare a TOR for the EIA study (scoping process). Other activities that are not required to conduct the EIA are obliged to prepare plans on environmental management and monitoring efforts (UKL and URL) in a fashion that the business activities should minimize negative environmental impacts.

Regarding the business activities that EIA is required of, ‘Environmental Impact Statement (EIS: an EIA study report called ANDAL in Indonesia)’ and ‘Environmental Management and Monitoring Plans (EMPs called RKL and RPL in Indonesia)’ are prepared and reviewed at the same time. Both review processes are conducted within the maximum of 75 working days. The regulation only specifies a rejection procedure without the proponent’s right of appeal, and the approval of EIA documents is made by the MOE or Governor of local autonomy. This EIA regulation enhanced the transparency of the EIA process through EIA publications and the provision of direct public involvement in the process. This was initiated by the implementation of public involvement guidelines, Decree of Head of BAPEDAL (No.8 of 2000), as introduced by the Government Regulation (No.27 of 1999).


Final Report 3-7

Activity proposal from proponent

Screening process: Prescribed list in

MOE Regulation No.03 of 2000 (Amended by No.17 of 2001 and No. 11 of 2006)

EIA（AMDAL） Required

TOR for EIA (Scoping)

Review by EIA commission

Preparation of EIA study plan (KA-ANDAL)

Simple environmental management and monitoring

plans (UKL/UPL）are required instead

Preparation of UKL and UPL

Coordination of UKL and UPL

Appraisal of UKL and UPL

Compliance with Requirements

Non-compliance with requirements

/ Rejected

Compliance with Requirements

/ Approval

Permission and licensing

Preparation of EIA statement（ANDAL）and

environmental management and monitoring plans (RKL/RPL）

Appraisal by EIA commission

Review by EIA commission

Approval by Minister of Environment

or Governor

75 days of work

75 days of work

EIA（AMDAL） Not required

Figure 3.1-1 EIA procedure in Indonesia

Source: The above figure is based on an EIA flowchart, shown to the Study Team in May 2011 at MOE, which is revised by the EIA division of MOE, standing on ‘Government regulation on environmental impact analysis (No.27 of 1999) and ‘Amendment to Law on environmental protection and management (No.32 of 2009)’, and which the Study Team partially made an edition to clarify the expression of contents.


Final Report 3-8

3.2 Trend and Challenge of Environmental and Social Considerations

(1) Cases of environmental and social considerations (Profiling ‘Good Practice’) The cases of SEA in the energy sector are sparse even from a global perspective. Among the limited

number, the following cases can be introduced as good practices. The first case is from the one studied by the society of interdisciplinary SEA study situated in Ministry of the Environment, Japan (MOE-Japan). The second case is one regarding energy analysis by the U.S. Department of Energy (US-DOE). The third is introduced by DAC Guidelines and Reference Series, OECD (OECD-DAC)

(a) A case studied by the society of interdisciplinary SEA study situated in MOE-Japan

SEA for Dutch national plan for ‘Structure Scheme Electricity Supply’ 1) The concerned plan was a long-term power supply strategy of the Netherlands, which drew up the

following. • the possible locations of power plants of 500 MW or more • the suitability of these locations for utilization of certain fuel types and the maximum capacity

per fuel type which may be installed in The Netherlands (with a policy of wind power utilization at a certain level)

• a project plan for routing of high voltage power extension lines 2) With the master plan, the plan needed to coincide with and contribute to realization of upper level

government policies of energy, environment, nature and landscape conservation and land use. Regarding the environmental policy, the primary issues of environmental conservation were measures for climate change, acid precipitation, conservation of water quality, waste management, internationalization of energy security and nature protection.

3) In the examination of environmental impacts, six basic alternative cases were studied with the combination of power demand and fuel types (cases of high power demand, low power demand, and cases of different mix with powdered coal, coal gasification and gas-combined type). The study made comparison for the basic cases of environmental impacts by acid precipitation, carbon dioxide, and coal ash generation. Then, additional analysis for two environmentally friendly alternatives was made, assuming a possible input of advanced environmental technology.

4) Further, the following examinations in construction site selection are informative to this JICA CCT study; studies of impacts by thermal wastewater, those on water quality of surface water, cross check with plans of nature protection and land use, risk analysis on shipment and storage of fuels and wastes.

Source: Mitsubishi Research Institute, INC. and MOE-Japan, Effective SEA systemand case studies, pp87-94, 2003. http://www.env.go.jp/policy/assess/2-4strategic/3sea_5_en/data/en_all.pdf, accessed on June, 2011

(b) A case introduced by the National Energy Technology Laboratory, US-DOE

Strategic Analyses on Energy: Cost and Performance Baselines for Fossil Energy Plants 1) In the hereto analysis, the studies make estimates for the cost and performance of combustion and

gasification based power plants as well as options for co-generating synthetic natural gas and fuels, all with and without carbon dioxide capture and storage.

http://www.env.go.jp/policy/assess/2-4strategic/3sea_5_en/data/en_all.pdf


Final Report 3-9

2) Several ranks of coal are being assessed in process configurations that are based on technology that could be constructed today such that the plant could be operational in the 2012 - 2015 timeframe.

3) Results of analyses will be compiled with four volumes in total, and three of them have been publicized so far. The Volume 1 shows benchmarking performance and cost data for fossil energy power systems, specifically integrated gasification combined cycle (IGCC) plants fueled with bituminous coal, pulverized coal (PC) plants fueled with bituminous coal, and natural gas combined cycle (NGCC) plants all with and without carbon capture and sequestration. The Volume 3 compares performance and cost data on as many as 28 cases, assuming low rank coal and natural gas applied to three types of power plants as IGCC, combustion, and NGCC and being based on specific coals of existing coal mines and current market conditions for coal-fueled plants. This JICA Study, assuming the use of low rank coal as a precondition, may well refer to the analyses given in the study concerned.

Source: NETL-the U.S. Department of Energy (2011), Energy Analyses: Cost and Performance Baselines for Fossil Energy Plants, http://www.netl.doe.gov/energy-analyses/baseline_studies.html accessed on June 2011

(c) A case shown by DAC Guidelines and Reference Series, OECD

Energy Environment Review in Iran and Egypt 1) The Energy and Environment Review (EER) is a specific approach proposed in the World Bank’s

Fuel for Thought: An Environmental Strategy for the Energy Sector, which includes the basic review process as follows: • Current situation and growth prospects with regards to energy generation and use • Environmental issues induced by the generation and use of energy, and damage cost estimates • Extent of contribution to climate-change through emission of greenhouse gases • Proposed mitigating measures for the previously identified environmental problems • Conclusions and recommendations, and a proposal for an action plan.

2) As the outcomes of EER in Iran, listed there are Increase in the price of energy fuels (gasoline, diesel, and electricity reaching real market values; diesel fuel price was increased by 15%, and electricity price by 20%); Reduction of gasoline price subsidies; the Carbon Business Finance Unit of the Bank being enabled to commit to buy US$ 50 million of carbon emission reductions; Having helped the Bank in convincing the government to ratify the Kyoto Protocol.

3) As the outcomes of EER in Egypt, listed are Having improved the Country Environmental Analysis of Egypt; Increased penetration of natural gas in industrial sectors; Improved efficiency of electrical transmissions and distribution systems; Increased price of diesel; Vehicle Emission Testing (VET) in Greater Cairo; as well as the Carbon Business Finance Unit of the Bank being enabled to commit to buy US$ 50 million of carbon emission reductions; and Having helped the Bank in convincing the government to ratify the Kyoto Protocol

4) The Review presents the case where, with normalized fuel prices, unnecessary expansion of energy demand is controlled, and proper and sustainable growth is driven to reduce environmental problems.

http://www.netl.doe.gov/energy-analyses/baseline_studies.html


Final Report 3-10

Source: OECD(2006), DAC Guidelines and Reference Series, Applying Strategic Environmental Assessment GOOD PRACTICE GUIDANCE FOR DEVELOPMENT CO-OPERATION, Case example 5.7. http://www.sourceoecd.org/development/9264026576, accessed on accessed on June, 2011

(2) Points to note from the aspect of environmental and social considerations This section describes points to note from the aspect of environmental and social considerations for

business activities to develop coal-fired power plants in Indonesia.

(a) Adjustment with the trend of environmental and social considerations (ESCs)

The ESCs for development plans is showing the clear trend that it is required to start the ESC-process in an earlier phase of planning process either internationally or in Indonesia. In Indonesia, as stated previously in 3.1 (2), legal provisions on strategic environmental assessment are prescribed in the basic environmental law and the MOE is currently preparing administrative guidelines to actualize the law requirements.

Since the 1990s, the AMDAL system has certainly been structured in Indonesia so that alternatives analysis and public involvement have been required in making plans of business activities. In accordance with these legal requirements, the DGE of MEMR (the government agency to oversee the business activities of coal-fired power plants in Indonesia) and PT.PLN (the state-run company to implement public utilities of power supply) have taken efforts to fulfill them.

With the view of the recent trend, however, it is surely needed for the both organizations to step up their implementation scheme so that they can start ESCs in the earlier phase of planning process than previously. To date, the DGE and the PLN have called into account the timing of initiating ESCs from the aspect of enabling the AMDAL approval before project implementation. For the future, it will be vital for the planners and environmental management staffs in the both organs to fit in the concept of initiating ESCs in the earlier phase of planning process and to steer their implementation scheme in such direction.

(b) Initiating measures for social considerations at an earliest phase

According to the foregoing cases of coal-fired-power-plant-development projects in Indonesia, such problematic situations have arisen that while the concerned feasibility and EIA study were finalized for most parts, yet the land acquisition for project site became tangled and time went by in vain before project implementation. The PLN, as business-implementing organization, acknowledges that the onset of the public-consensus formation and, based on the formed consensus, the consultation for land acquisition could be started earlier.

Therefore, it is thought to be obvious that starting involvement of, information disclosure to and discussion with stakeholders at an earliest phase of planning process is essential for confirming the wills of concerned people and land acquisition issue on a sufficiently early stage of the process.

On the other hand, the implementing organ is concerned if the information disclosure to general public at an early phase of planning might raise speculative activities around the pertinent project site or inappropriate requests of unspecified public. It is certain that with such concern they have a

http://www.sourceoecd.org/development/9264026576


Final Report 3-11

tendency of hesitating to initiate the early onset of information disclosure and necessary explanation and consultation about the plan to stakeholders.

However, as lessons from foregoing plans and projects it should be realized that the delay with this reason may delay project implementation in the end, and that early initiation of stakeholders meeting and land ownership survey is essentially important for smooth conclusion of land acquisition and appropriate project implementation.


Final Report 4-1

Chapter 4 Electricity business - current status and issues 4.1 Outline of the power generation business

Installed Capacity PLN, its subsidiaries Indonesia Power (IP) and PJB (Persero) and independent power producers

(IPPs) are engaged in the power generation business. Table 4.1-1 shows the installed capacity of the Java-Bali system as of the end of 2011. By fuel, coal-fired power generation accounts for the largest 46.5%. Shift from oil fuel has been promoted in response to soaring oil prices and to concerns about the depletion of oil resources, and the development of coal, which is available at low prices, has been promoted. Power generated by the use of coal as fuel was 3,520 MW out of 3,730 MW developed over two years (2010 and 2011).

The operation of oil-fired power plants will be discontinued starting with aged low-efficiency ones, and also for diesel-fired power generation, the output is 2,465 MW and accounts for less than 10% of the total. Also, although the country plans to develop renewable energy in a proactive manner, the actual output is small due to the high development cost, and the output from hydropower and geothermal energy totals 3,581 MW and accounts for only about 13%.

Table 4.1-1 Installed Capacity of the Java-Bali System by Power Source

As of Dec. 2011 Power source Installed capacity

(MW) Share (%)

Coal-fired 12,390 46.5 Gas-fired 1,640 6.2

Gas- and oil-fired 6,569 24.7 Oil- and diesel-fired 2,456 9.2 Hydropower 2,536 9.5 Geothermal 1,045 3.9 Total 26,636 100.0

Source：PLN reference materials

The following table shows the installed capacity by electric utility

Table 4.1-2 Installed Capacity of the Java-Bali System by Electric Utility

As of Dec. 2011

Electric Utility Installed capacity（MW）

Share (%) Major power plant

PLN 6,113 23.0 Tanjung Jati B、Indramayu Indonesia Power（IP） 9,646 36.2 Suralaya、Tambak Lorok PJB 6,902 25.9 Gresik、Cirata IPP 3,975 14.9 Cilacap、Cikarang Listrindo Total 26,636 100.0 －



Final Report 4-2

0

5000

10000

15000

20000

25000

30000

2005 2006 2007 2008 2009 2010 2011

PLTG/PLTGU

PLTUgas

PLTU/PLTD oil

PLTUcoal

PLTP

PLTA

Year

[GWh]

Figure 4.1-1 Changes in Installed Capacity


Output The total output came to about 170 TWh in 2010, of which coal-fired power generation accounts

for the largest percentage of 41.1%. The total output in 2011 has not yet been calculated, but the output of 3,220 MW was added in the year by coal-fired power generation and the share will further increase in the future.

0

20000

40000

60000

80000

100000

120000

140000

160000

180000

2005 2006 2007 2008 2009 2010

PLTG/PLTGU

PLTUgas

PLTU/PLTD oil

PLTUcoal

PLTP

PLTA

Year

[GWh]

Figure 4.1-2 Changes in production of electricity

Source：Statistic Electricity 2011


Final Report 4-3

4.2 Present situation and challenges concerning coal-fired power plants

(1) Present situation concerning coal-fired power plants The history of coal-fired power development in Indonesia is comparatively short. As an

oil-producing country, Indonesia has supplied power generated mainly by oil-fired plants (including diesel-powered ones) as well as hydropower plants drawing on its abundant hydropower resources. It began to introduce coal-fired plants in response to the gradual depletion of its oil resources and jump in oil prices.

The first coal-fired power plant constructed in the country was the PLN Suralaya power plant, with its No.1 unit (400 MW) starting operation in 1986. In 2011 the No. 8 unit (625 MW) started operation, increasing the total output of the plant to 4,025 MW. Subsequently the construction of the Paiton and Tanjung Jati B plants was carried out.

Under the first crash program, a total of 10,000 MW coal-fired power plants will be newly established across the country by 2014, and for the Java-Bali system, 300 MW and 3,220 MW coal-fired power generation was newly started in 2010 and 2011 respectively (Table 4.2-1). As a result, the installed capacity came to 12,390 MW at the end of 2011, of which IPPs accounted for 3,030 MW.

Table 4.2-1 PLN coal-fired power plants (Java-Bali system)

Installed NettCapacity Capacity

[MW] [MW]

Suralaya PLTU 1 steam coal 400 371.5 1985 IP2 steam coal 400 371.5 1989 IP3 steam coal 400 371.5 1989 IP4 steam coal 400 371.5 1989 IP5 steam coal 600 575.2 1997 IP6 steam coal 600 575.2 1997 IP7 steam coal 600 575.2 1997 IP8 steam coal 625 600 2011 IP

Labuhan PLTU 1 steam coal 300 300 2009 PLN2 steam coal 300 300 2010 PLN

Lontar PLTU 1 steam coal 315 300 2011 PLN1 steam coal 330 300 2011 PLN2 steam coal 330 300 2011 PLN3 steam coal 330 300 2011 PLN

Cilacap PLTU 1 steam coal 300 281 2006 IPP2 steam coal 300 281 2006 IPP

PLTU 1 steam coal 660 660.8 2006 PLN2 steam coal 660 660.8 2006 PLN3 steam coal 660 660.8 2011 PLN

Rembang PLTU 1 steam coal 315 300 2011 PLN2 steam coal 315 300 2011 PLN

Paiton PLTU 1 steam coal 400 370 1993 PJB2 steam coal 400 370 1993 PJB5 steam coal 610 610 1999 IPP6 steam coal 610 610 2000 IPP7 steam coal 615 615 1998 IPP8 steam coal 615 615 1999 IPP

Total 12390 11946

Fuel OwnerCODYear

Indramayu PLTU

Tanjung Jati B

Plant Type



Final Report 4-4

(2) Challenges concerning coal-fired power plants Coal resources of Indonesia are mainly low-grade coal, such as brown coal and subbituminous coal

with high moisture content and low heat generation. High-grade bituminous coal is mostly exported. In the country, it is therefore necessary to make effective use of low-grade coal, and the following challenges should be met at existing power plants and in new power plant projects for the use of low-grade coal as main fuel for coal-fired power generation.

1) Existing coal-fired power plants

Plant Thermal Efficiency; Most of the existing power plants in Indonesia are steam condition on sub criticality, and the heat

efficiency is in the low 30s percent, also, the power plant heat efficiency will decline more by the reason of using the low rank coal with the different heat value from the design coal,

The modification of steam generator (boiler) facilities is required to maintain the power plant thermal efficiency (The influence depends on the design specification of the existing facilities).

For example, Suralaya coal-fired power plant was constructed under the condition to use the coal of Bukit Assam (5,200kcal/kg) from Sumatra however, the coal of the Bukit Assam is about 60 % and remainder of 40 % is low rank coal (4,200kcal/kg) of Kalimantan at present.

The heat efficiency was decreased because the blend coal has a calorific value 4,800kcal/kg which is different from design coal

Another reason to decrease the heat efficiency will aging deterioration, which can recover by the maintenance and so on.

Coal and Ash Handling Facilities; By the modification of steam generator (boiler) facilities to maintain the heat efficiency, the coal

consumption and ash will be increased. Accordingly the modification of coal unloading facilities, coal storage yard/coal transfer facilities, ash handling system and so on is necessary. However the remodeling of a coal-pulverizer inside the steam generator facility building and so on is very difficult.

Environment Facilities; In case of the existing coal-fired power plant use the low rank coal from high rank coal, the sulfur

content increases more than the design coal, therefore it is necessary to construct FGD.

The Suralaya coal-fired power plant was to use the low-sulfur contents (0.4 %) coal, but actually it uses the low rank coal of high-sulfur contents, and the environmental standard becomes severe in Indonesia. In case it is difficult to satisfy SOx regulation value, the FGD is desirable to be installed. But, the engineer is suffering to solve technically because there is not space for FGD

The affect to environment condition: In case of the existing coal-fired power plant use the low rank coal from high rank coal, the

efficiency of EP (Electrostatic Precipitator) decreased with the calorific value and the ingredient of coal, and In case of the existing coal-fired power plant can not secure the space for FGD and De-SOx


Final Report 4-5

system, the emission of SOx and NOx will increase.

Also, In case of the existing coal-fired power plant can not prepare additional space for coal storage and ash disposal pond, there will be some problems to the ash scatter and the drainage and so on.

Maintenance: In case of using coal with higher sulfur contents than design coal use, the plant needs frequent

maintenance work to prevent trouble by oxidation sulfur

2) New coal-fired power plants In case of converting low rank coal from the design coal, the construction cost will be increased to

enlarge the size of the boiler, boiler auxiliary facilities and so on, and the construction costs such as the coal handling facilities and the ash handling facilities will be increased.

In case the new power plant use coal with high-sulfur contents, the cost will be increased because the boiler tube needs high-quality materials with enough thickness to prevent of corrosion and erosion.

The construction cost of the environment facilities such as EP and FGD will be increased for the enlargement of the size.

4.3 Present situation and challenges concerning the Java-Bali power transmission system

(1) Present situation concerning transmission and substation equipment The Java-Bali system, which supplies power to Jakarta, the capital of Indonesia, accounts for about

80% of the total power supplied across the country. The system voltage is composed of 500 kV, 150 kV and 70 kV. Over five years from 2006, the maximum power supply increased by 4%, with which the transmission equipment was also expanded.

As of the end of 2010, the length of transmission lines owned by PLN was about 21,030 km (about 5,050 km for 500 kV, about 12,370 km for 150 kV and 3,610 km for 70 kV).

As of the end of 2010, the transformer capacity of the substations owned by PLN was about 65,190 MVA (19,500MVA for 500/150 kV class, 32,260MVA for 150/70 kV and 150/20 kV class, 2,750MVA for 70/20 kV).

Table 4.3-1 and Table 4.3-2 show changes in the transmission line length and substation transformer capacity during the period from 2006 to 2010, respectively. Over four years from the end of 2006, the transmission line length was increased by 1,050 km while the substation transformer capacity was expanded by 5,750 MVA. Giving considerations to transmission capacity, supply reliability and power quality improvement, the 150 kV system was proactively developed, while the 70 kV system was on a downward trend.


Final Report 4-6

Table 4.3-1 Transmission line length

Unit: kmYear 2006 2007 2008 2009 2010

500kV 5,050 5,050 5,090 5,110 5,050150kV 11,270 11,610 11,850 11,970 12,37070kV 3,660 3,580 3,610 3,610 3,610Total 19,980 20,240 20,550 20,690 21,030

Source：RUPTL 2011-2020

Table 4.3-2 Substation transformer capacity

Unit: MVAYear 2006 2007 2008 2009 2010

500/150kV 17,000 17,000 17,000 17,000 19,500150/70kV 3,580 3,580 3,580 3,820 3,820150/20kV 25,300 26,070 26,150 26,330 28,44070/20kV 2,880 2,800 2,750 2,740 2,750

Total 48,760 49,450 49,480 49,890 54,510 Source：RUPTL 2011-2020

(2) Plan for the Java-Bali system transmission facilities For the Java-Bali system, future demand is projected to increase by about 7% on average per year,

and accordingly it is necessary to develop power sources and expand transmission facilities on a large scale. Table 4.3-3 and Table 4.3-4 show the transmission line development plan and the substation transformer capacity expansion plan for 2020, which were made based on RUPTL 2011-2020, respectively. Over the next ten years (2011 – 2020), the transmission line length and the substation transformer capacity will be increased by 11,578 km and 75,916 MVA.

Table 4.3-3 Projection of transmission line length

Unit : kmYear 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Total

５００ｋV AC 82 172 374 12 459 738 538 20 40 40 2,475５００ｋV DC 300 300

150kV 1,509 1,950 657 1,562 1,593 490 174 342 210 106 8,59370kV 110 100 210Total 1,591 2,232 1,031 1,674 2,052 1,528 712 362 250 146 11,578


Table 4.3-4 Projection of substation transformer capacity

Unit : MVAYear 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Total

500/150kV 8,660 1,830 5,000 2,000 4,000 5,500 3,500 500 1,500 1,000 33,490150/70kV 0150/20kV 7,916 7,710 1,560 3,900 2,850 3,990 2,970 3,630 3,300 3,510 41,33670/20kV 440 120 80 60 30 30 90 180 60 1,090

Total 17,016 9,660 6,640 5,960 6,850 9,520 6,500 4,220 4,980 4,570 75,916 Source：RUPTL 2011-2020


Final Report 4-7

Table 4.3-5 and Table 4.3-6 show the 500 kV transmission line and substation development plans made based on RUPTL 2011-2020, respectively. Figure 4.3-1 shows the 500 kV system diagram for 2020.

As large-scale development plans for transmission facilities, the following projects are under way.

1) Java-Sumatra direct-current interconnected transmission line construction project implemented between XBogor, T. Pucut, Ketapang (Sumatra) and M. Enim (Sumatra), being financed by yen loans since FY2008 for the start of operation in 2016, in which coal-fired power generation facilities will be developed in Sumatra rich in coal resources and the generated power will be supplied to the Java-Bali system, which will in turn supply it to the area with high demand.

2) Core transmission line construction project implemented in the central and western part of Java, specifically between T. Jati B, Pemalang, Mandirancan, Indramayu and Cibatu being financed by yen loans since FY2012 for the step-by-step launch of operation by 2015, in which the 500 kV north route will be increased to two routes to transmit power generated at the large power plants to be constructed in T. Jati and J. Tenga.

3) Project to introduce 500 kV transmission equipment to Bali, specifically between Paiton and Kapal for the start of operation in 2015


Final Report 4-8

Table 4.3-5 500 kV Transmission line development plan

COD Province From To Conductor Length (km)

Status

2011 Banten Balaraja Suralaya Baru 2 cct, 4xDove 80 On Going Jabar Ujungberung Inc. (Mdcan-Bdsln) 2 cct, 4xDove 2 On Going

2012 DKI Jakarta Bekasi Tx. Mtawar-Cibinong 2 cct, 4xDove 12 On Going Jatim Surabaya Selatan Grati 2 cct, 4xGannet 160 On Going

2013 DKI Jakarta Durikosambi (GIS) Kembangan 2 cct, 4xZebra 6 On Going Banten Balaraja Kembangan 2 cct, 4xZebra 80 Committed Jateng Tanjung Jati Inc Tx (Ungar-Pedan) 2 cct, 4xZebra 260 On Going Jatim Watu Dodol Lampumerah 2 cct, ACS 380 8 On Going Jatim Lampumerah/Segararupek Gilimanuk 2 cct, 4xDove 20 On Going

2014 Banten Lengkong 500 kV Inc. (Blrja-Gndul) 2 cct, 4xDove 4 Plan Jateng Rawalo/Kesugihan Dbphi (Pedan-Tasik) 2 cct, 4xGannet 4 On Going Jateng Rawalo/Kesugihan PLTU Adipala 2 cct, 4xZebra 4 On Going

2015 DIY Bantul Dbphi (Rawalo-Pedan) 4 cct, 4xGannet 8 Plan Jatim Paiton Watu Dodol 2 cct, 4xDove 262 Propose Jatim Bangil 500 kV Inc. (Piton-Kediri) 2 cct, 4xGannet 4 Propose Bali Gilimanuk New Kapal 2 cct, 4xDove 185 Propose

2016 DKI Jakarta Cawang Baru (GIS) Gandul 2 cct, 4xZebra 40 Propose DKI Jakarta Muarakarang (GIS) Durikosambi (GIS) 2 cct, 4xZebra 30 Plan

Banten Bogor X Inc (Clgon-Cibinong) 2 cct, 4xDove 60 Committed Banten Bogor X Inc (Depok-Tsmya) 4 cct, 4xDove 6 Committed Banten Banten PLTU Inc. (Suralaya - Balaraja) 4 cct, 4xDove 40 Committed Banten Bogor X Tanjung Pucut 2 pole, HVDC OHL 220 Committed Banten Tanjung Pucut Ketapang 2 pole, HVDC CABLE 80 Committed Jabar Tambun 500 kV Inc. (Bkasi-Cibinong) 2 cct, 4xDove 2 Propose Jabar Upper Cisokan PLTA (Kit) Incomer (Cibng-Sglng) 2 cct, 4xGannet 30 Propose Jabar Cigereleng II/Cikalong Dbphi. (BogorX-Tasik) 4 cct, 4xDove 4 Plan

Jateng Pemalang Tx (Ungar-Pedan) 2 cct, 4xZebra 126 Propose Jateng Pemalang Mandirancan 2 cct, 4xZebra 360 Propose Jateng Jateng PLTU Pemalang 500 kV 2 cct, 4xZebra 40 Commited

2017 DKI Jakarta Pulogadung (GIS) Cawang Baru (GIS) 500 kV 2 cct, 4xZebra 24 Plan Jabar Indramayu Mandirancan 2 cct, 4xZebra 200 Propose Jabar Cibatu Baru Inc (Cbatu-Mtwar) 2 cct, 4xGannet 4 Plan Jabar Indramayu PLTU Cibatu 2 cct, 4xZebra 270 Propose Jatim Tandes Krian 2 cct, 4xZebra 40 Plan

2018 DKI Jakarta PLTU Bekasi Muaratawar 2 cct, 4xDove 20 Plan2019 Jabar Matenggeng PLTA Inc (Tasik-Rawalo) 2 cct, 4xDove 20 Plan

Jatim PLTGU Tuban/Cepu Ngimbang 2cct 4xZebra 20 Plan2020 Jatim Grindulu PLTA Inc (Pedan-Kediri) 2 cct, 4xGannet 40 Plan



Final Report 4-9

Table 4.3-6 500kV Substation development plan

(2011 – 2013)

COD Province Substation Project scope Capacity(MVA)

Status

2011 DKI Jakarta Kembangan (GIS) Spare, 1 phase 166 On Going DKI Jakarta Cawang Spare, 1 phase 166 On Going DKI Jakarta Kembangan (GIS) Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going DKI Jakarta Bekasi Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going

Jabar Mandirancan Spare, 1 phase 166 On Going Jabar Cibatu Spare, 1 phase 166 On Going Jabar Bandung Selatan Spare, 1 phase 166 On Going Jabar Depok D Spare 1 phase S 1 se 166 On Going Jabar Mandirancan Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going Jabar Tasikmalaya Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going Jabar Ujung Berung Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going Jabar Bekasi Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going Jabar Depok Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going Jabar Ujung Berung New, 2 dia 6 CB, 2 IBT, 2 TB 150kV 500 On Going

BAnten Balaraja Spare, 1 phase 166 On Going

Banten Cilegon Spare, 1 phase 166 On Going

Banten Cilegon Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going

Jateng UUngaran Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going DIY Pedan Spare, 1 phase 166 On Going

Jatim Krian Spare, 1 phase 166 On Going Jatim Ngimbang Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going Jatim Krian Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going Jatim Grati Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going Jatim Paiton Paiton Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going

2012 DKI Jakarta Durikosambi (GIS) Spare, 1 phase 166 On Going DKI Jakarta Bekasi Spare, 1 phase 166 On Going DKI Jakarta Cawang (GIS) Ext, 1dia2CB, 1IBT, 1 TB 150kV 500 On Going

Jabar Muaratawar Spare, 1 phase 166 On Going Jabar Gandul Spare, 1 phase 166 On Going

Banten Kediri Spare, 1 phase 166 On Going Jatim Surabaya selatan Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going

2013 DKI Jakarta Durikosambi (GIS) New, 4 dia 10 CB, 2 IBT, 2 TB 150kV 1000 On Going DKI Jakarta Kembangan (GIS) Ext, 2 dia 4 CB Propose

Jabar Muaratawar Ext, 2 dia 4 CB, 2 IBT, 2 TB 150kV 1000 On Going BAnten Balaraja Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going BAnten Balaraja Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going Jateng Tanjung Jati Ext, 2 dia 4 CB, 2 IBT, 2 TB 150kV 1000 On Going DIY Pedan Pedan Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going

Jatim Krian Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 On Going


Final Report 4-10

(2014 – 2020)

COD Province Substation Project scope Capacity(MVA)

Status

2014 Banten Lengkong 500 kV New, 4 dia 10 CB, 2 IBT, 2 TB 150kV 1000 Propose Jateng Rawalo/Kesugihan New, 4 dia 10 CB, 1 IBT, 1 TB 150kV 500 On Going Jatim Surabaya Selatan Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 Plan

2015 DKI Jakarta Durikosambi (GIS) Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 Plan DIY Bantul New, 4 dia 10 CB, 2 IBT, 2 TB 150kV 1000 Plan

Jatim Paiton (GIS) Ext, 2 dia 4 CB Propose Jatim Kediri Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 Plan Jatim Bangil 500 New, 4 dia 10 CB, 2 IBT, 2 TB 150kV 1000 Propose Bali New Kapal/Antosari (GIS) New, 2 dia 6 CB, 2 IBT, 2 TB 150kV 1000 Propose

2016 DKI Jakarta Cawang Baru (GIS) New, 2 dia 6 CB, 2 IBT, 2 TB 150kV 1000 Propose DKI Jakarta Muarakarang (GIS) 500 kV New, 2 dia 6 CB, 2 IBT, 2 TB 150kV 1000 Plan DKI Jakarta Durikosambi (GIS) Ext, 2 dia 4 CB Plan

Jabar Tambun 500 New, 4 dia 10 CB, 2 IBT, 2 TB 150kV 1000 Propose Jabar Mandirancan Ext, 2 dia 6 CB Propose Jabar Upper Cisokan PS New, 2 dia 4 CB Propose Jabar Bogor X dan Converter St New, 12 dia 36 CB, 2 IBT, 2 TB 150kV, 2 1000 Propose Jabar Mandirancan Ext, 1 dia 2 CB Propose Jabar Cigereleng II/Cikalong New, 4 dia 10 CB, 2 IBT, 1 TB 150kV 500 Plan

Banten Banten PLTU New, 4 dia 8 CB Propose Jateng Pemalang 500 kV New, 2 dia 6 CB, 2 IBT, 2 TB 150kV 1000 Propose Jateng Jateng PLTU IPP New, 3 dia 6 CB Propose

2017 DKI Jakarta PLTU Bekasi Ext, 2 dia 4 CB Plan DKI Jakarta Pulogadung (GIS) 500 kV New, 2 dia 6 CB, 2 IBT, 2 TB 150kV 1000 Plan DKI Jakarta Cawang Baru (GIS) Ext, 2 dia 4 CB Plan

Jabar Cibatu Ext, 2 dia 4 CB Propose Jabar Cibatu Baru New, 5 dia 13 CB, 2 IBT, 2 TB 150kV 1000 Plan Jabar Indramayu PLTU 1000 New, 4 dia 10 CB Propose Jatim Kediri Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 Plan Jatim Tandes (GIS) New, 2 dia 6 CB, 2 IBT, 2 TB 150kV 1000 Plan

2018 DKI Jakarta Durikosambi (GIS) Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 Plan2019 DKI Jakarta Cawang Baru (GIS) Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 Plan

Jabar Matenggeng PS New, 2 dia 4 CB Plan

Jabar Cirata Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 Plan

Jabar Cirata Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 Plan

Jatim Ngimbang Ext, 2 dia 4 CB Plan2020 Jateng Ungaran Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 Plan

DIY Pedan Ext, 1 dia 2 CB, 1 IBT, 1 TB 150kV 500 Plan Jatim Grindulu PS New, 2 dia 4 CB Plan



Final Report 4-11

Figure 4.3-1 JAWA- BALI 500kV transmission development plan (RUPTL 2011)

SURALAYA1,2

CILEGON

M.TAWAR

GANDUL

CIBATU

CIBNG

CIRATA

SAGULING

DEPOK

BEKASI

CWANG

BANDUNGSELATAN

MANDIRANCAN

KMNGN

BLRJA

UBRNG

IDMYU

DUKSB

LKONG

TMBUN

MKRNG

CWANG2

CSKAN

BANTEN

BOGOR

TPCUT

CBTBR

SURALAYA1,2

CILEGON

M.TAWAR

GANDUL

CIBATU

CIBNG

CIRATA

SAGULING

DEPOK

BEKASICWANG

TASIKMALAYA

BANDUNGSELATAN

MANDIRANCAN

UNGARAN

T.JATI

PEDAN

PAITON

GRATI

KRIAN

GRESIK

KMNGN

NGBNGSBSLT

BLRJA

KEDIRI

UBRNG

IDMYU

PMLNG

BNGILRWALO

BNTUL

CLCAP1,2

DUKSB

LKONG

TMBUN

MKRNG

CWANG2

CSKAN

KAPAL

BANTEN

BOGOR

TPCUT

CIGRE

TUBAN

MGENGGRDLU

CBTBR

JTENG

Existing Power plant T/L S/S Planned (RUPTL2011) Power plant T/L S/S DC line

Introduce 500kV system in Bali (2015)

500kV HVDC line (2015)

Doubling north route (2013-2015)

Source：JICA Study Team


Final Report 4-12

(3) Challenges concerning the Java-Bali system As the large-scale power sources of the Java-Bali system, the Paiton coal-fired power plant

(3,250 MW) and the Suralaya coal-fired power plant (3,400 MW) are located in the eastern and western parts of Java, respectively, and the power sources are thus unevenly distributed in the east and the west. The demand areas, however, are concentrated in the western part of Java, where Jakarta, the capital of the country is located. As a result, as shown in Figure 4.3-2 (Actual power flow), large power of about 2,000 MW is being transmitted over a long distance from the east to the west, giving adverse impacts to the system voltage in the vicinity of Jakarta.

Figure 4.3-2 Actual power flow at night peak load (Feb. 27, Thu., 2011, 7p.m.)

Source：P3B

Also in the future plan based on RUPTL 2011-2020, the power flow remains to be directed to the west. In particular in the diagram of power flow direction planned for 2015, in which most of the committed power sources are incorporated, the west-directed flow is further expanded from that planned for 2011 (Figure 4.3-3).

In 2016, the direct-current interconnected transmission line will start to be operated between Java and Sumatra, and power from the coal mine coal-fired power plant in Sumatra will begin to be supplied through the line. Accordingly, the east-directed flow is mitigated in the diagram for 2020.

However, the power sources in and after 2016 are laid out in the positions that will give advantage to the system, many of which are not committed power sources. It is therefore desirable to formulate specific power source development plans giving priority to the system flow direction and the impacts on the system voltage.


Final Report 4-13

Table 4.3-7 Voltage analysis result

Year Region 1 Region 2 Region 3 Region 4

2011 481.4kV (BKASI7)

487.8kV (CBATU)

500.4kV (UNGRN)

491.8kV (KRIAN)

2015 481.1kV (BKASI7)

485.6kV (UBRNG)

486.3kV (PEDAN)

484.4kV (KDIRI)

2020 469.1kV (MKRNG)

484.3kV (CRATA)

479.0kV (PEDAN)

467.5kV (KDIRI)


Figure 4.3-3 Trend of power flow direction (500 kV system)


(4) System plan for 2025 formulated by the Study Team According to the super long-term projection by PLN, the maximum demand will continue to

increase by 6 to 7% a year also in and after 2020, which will necessitate the development of 2,000 to 3,000 MW coal-fired power generation facilities per year. The Study Team carried out a simulation on

SURALAYA1,2

CILEGONM.TAWAR

GANDUL

CIBATU

CIBNG

CIRATA

SAGULING

DEPOK

BEKASICWANG

TASIKMALAYA

BANDUNGSELATAN MANDIRANCAN UNGARAN

T.JATI

PEDAN

PAITON

GRATI

KRIAN

GRESIK

KMNGN

NGBNGSBSLT

BLRJA

KEDIRI

UBRNG

IDMYU

PMLNG

BNGILRWALO

BNTUL

CLCAP1,2

DUKSB

LKONG

TMBUN

MKRNG

CWANG2

CSKAN

KAPAL

BANTEN

BOGOR

TPCUT

CIGRE

TUBAN

MGENGGRDLU

CBTBR

JTENG

1,572M

1,046M

Year 2011

SURALAYA1,2

CILEGONM.TAWAR

GANDUL

CIBATU

CIBNG

CIRATA

SAGULING

DEPOK

BEKASICWANG

TASIKMALAYA


T.JATI

PEDAN

PAITON

GRATI

KRIAN

GRESIK

KMNGN

NGBNGSBSLT

BLRJA

KEDIRI

UBRNG

IDMYU

PMLNG

BNGILRWALO

BNTUL

CLCAP1,2

DUKSB

LKONG

TMBUN

MKRNG

CWANG2

CSKAN

KAPAL

BANTEN

BOGOR

TPCUT

CIGRE

TUBAN

MGENGGRDLU

CBTBR

JTENG

2,145M

1,205M

Year 2015

SURALAYA1,2

CILEGONM.TAWAR

GANDUL

CIBATU

CIBNG

CIRATA

SAGULING

DEPOK

BEKASICWANG

TASIKMALAYA


T.JATI

PEDAN

PAITON

GRATI

KRIAN

GRESIK

KMNGN

NGBNGSBSLT

BLRJA

KEDIRI

UBRNG

IDMYU

PMLNG

BNGILRWALO

BNTUL

CLCAP1,2

DUKSB

LKONG

TMBUN

MKRNG

CWANG2

CSKAN

KAPAL

BANTEN

BOGOR

TPCUT

CIGRE

TUBAN

MGENGGRDLU

CBTBR

JTENG

724MW

542MW

Year 2020


Final Report 4-14

the introduction of a large-scale coal-fired power plant (with the unit capacity of 1,000 MW) in and after 2020, targeting the suburbs of Jakarta, which is a demand area, as a candidate for the power plant construction site, with a view to mitigating the west-directed power flow caused by the uneven distribution of power sources.

Table 4.3-8 and Figure 4.3-5 show the specific power plant development list made in the simulation. Of 14,000 MW to be developed over the period from 2020 to 2025, the Study Team assumed that more than half (8,000 MW) would be developed in Region 1, where Jakarta is located.

By the development of the power source, the power flow will begin to be directed to the east from the western part of Java, and as a result the west-directed flow from the eastern part of Java will be substantially mitigated (Figure 4.3-4).

Table 4.3-8 Voltage analysis result

ower plant Capacity Total

Region 1

Bojonegara 1,000MW x 2unit

8,000MW Sujung 1,000MW x 2unit Tanjung Pakis 1,000MW x 2unit Tanjung Sedari 1,000MW x 2unit

Region 2 - - 0MW

Region 3 Central Java 1,000MW x 2unit

5,000MW Tanjung Jati B 1,000MW x 1unit Adipala 1,000MW x 2unit

Region 4 Gresik 1,000MW x 1unit 1,000MW Total 14,000MW


Figure 4.3-4 Trend of power flow direction (500kV system) in 2025


96MW

1,217M


Final Report 4-15

Figure 4.3-5 JAWA- BALI 500kV power system in 2025 by JICA Study Team Study Team

SURALAYA1,2

CILEGONM.TAWAR

GANDUL

CIBATU

CIBNG

CIRATA

SAGULING

DEPOK

BEKASICWANG

TASIKMALAYA


T.JATI

PEDAN

PAITON

GRATI

KRIAN

GRESIK

KMNGN

NGBNGSBSLT

BLRJA

KEDIRI

UBRNG

IDMYU

PMLNG

BNGILRWALO

BNTUL

CLCAP1,2

DUKSB

LKONG

TMBUN

MKRNG

CWANG2

CSKAN

KAPAL

BANTEN

BOGOR

TPCUT

CIGRE

TUBAN

MGENGGRDLU

CBTBR

JTENG

Existing Power plant T/L S/S Planned (RUPTL2011) Power plant T/L S/S DC line Proposed (JICA Study Team) Power plant T/L

Adipiala 1,000MW x 2unit

Tanjung Jati B 1,000MW x 1unit

Central Java 1,000MW x 2unit

Gresik 1,000MW x 1unit

Source：JICA


Final Report 4-16

4.4 The current situation and issues to finance power supply

(1) PLN’s financial situation In Indonesia, PLN’s average supply cost of electricity is higher than its average sales price. The

figure below illustrates electricity tariff and generation cost, the differences per kWh were 97.8 Rp. and 96.5 Rp. in 2009 and 2010, respectively. In order to compensate the gap between (i) the supply cost including transmission and distribution costs in addition to this generation cost plus PLN’s margin and (ii) the average sales tariff, the government provides the large amount of the subsidies to PLN every year.

3470 12511 32909 36605 78577 53720 58108

581.75

590.91

628.14 629.18 653.00 670.02699.09

351.34

469.78

705.96 706.62

1051.84

767.79795.59

0

200

400

600

800

1,000

1,200

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

2004 2005 2006 2007 2008 2009 2010

Ave

rage

tari

ff,

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rage

gen

erat

ion

cost

（Rp

./kW

h)

Gov

ernm

ent S

ubsi

dy (

bn. R

p.)

Government subsidy(bn. Rp.)

Average tariff（Rp/kWh)

Average generation cost(Rp/kWh)

Figure 4.4-1 Electricity price, generation cost and the subsidy for PLN Source: PLN statistics 2009, 2010, PLN Annual report

Despite provision of the subsidies, PLN’s net income has been in deficit until 2008, but the it became positive after 2009. However, there are no changes in dependence on the subsidy and the net income will be negative if there are no subsidies.

Table 4.4-1 PLN’s financial situation and subsidy from the government

(Unit: 1 billion Rp.) Year 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Government subsidy

4,739 4,097 3,470 12,511 32,909 36,605 78,577 53,720 58,108 93,178

Net profit -6,060 -3,558 -2,021 -4,921 -1,928 -5,645 -12,304 10,356 10,087 7,193

(Source: PLN Consolidated Financial Statement 2011, PLN Annual Report 2008, 2009 and 2010, Japan Electric Power Information Center)

The fundamental problem of this financial situation is that the tariff increase has been limited. As a

result, the financial situation was deteriorated because of increase of the fuel costs or the power purchase costs from IPP (the fuel costs are pass-through). The fiscal burden due to the subsidy for


Final Report 4-17

PLN is the great concern for Indonesian government, therefore the government is trying to increase the tariff, which is the fundamental solution to the problem, but it is not easy due to the objection from the citizens and industries and the approval from the cabinet required according to the revision of electricity law in 2009. Furthermore, the fuel cost is in principle denominated in US dollars, while the tariff is in Rupiah and the fluctuation of the fuel costs and exchange rate cannot be transferred to the electricity tariff; this negatively affects PLN’s profits. In addition, PLN’s sales margin is also not stable revenue and it might put pressure on PLN’s financial situation, as its reduction from 8% to 3% is requested by Ministry of Finance. On the other hand, PLN has responsibility to supply stable electricity in Indonesia, even if PLN’s financial standing is not necessarily stable like this. Therefore, if PLN can receive the finance with low interest and long repayment upon construction of the power plants, PLN can enhance power supply capacity while reducing the financial burden for PLN.

(2) Challenges to receive finance in case of IPP projects Electricity demand in Indonesia is increasing and IPP projects are also increasing in power

development together with PLN led projects over next 5 years.

Table 4.4-2 Electricity sales (Unit: GWh)

Year 2005 2006 2007 2008 2009 2010

Electricity sales 107,032 112,609 121,246 129,018 134,581 147,297

Source: PLN Annual Report 2010

Table 4.4-3 Generation volume (Unit: GWh)

Year 2005 2006 2007 2008 2009 2010

PLN 98,177 101,664 107,984 113,340 115,434 123.477

IPP 26,088 28,639 31,199 31,389 36,169 38.076

Generation by lease 3,105 2,804 3,257 4,707 5,194 8.233

Total generation 127,370 133,108 142,440 149,436 156,797 169.786

Source: PLN Annual Report 2010

In the project list in 2nd crash program to accelerate power development (MEMR Ministerial degree 2010/02, 2010-2014), there are IPP projects with 6,235 MW18 while PLN projects are 3,757MW18. On the other hand, according to RUPTL 2011-2020, electric power development until 2020 including 2nd crash program will be mainly led by IPP until 2018 after 2014 but this reliance will be decreased step by step the ratio to be developed by PLN will be higher than the one by IPPs in 2019. There are similar tendency for the coal-fired plants and in 2019, the ratio of PLN will be higher.

18 RUPTL 2011-2020


Final Report 4-18

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Coa

l-Fire

d

Tota

l

Coa

l-Fire

d

Tota

l

Coa

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Coa

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d

Tota

l

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

MW

Capacity expansion plan

IPP

PLN

IPP Coal-fired

PLN Coal-fired

Figure 4.4-2 Capacity expansion plan Source: Prepared by study team based on RUPTL 2011-2020

In order to promote international IPPs to get into the market, international banks require Indonesian

government guarantee against PLN’s credit risk for the bank finance. IPP projects can be based on PPP scheme following Presidential decree 67/2005 and Presidential decree 2010/13. However, this PPP scheme is still new in Indonesia as the 1st project just finished bidding and the establishment and improvement of the implementation process are expected in the future.


Final Report 5-1

Chapter 5 Introduction of CCT roadmap 5.1 Policy on the CCT Introduction Roadmap

In Indonesia, demand for electric power has been increasing in accordance with the country’s remarkable economic growth, and to meet the increasing demand, a range of power source development plans have been implemented in the country. In the power source diversification promoted based on the policy of decreasing dependence on oil in response to the feared depletion of the resource and to the soaring oil prices, coal-fired power generation, the output of which can be increased at lower costs, will play a central role in the future power source development. In particular in the Java-Bali area, it is planned to develop a total of 22.6 GW coal-fired power plants over 10 years from 2011 to 2020 (RUPTL2011), which accounts for 70% of the total output of 32.1 GW planned for the period. The country will not change its power source development policy also in and after 2021, and so coal-fired power generation will continue to be a dominant power source in the power source development plan.

On the other hand, CO2 emissions from coal-fired power generation are characteristically large compared with other power sources. Indonesia upholds the target of reducing its GHG emissions by 26% relative to the business as usual (BAU) scenario by 2020, and needs to increase the efficiency of its power plants to meet this target. The improvement of efficiency will also help reduce the consumption of coal, which is now increasing in the country and lead to more effective use of coal resources.

In Japan the efficiency of coal-fired power plants has been improved and the introduction of the technology together with other environmental technologies to Indonesia is expected. The target of the technology to be introduced to the country for more efficient power generation will be the ultra-super critical (USC) and integrated gasification combined cycle (IGCC) technologies, and for the creation of a CCT introduction roadmap toward 2025, examinations will be made on the introduction timing in consideration of the situation in Indonesia from technological, policy and economic aspects.

Specifically, following items will be examined.

< Examination items > 1) Technological aspect

Present situation and challenges for CCT development

Examination of the introduction timing to Indonesia

2) Policy aspect

Types, reserve, and future prices of the coal resources to be used

Consistency between the use of the coal resources and the policy

CO2 emissions achieved through the CCT introduction

3) Economic aspect

Economic assessment on the CCT to be introduced


Final Report 5-2

5.2 Characteristic of the high efficiency coal thermal power plant technology to make study on introduction

In Indonesia, construction of the Ultra Supercritical Critical pressure (following, USC) power plants are planed which the Central Java Coal-fired thermal power plant (1,000MW×2units, IPP, COD will be 2017) Indra Mayu Coal-fired thermal power plant (1,000MW×1unit, ODA projects, COD will be 2017) and the Development program of PLN will be expected the application of USC technology and the integrated gasification combined cycle (following, IGCC) technology which achievement of operation are accumulated in the future.

JICA Study Team organized about technology of not only USC also IGCC which is great potential for high efficient technology in the future.

(1) USC Power generation : 1) Characteristic of technology

The steam condition of Coal-fired thermal power plant in Indonesia are sub-critical and super critical (SC), these maximum plant efficiency (from 35% to 40 %) lower than USC plant, Because of this, to adopt the USC is expected to make a contribution for the fuel consumption reduction and CO2 emissions reduction.

The boiler which is used under the steam conditions of the SC and USC are used one through type because these boilers are quick response for a load.

(a) Definition of Steam condition

Definition of Steam condition of Sub-critical, SC and USC are as follows:

Sub critical: Main steam and Reheat Steam temperature at turbine inlet; < 22.1MPa, ≤ 566ºC

SC (super critical): Main steam and Reheat Steam temperature at turbine inlet; ≥22.1MPa, ≤ 566ºC

USC (Ultra Super Critical): Main steam and Reheat Steam temperature at turbine inlet; ≥22.1MPa, >593ºC

In addition, USC technology was a technique on the extension line of the SC technique, and USC technology was merely only as supper critical worldwide before, but USC and the name to say penetrated because the results of the thing more than 593 degrees Celsius increased temperature on the condition that was super more than critical point (SC) about the steam state in the steam turbine inlet in after 1989.

2) USC technology: The steam condition of the coal thermal power generation technology used all over the world is

sorted by sub-critical, SC and USC.

The change of the steam condition of the coal-fired thermal power plant in the World is shown in Figure 5.2-1.and the change of the steam condition of the coal-fired thermal power plant in Japan


Final Report 5-3

shown in Figure 5.2-2.

0

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1950 1960 1970 1980 1990 2000 2010

18.6

24.1 24.525.0

16.6

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5.84.1

450

510

593600

610

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Stea

m P

ress

ure

[MPa

]

Stea

m T

empe

raur

e [ ℃

]

#2(24.1MPa 593/593C)

磯子新1

(24.1MPa 600/610C)

橘湾#1,2(25.0MPa 600/610C)

磯子新2(25.0MPa 600/620C)

620

USC 技術開発

（国プロ） J-POWER

USC

超臨界

亜臨界538

566

482

12.510.0

Phase-1 Phase-2

Eddystone(34.5MPa,649/566/566)

Philo No.6(31.0MPa,621/566/538)

Super Critical

Sub Critical 538

Japan AJapan B

Japan C

Japan D

USC developmentPeriod

Figure 5.2-1 The change of the steam condition of the coal-fired thermal power plant in the World


1990 1995 2000 2005 2010 2015 2020 2025

Effic

ienc

y (%

Net

, LH

V)

55

50

40

538℃566℃

600℃

Main Steam Temp.

Efficiency

Mai

n St

eam

Tem

p. (℃

)

650

600

550

500

USCSCIGCC

1700℃Class Gas

Turbine

1500℃Class Gas

Turbine

A-USC45

35

593℃

Effic

ienc

y (%

Net

, LH

V)

55

50

40

538℃566℃

600℃

Main Steam Temp.

Efficiency

Mai

n St

eam

Tem

p. (℃

)

650

600

550

500

USCSCIGCC

1700℃Class Gas

Turbine

1500℃Class Gas

Turbine

A-USC45

35

593℃

Figure 5.2-2 Change of the steam condition of the coal-fired thermal power plant in Japan Source: JICA Study Team


Final Report 5-4

(a) Deference of SC and USC (Steam condition, deference of plant efficiency and material)

[Steam condition and deference of plant efficiency] Steam condition (SC, USC) and plant efficiency are subjected by manufacturer of generating

facilities and steam condition, in general it is acquired the high efficiency by increase the pressure and temperature. Relations of steam condition and plant efficiency layout in power plant are shown in Table 5.2-1.

Table 5.2-1 Relations of steam condition and plant efficiency

Steam condition Plant efficiency (Gross) (%)

S

C

24.1MPa/538°C/538°C 100.00（base）

24.1MPa/538°C/566°C 101.24

24.1MPa/566°C/566°C 104.34

U

S

C

24.1MPa/566°C/593°C 105.21

24.1MPa/593°C/593°C 105.96

25.0MPa/600°C/610°C 106.95

25.0MPa/600°C/620°C 107.20


[Material]

The facilities configuration of the USC power plant is almost similar to SC power plant, however It is a steam condition which exceeds SC power plant in the main steam pipe and hot reheat pipe which connect a boiler, super heater and a main turbine especially in the portion which high temperature and high- pressurization influence, and material with a higher grade (high chromium steel) is used.

(improvement, developed materials are used in consideration of high temperature creep strength, steam oxidation properties about the turbine materials including the high temperature corrosion, steam oxidation characteristic high temperature creep strength about the boiler materials.)

(b) Outline of the Boiler type

Outline of the Boiler type for Dram type and Once-through type are shown in Figure 5.2.3.

SC and USC type of Boiler is not much different, a number of super heater portion are increase requirement for high-temperature steam.


Final Report 5-5

Figure 5.2-3 Deferent point of drum type and one through type of Boiler Source：JICA Study Team

(c) Introduction situation of the USC power plants in the world

86 ultra-supercritical pressure coal-fired power plants are having commercial operation in the world at the end of 2010.

It is assumed that the adoption of the ultra-supercritical pressure coal-fired power plants advances in future in the Southeast Asian countries where economic growth is remarkable by the rise in coal price and a surge of the CO2 reduction needs.

Figure 5.2-4 (a) A n operating USC Power Plants in major countries Source：JICA Study Team

Drum Boiler Benson Boiler Sulzer Boiler One-through Boiler


Final Report 5-6

Figure 5.2-4 (b) Number of operating USC Power Plants in major countries Source：JICA Study Team

(d) The development circumstances of USC in Japan

In the coal-fired power plants of Japan, re-heat steam temperature of 593 degrees Celsius was adopted in the third unit of Hekinan power plant, Chubu Electric Company in the early 1990s, and the times of the USC technique started operation.

Japan worked on the high efficiency of the coal-fired power plant for the purpose of reduction of the environmental impact load, high efficiency of the energy positively and, in the second unit of new Isogo power plant of J-Power which was started of the commercial operation in 2009 that power plant adapted steam condition of 25MPa for main steam pressure, 600 degrees Celsius for main steam temperature and a 620 degrees Celsius for re-heat steam temperature.

(2) Integrated coal Gasification Combine Cycle (IGCC) IGCC (Integrated Gas Combined Cycle)is the compound power generation method which is

composed of coal gasification facilities, gas purification plant and gas turbine generator, the gross thermal efficiency is supposed to be about 5 % higher than the power generation way of usual coal heating power. Each advanced country constructs and studies the demonstration plant of the coal gasification facilities and makes the technical development of the coal gasification main constituent. Each advanced country constructs the demonstration plant of the coal gasification facilities and the technical development is doing studies for the coal gasification.

Also, each gas turbine manufacturer tackles the improvement of the combustion temperature of the gas turbine and heat efficiency improvement.

1) The characteristic of the technology The gross-thermal-efficiency is 48 % in the 1500 °C combustion temperature class by the

proven technology of the gas turbine power plant, and when raising a combustion temperature, the heat efficiency improves more from now,


Final Report 5-7

CO2 emission is under the influence by the heat efficiency therefore the IGCC technology is the most excellent technology for the reduction of the CO2 emission.

There are several methods (Dry Feed Air Blown Entrined Bed and Entrained Flow, Oxygen Dry Feed Slugging) in the coal gasification technology then, the reduction of the construction cost of the plant and the improvement of the heat efficiency will be main subject.

Technical characteristics of Comparison with the conventional Boiler and IGCC are shown below Table 5.2-2.

Table 5.2-2 Technical characteristic (Comparison with the conventional boiler and IGCC)

Item Pulverized coal Boiler IGCC

Fuel facilities Coal-Pulverizer and coal feeder Coal Gasification Facilities

Plant facilities Pulverized coal fired boiler Gas Turbine and HRSG

Steam Turbine Generator Steam Turbine Generator

Generation max.

capacity

1,000 MW/Unit 250 MW（500 MW～650 MW*1）

Plant Efficiency 43％(USC) 48％

(1500degree C Crass)

CO2 Reduction The quantity of CO2 reduction has a

limit by power plant thermal

efficiency.

There is possibility of the more CO2

reduction by the power plant thermal

efficiency improvement

Note *1；The target value in 2015～2020


Outline Diagram of IGCC IGCC is divided into the gas turbine power generation plant and coal gasification plant and.

Major equipment of the gas turbine combined cycle power plant consists of the steam turbine, HRSG and generator, and other auxiliary facilities. And Coal gasification plant consists of the coal gasification furnace, coal gas treatment system, air blower units and coal gas filtering unit


Final Report 5-8

CONDENSER

COMBINED CYCLE POWER PLANTGASIFICATION UNIT

COAL GAS TREATMENT &COAL GAS FLIRTING UNITs

GASIFICATION UNIT

COALHOT AIR

STACK HRSGFUEL GAS

HP HOT AIR

COMPRESSOR

CIRCULATINGCOOLING WATER

MAIN STEAM

STEAM TURBINE

POWERGENERATORGAS TURBINE

GHP IP LP

M

M

LP IP HP

FLUE GAS

FEED WATER

CONDENSATE WATER

DEMINERALIZED WATER

Figure 5.2-5 Outline Diagram of IGCC Source：JICA Study Team

2) The development circumstances in the world <The U.S>

Some IGCC demonstration plants were constructed in the 1990s but the heat efficiency can not be improved from about 40 %. And the construction of commercial IGCC power plant isn't planned now.

<EU> In the beginning of the 2000s in Italy, the three IGCC power plant project began operation.

However, IGCC plant was not coal and fuel used residual oil also he support by the political of electric-power selling contract for which it is possible to collect a fee and so on was indispensable..

<Japan> The demonstration plant of 250 MW was constructed of about 1/2 scales (500MW～600MW)

for the commercial plant on 2007. and It is implementing a test-operation. It completed a durable audit test for 5,000 hours in 2010. The plant implementation test (The type-of-coal conformability, the design and operation technology establishment and so on) plan will be completed of the IGCC technology in 2011～12.

The coal-fired power plant which is planned in the future is required to reduce the emission of maximum CO2 using the technology of the highest level of the IGCC technology about which it is possible to adopt.

The demonstration plant which combined IGCC and CCS facilities is constructed until 2017.


Final Report 5-9

Table 5.2-3 Current situation of IGCC in the World

Majored IGCC plant in the world Project name (country） Type of Grassfire Gas Turbibe Rated out-put

（MW） Operation date Continuous operation time (hr)

Puertollano ELCOGAS (Spain) Prenflo （Oxygen）

Siemens V94.3 318 Nov.1997 984

Buggenum Nuon （Holland）

Shell （Oxygen）

Siemens V94.2 284 Jan.1994 3291

Wabash River （USA）

E-Gas （Dow）

（Oxygen）

GE 7FA 296 Aug.1995 1560

Tampa Electric （USA）

GE （Texaco）（Oxygen）

GE 7FA 315 July.1996 1008

Under construction and Planed IGCC Project

Project Name (Country） Owner Fuel Grassfire GT

Rated out-put （MW）

Original commercial operation date Situation

Edwardsport （USA IN）

Duke Energy （Electric utilization

company） Coal GE GE 618 (net) 2012 Under

construction

GreenGen Stage1 （China Tenshin）

Green Gen （Hua Neng

Dian Li Gong Si etc）

Coal HCERI Simens 265 2012 Under

Construction

Korea IGCC R&D project

(Korea）

IGCC RDD&D

Organization

Coal SHELL Unclear 380 2016 Under

construction

CPI- Langfang （China）

China Power Investment

Coal Unclear Unclear 400x2 N.A FS

Note: FS（feasibility study） CO2 Reduction plant with IGCC

Project Name (Country） Owner Fuel Grassfire GT

Rated out-put （MW）

Original commercial

operation date Situation

Green Gen Stage2 （China）

Green Gen （Hua Neng

Dian Li Gong Si etc） Coal

Unclear Unclear 400

+ H2 Product 2015～20 FS

Kemper （USA MS）

Mississippi Power （Electric company） Lignite KBR Siemens 524(net)

+ duct firing 2014 Under Construction

Don VALLEY （Eng） TPG capital Coal SHELL GE 900 N.A FEED

Tilbury （Eng）

RWE （Electric company） Coal Unscheduled Unscheduled 450 2014 FS

Clean Hydrogen Power Generation

（USA CA）

Southern California Edison Coal Unscheduled Unscheduled 500 2016 FS

Hydrogen Energy California （USA CA）

Hydrogen Energy California

Petocoke / Coal

MHI （oxygen method）

MHI 400 + Urea Product 2017 FEED

Texas Clean Energy （USA TX）

Summit Power （Electric company） Coal Siemens Siemens 400

+ Urea Product 2014 FEED Completed

Note: FEED（Front End Engineering & Design）,FS（feasibility study） Source: Crean Coal Power Institute

http://www.ccpower.co.jp/igcc/foreign_situation.html


Final Report 5-10

(3) CCS technology While forests and oceans as large carbon sinks are to be contributing to reduce CO2 and other

GHGs, what we have seen during the last years in developing countries is progressing degradation of these sinks; forests and peatlands are decreasing in number as well as in scale through replacement by farmlands, forest fires, etc. REDD (Reduced Emissions from Deforestation and Forest Degradation in Developing Countries) and its successor REDD+ have been developed and projects have been tried out under the scheme to address the issues through preventing measures against forestry destruction and degradation.

In the meantime, potential of Carbon Capture and Storage, CCS, for a large scale coal-fired power plant like the model coal-fired power plant that has been studied in this Study is reviewed and developed worldwide. CCS is deemed to be an effective technology that may reduce CO2 emissions directly from the source, though it should be noted that some environmental issues such as possibilities for groundwater contamination or leakage to the ground and to the sea should be considered and addressed. 1) CCS

CCS (Carbon Dioxide Capture and Storage) which is the technology of controlling to the rising levels of carbon dioxide in the atmosphere by separating and capturing carbon emissions, storage and isolation carbon emissions in the underground or deep-sea which is CO2 emissions from large scale source over the long term, it will be helpful to global warming countermeasures through the emissions reduction on the sift to low carbon component fuel, promote renewable energy and the energy efficient.

2) Characteristic of CCS CCS differs from renewable energy and the energy efficient, it is specialized global warming

countermeasure and economic incentive is not able to function alone.

It is necessary for it to solve the problem which improving of the legal system, environment and safety, social acceptability; of course, they have the effect of cost performance by advancement of technology.

In the solution to such problem, it is important to perform a discussion with proof scientific enough based on an international meeting trend.

3) Configuration of CCS CCS consisting of four functional categories which separating and capturing, transportation, press

fit and storage.

Variety of the separating and capturing are such as chemical absorption technique, physical absorption technique, membrane separation, physical absorption and cryogenic separation. Technology of capturing high levels of CO2 has been developed by oxygen combustion directly.


Final Report 5-11

4) CCS image Image of the CCS (Figure 5.1-6) is as follows

Figure 5.2-6 Image of the CCS Source: Scottish Carbon Capture & Storage, School of Geo Sciences, University of Edinburgh

Image of the underground storage system (Figure 5.2-7) are as follows

Separation & collection Transfer Pressurizedinjection

Storage site(in land) Separation & Collection

Storage site on shore)

Pipeline transferPressurew ell

Seal

Storage

Impermeable mudstone of water and gas

Sandstone including salt water

Figure 5.2-7 Image of the underground storage system Source：RITE(Research Institute of Innovative Technology for the Earth)

CO2Underground storage technology is to store to the sandstone bed containing salt in deep underground among the CCS technology which storage to the CO2 which separated and captured from thermal power plants etc, extreme care should be select the layer impervious to water or gas as same as the mudstone bed are stored the natural gas and petroleum.


Final Report 5-12

5) CO2 separation technology in CCS CO2 separation technology consisting are three functional categories.

Note: ASU (Air Separation Unit)

Figure 5.2-8 CO2 Image of the separation Technology Source: JICA Study Team

6) The current CCS situation in Japan CCS are in the early stages of verification test, CO2 separation technology are on trials stages, CO2

Underground storage and deep sea storage are on capability investigation of selection about candidate for storage sites, equipment of underground and deep-sea are not quite advanced enough yet due to construction costs are high in Japan.

7) The current CCS situation in Indonesia In the technological study about the CCS transportation with storage in Indonesia, The promising

point, Indonesia CCS Working Group will inquire as follows as "Understanding Carbon Capture and Storage Potential In Indonesia" in November, 2009, And it has been reported.

Boiler

Boiler

Flue-gas treatment

CO2 separation

Compression

Flue-gas

treatment

Compression

Storage

Storage

Fuel

Fuel

Air

Air

Exhaust recirculation CO2

After combustion capture system

Oxygen combustion system

Thermal power generation (SC, USC)

Cooled

酸素又は

IGCC Power generation

Before combustion

capture system

Compression CO2 Storage

Fuel

O2 or Air

Gasification furnace

Gas purification

CO2 separation

Shift CO


Final Report 5-13

At present, a CCS application promising point is as follows.

Figure 5.2-9 CCS application promising point at Indonesia Source: Indonesia CCS Working Group

8) Policy and technology development of CCS in the international sphere

EU under its Renewable Energy Package and Climate Change that referred to among others the potential

of CCS issued a directive no. 2009/31/EC, which stipulates implementation of storage site survey,

obligation of a CCS FS upon new construction of a coal-fired power plant, obligation of CCS

implementation should high potential be acknowledged in such new construction, etc. as the acceleration

policy for CCS development and utilization. Following the move, NER300, a fund aiming at financing

renewable energies and CCS was established, with which EU showed to the world its firm position to

pursue the possibility of CCS as one of the options to enhance its emission reduction policies while

remaining to the principle of environmental considerations including continuous monitoring obligation by

the implementer.

In the meantime, Germany put off introduction of CCS due to the disapproval of its people toward

utilization of the technology. U.K., once announced to extend a financial support to the first CCS project in

the country has yet to see any progress.

All in all, whether commercial or non-commercial, no coal-fired power project with CCS has come true.

Only two commercial CCS projects are found in EU; CCS in Sleipner gas field in Norway since 1996 and

the other with Snohvit LNG Project since 2008.

U.S. saw a sound progress; in Frio, Texas, a pilot project was implemented, through which criteria for

determination of optimal condition and quality of saline aquifer for the long-term CO2 storage. Also in


Final Report 5-14

Texas a commercial-based 200MW IGCC is planned to commence its operation in 2015. This CCS with

IGCC is aiming at capture of 90% CO2, which is to be utilized for EOR（Enhanced Oil Recovery）.

COP17/CMP7 after many years of arguments has approved CCS as applicable to CDM on strict

conditions in monitoring and measures in case of leakage. On the same occasion, CCS was decided to be

applicable as the target area of GCF that was introduced in 2.2. (7) of this Report. While the actual

applicability should be determined according to the progress of commercialization, the decisions cleared

the way to future materialization of coal-fired power plant with CCS under CDM or any other offset credit

mechanism that may come in place in the near future.

5.3 The Outlook for Coal Resources

(1) The Outlook for Coal Resources in Indonesia According to the report published in 2010 by the Geological Agency of the Ministry of Energy and

Mineral Resources, Indonesia's coal resources amount to 104.8 billion tons (see Figure 4.2.1). Most of the resources are located in Sumatra (52.5 billion tons) and Kalimantan (51.9 billion tons). Indonesian coal is classified by calorific value (air-dry basis). Coal with a calorific value of 7,100kcal/kg or more is classified as "very high rank coal," 6,100–7,100 kcal/kg as "high rank (bituminous) coal," 5,100–6,100 kcal/kg as "medium rank (sub-bituminous) coal," and 5,100 kcal/kg or less as "low rank (lignite) coal." Using this classification, bituminous coal, sub-bituminous coal, and lignite coal account for 14%, 66%, and 20% of total coal resources, respectively (i.e., 86% is comprised of lower-ranked sub-bituminous and lignite coal).

Total coal reserve is estimated at 21.3 billion tons, of which 11.2 billion tons are located in Sumatra, and 9.9 billion are in Kalimantan. By coal classification, bituminous, sub-bituminous, and lignite coal account for 11%, 60%, and 29% of total reserves respectively, which means that 89% is comprised of the lower-ranked sub-bituminous and lignite coal.

Most of Indonesian coal is present in Kalimantan and Sumatra. In Kalimantan, the largest reserves are present in East Kalimantan and South Kalimantan. Most of the Kalimantan coal is bituminous or sub-bituminous grade. In Sumatra, approx. 60% of coal reserves are located in South Sumatra. Most of the South Sumatran coal is classified as low grade.


Final Report 5-15

Reserves : 21,13 b. tLignite : 29 %Subituminous : 60 %Bituminous : 11 %

11.23 b.t

Resources : 104,842 b. tLignite : 20 %Subituminous : 66 %Bituminous : 14 %

52.53 b.t

b.t : billion tons

0.01 b.t

51.92 b.t

0.23 b.t 0.002 b.t 0.15 b.t

9.90 b.t


11.23 b.t


52.53 b.t

b.t : billion tons

0.01 b.t

51.92 b.t

0.23 b.t 0.002 b.t 0.15 b.t

9.90 b.t


11.23 b.t


52.53 b.t

b.t : billion tons

0.01 b.t

51.92 b.t

0.23 b.t 0.002 b.t 0.15 b.t

9.90 b.t

Figure 5.3-1 Indonesian coal resources and reserves

Figure 5.3-2 shows the changes in the volume of Indonesian coal resources. As of 2004, the amount of coal resources in Indonesia was estimated at 60.5 billion tons. In the same year, a Japan-Indonesia joint project was launched to analyze/investigate Indonesia's coal resources. During the project, a detailed assessment of coal resources in South Sumatra, East Kalimantan, and South Kalimantan was carried out. As a result, the estimate for 2007 increased significantly to 93.4 billion tons. Since then, in response to the increasing coal demand, more exploration, development, and production activities have been conducted in new and existing mining areas. Consequently, more resource volume data have been added and coal resources as of 2010 have reached 105.2 billion tons. This increase is mainly attributable to medium- and low-rank coal.

0

20

40

60

80

100

120

2004 2007 2010

Billion ton

Low (<5100) Medium (5100-6100)High (6100-7100) Very High (>7100)

66%

20%

13%

Figure 5.3-2 Change in Indonesian coal resources (2004-2020) Source: Indonesian Coal Book 2010/2011 (Indonesia Coal Mining Association)

Source: Geological Agency, 2010, and other sources


Final Report 5-16

As shown by the figure above, only a small part of Indonesian coal is comprised of high clarification (bituminous) coal, and the rest of low grade (sub-bituminous or lignite) coal. As the bituminous coal is produced mainly for export purposes, the domestic market is generally supplied with medium- and low-rank coal. Table 5.3-1 illustrates the properties of leading low-rank coal brands, which accounts for a large part of Indonesia's coal resources. As shown in the table, low-rank coal has high moisture content and low calorific value. Moreover, due to the lower ash melting point compared to typical bituminous coal, low-rank coal is likely to cause ash deposits when burned in a boiler furnace etc.

Figure 5.3-3 shows the general properties of low-rank coal and its characteristics when used. Low-rank coal has a low calorific value because of its high moisture content, low carbon content, and high oxygen content. Furthermore, owing to its porous structure and resultant large surface area, low-rank coal is highly pyrophoric. On the other hand, its high volatile content contributes to high combustibility. In addition, due to the high gasification reactivity and low ash melting point, low-rank coal is suited for entrained bed gasification. Therefore, in the future, it can be used as raw fuel for IGCC power plants.

Table 5.3-1 Properties of Indonesian Low rank coal

Coal A B C D

Region S.Kalimantan E.Kalimantan E.Kalimantan S.Sumatra

Moist. (%, GAR) 35 45 45 60

CV (kcal/kg, GAR) 4200 3400 3400 2400

AFT (℃ ; Reducing)Initial DeformationHemisphericalFluid

112611541192

117912301289

122812471268

112011701380

Resources (million ton) 1,608 281 9,527 2,000

Source: JICA study team

High Moisture ▲▲Low Heating ValueLow Heating Value

Low C, High OxyLow C, High Oxy

High Porosity/Pore VolumeHigh Porosity/Pore Volume ▲▲Spontaneous CombustionSpontaneous Combustion

High VMHigh VM ○○Good CombustibilityGood Combustibility

Low Ash, S Low Ash, S ○○Low Environmental Problems Low Environmental Problems

High Gasification Reactivity High Gasification Reactivity ○○Application for IGCC Application for IGCC

Low Ash Fusion Temp.Low Ash Fusion Temp.

Figure 5.3-3 Properties of Low rank coal for Power Plant fuel Source: Y. Otaka, （JCOAL Coal Technology Conference 2006）


Final Report 5-17

(2) Coal Price Outlook An essential step in forecasting future coal price is to project future coal consumption. Figures

5.3-4 and 5.3-5 show GDP and coal consumption forecasts up to 2035 by the US Energy Information Administration. The forecasts clearly show that while the GDP of OECD member countries (developed countries) will continue to grow, the GDP of non-OECD member countries (developing countries) will increase sharply to reach the level of developed countries by around 2015 and will continue to grow thereafter at a faster pace than the developed countries. Energy consumption will also increase significantly in conjunction with high economic growth,. As illustrated by Figure 4.2-5, energy consumption in China, India, and other Asian countries will rise rapidly and coal is expected to become the primary source of energy in the future because of its lower price compared to oil or gas and the large amount of resources,.

0

20

40

60

80

100

1990 2000 2007 2015 2025 2035

trilllion 2005 U.S. dollars

OECD

Non-OECD

History Projections

Figure 5.3-4 Outlook of OECD and Non-OECD total GDP Source: International Energy Outlook 2010 (US. Energy Information Administration）

Figure 5.3-5 Coal Consumption of OECD and Non- OECD ASIA Source: International Energy Outlook 2010 (US. Energy Information Administration）

quadrillion Btu

0

40

80

120

160

1990 2000 2007 2015 2025 2035

Non-OECD Asia

OECD

History Prediction


Final Report 5-18

1) Coal Demand and Supply Planning

In view of its vibrant economy, Indonesia is expected to maintain a high growth rate. Indonesia was blessed with abundant deposits of fossil energy resources of oil, gas and coal; but oil and gas resources and production amounts have been reaching their limits. Accordingly, the Indonesian government has designated coal as the nation's future primary source of energy in its energy policy. As shown in Figure5.3-6, while Indonesia's domestic coal demand is expected to increase, most of the increase in demand will be for low-ranked lignite coal (36%) rather than for high-coalification coal (1% only). The domestic coal demand is mostly driven by coal-fired power plants, which are required to meet the increasing electricity demand resulting from economic growth.

44.5 40 4048 52

0.5

50

108

136

184

0

20

40

60

80

100

120

140

160

180

200

2006 2010 2015 2020 2025

Domestic Coal Demand (Mil Tons)

+ 36%

+1%

= Bituminous and Sub Bituminous

= Low Ranked Coal (Lignite)

Figure 5.3-6 Estimation of Indonesian domestic coal demand Source: Jefrey Mulyono (Coaltrans Conference, Investing in Coal Upgrading and New Technologies, 2007)

Figure 5.3-7 shows Indonesia's actual and planned coal production volume. Because of its low

ash/sulfur content, Indonesian coal is suited for environmental measures. For this reason, increasing volumes of Indonesian coal are exported to China, India, and other Asian countries. However, although production will rise to meet the increasing domestic demand, the total volume of export will remain almost unchanged, because coal producers are required to prioritize supply to the domestic market under DMO regulations. By 2020–2025, domestic supply is expected to exceed exports.

As a measure to protect environment from the impact of increasing coal production, the government requires coalmine operators to perform production activities in a manner that avoids environmental degradation as much as possible, by, for example, conducting the aforementioned AMDAL-based environmental assessment, as part of the production plan to be filed at the time of commencement of business. Because of the nature of the process and procedures, coal production is


Final Report 5-19

unlikely to affect air, noise quality, or water quality; however, it has a negative impact on the geological formation, soil, and the ecosystems of flora and fauna. Therefore, the Indonesian government intends to conserve biodiversity and ecosystems by, through the enforcement of the New Mining Law and the Forestry Law, prohibiting mining activities in nature and forest reserve areas, as well as opencast mining in designated areas. It is also endeavoring to minimize environmental degradation by making it mandatory to carry out forest restoration and rehabilitation after completion of mining even in the approved mining areas.

0

50

100

150

200

250

300

350

400

450

2006 2007 2008 2009 2010 2015 2020 2025

(millio

n t

on)

Production Export Domestic

Figure 5.3-7 Realization and Estimation of Indonesian coal production, Export and Domestic sales

Source: Directorate General of Mineral and Coal, Ministry of Energy and Mineral Resources

2) Coal Price Outlook Figure 5.3-8 shows the international coal price in 1980s and thereafter. During the period from

1980 through circa 2004, the coal price remained within the range of US$24/t–US$40/t, with only minor fluctuations. After 2004, the coal price was hiked due to a combination of tight demand-supply balance caused by increased demand from China, India, etc. and a decreased supply as a result of constraints of transportation infrastructure in the exporting countries and extreme weather conditions and production disruptions in producer countries. In 2007–2008, affected by the financial crisis, coal price rose sharply to US$200/t and then subsided temporarily. At present, the price is in an increasing trend again.


Final Report 5-20

New Castle FOB

0

50

100

150

200

250

0 60 120 180 240 300 360 4201980 1985 1990 1995 2000 2005 2010

Figure 5.3-8 Change in Coal price index (New Castle FOB）


Until around 2007, there were no international price indices developed for export-grade Indonesian coal. Indonesian exported coal is characterized by relatively low calorific value, except for certain types of bituminous coal; and although exports of sub-bituminous coal with a calorific value of approx. 5,000 kcal/kg have been increasing, they have lower ash/sulfur content compared to coal from Australia or other countries. In 2004, Indonesia became the second largest coal exporter in the world following Australia, and the largest producer of steam coal. However, because the US and Australian coal price indices did not necessarily reflect Indonesian coal prices, and also in order to prevent Indonesian prices from being affected by foreign market prices, the Indonesian Coal Mining Association and others introduced the Indonesian Coal Index (ICI), which exclusively focused on Indonesian coal, and announced three ICIs for coal grades determined by total calorific value (on as received basis), namely: ICI-1 (6,500 kcal/kg), ICI-2 (5,800 kcal/kg), and ICI-3 (5,000 kcal/kg). ICI is reported weekly by PT Coalindo Energy which was established by coal companies, consumer companies, trading houses and others. ICI is set by collecting price information from ten coal companies, ten user companies, trading houses, etc., and after eliminating the top ten percent and bottom ten percent prices, assessments by Argus Media Ltd., a leading energy information provider in the UK are incorporated. ICI is 50% comprised of futures prices and 50% of spot prices. Subsequently, inquiries increased from China and India and trading volume of low-rank coal (5,000 kcal/kg or less) started to grow. Such coal was not actively traded in the market before. In response, ICI-4 (calorific value of 4,200 kcal/kg) was introduced in July 2008 and ICI-5 (calorific value of 3,400 kcal/kg) was introduced in November 20011. So far, ICI-5 is the lowest-rank coal price index.

Domestic coal prices are determined by coal consumer companies and coal producer companies based on long-term contracts or through tender processes. Previously, the country had no unified market price index for domestic-use coal. In view of this, in 2010, the Ministry of Energy and Mineral Resources launched the HBA system as part of its new coal policy, to provide a unified price index for both export and domestic markets. HBA is calculated from four international price indices and therefore can be considered to be linked to the international prices. Currently, HBA has indices for


Final Report 5-21

lower grades of coal than ICI-4 (4,200 kcal/kg), namely the 3,500 kcal/kg and 3,000 kcal/kg grades. Thus, price trends of low-ranked Indonesian coal can be monitored by referring to ICI-4 or low calorific-value grade HBA.

Figure5.3-9 shows the price changes from 2008 of four ICIs and HBA, HBA3500, HBA3000. The four ICIs have different prices depending on their calorific value, but their prices fluctuate in the same pattern. The three HBA prices slightly lag behind the ICI prices, but their fluctuation patterns are the same. (The reasons for the lag of HBA prices are that A) HBA is calculated from ICI data after its public release and B) while ICI and other international price indices are released weekly, HBA is released monthly.) In view of this, a price forecast for low-ranked Indonesian coal has been developed below based on ICI-4. Figure5.3-10 shows the price changes after the price hike in 2008 and the subsequent dip in the coal price. Assuming that this increasing trend continues into the future, this would amount to an annual price increase of approx. 7% which would cause ICI-4, HBA3500, and HBA3000 to double by 2020 from the 2010 level. Given such an increase in the low-rank coal prices, the demand for more efficient CCT technologies for power plants, who are the consumers of low-rank coal, can be expected to grow in the future.

$0

$50

$100

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2008/10/03 2009/08/03 2010/06/03 2011/04/03

ICI-1(6500kcal)

ICI-2

ICI-4(4200kcal)

ICI-3

HBA(3000kcal)

HBA(3500kcal)

HBA

October 2008 Augst 2009 June 2010 April 2011

Figure 5.3-9 Change in ICI and HBA Source: JICA Study Team

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