2006 indonesia energy outlook & statistic

i

INDONESIA

OUTLOOK & STATISTICS 2006

Editorial Team :

Dr. Ir. Widodo Wahyu Purwanto, DEA

Ir. Yulianto Sulistyo Nugroho, M.Sc, Ph.D

Ir. Rinaldy Dalimi, MSc, Ph.D

Dr. A. Harsono Soepardjo, M.Eng

Ir. Abdul Wahid, MT

Ir. Dijan Supramono, M.Sc

Dinna Herminna, ST

Teguh Ahmad Adilina, ST

Editorial Address :

Pengkajian Energi Universitas Indonesia Gedung Engineering Center Lantai 3 Fakultas Teknik Universitas Indonesia

Depok 16424, Indonesia Phone : (62-21) 7866461, 7873117

Facsimile : (62-21) 7873117 http://peui.eng.ui.ac.id

PENGKAJIAN ENERGI UNIVERSITAS INDONESIA

ii

INDONESIA ENERGY OUTLOOK AND STATISTICS 2006 ISBN No. 979-95967-1-8 Book Size : A4 (21 cm x 29.7 cm)

Number of Pages : 276 pages

Type of Paper : Matte Paper 120 gram

Cover Material : Art Carton 260 gram, Full Color

Language : English

Circulation : 500 Books

Editor : Pengkajian Energi Universitas Indonesia

Published by: Pengkajian Energi Universitas Indonesia

Gedung Engineering Center Lantai 3

Fakultas Teknik Universitas Indonesia

Depok

First Printing, December 2006 All rights reserved. This book, or parts thereof, may not be reproduced in any form without prior written permission of the published. This may be cited with reference to the source. Copyright © 2006 by Pengkajian Energi Universitas Indonesia

iii

PREFACE

Realizing the fact that accurate and complete energy data are essential for energy modeling and analysis, Pengkajian Energi Universitas Indonesia (PE UI) published the first edition of Indonesia Energy Outlook and Statistics in 1998. The energy projection included in the book was produced by a dynamic program called Indonesia Energy Outlook System Dynamic (INOSYD) developed by the PE-UI experts. Following the success of the first edition, PE UI published the second edition of the book completed with the multimedia version (CD included) in 2002.

During the period of 2003 to 2006 experts at PE UI have made major improvements in INOSYD model including the Reference Energy system (RES), energy infrastructure and macro economic modules. The progress in the INOSYD model inspires the preparation and publication of the third edition.

The 2006 edition contains latest data of Indonesia economic indicators related to energy use; energy prices in Indonesia; energy statistics data of Indonesia starting from its reserves or potentials, export and import, production and consumption; electric power statistics both of power production and consumption; selected world energy statistics including the prices. This edition adds new data on energy infrastructures such as oil and gas refineries, storage facilities, pipelines, coal harbors, railways and power generations. The energy projections to year 2025 were produced by running the INOSYD model. The analysis of the model would give benefits to central and regional governments, some institutions, industry, and academics involved in energy research and communities concerning energy uses. Besides the projections of some conventional energy economic parameters, the readers will find interesting forecast on primary and final energy supply, demand, and contributions as well as new plant capacity required to meet the forecast and the corresponding investment costs based on capital expenditures. The book also contains analysis of perspective of energy at present and in the future. It provides some laws in energy and policy of national energy and energy conservation. A special chapter is dedicated to review the current state and future direction of energy technologies. The format and lay-out of the tables and graphs are enhanced by colored printing.

Data and projections of energy will be published in 3 formats: 1. Books, 500 copies. 2. CD, 500 copies. 3. Executive summary up loaded in the website of PEUI.

PEUI intent to donate some copies to universities in Indonesia.

The data were contributed by several 20 institutions and individuals involved in energy in Indonesia and abroad. Most of the data referred to documents and publications published by those institutions and some were provided by them. We would like to express our gratitude for their beneficial contributions. The publication of the books is the result of significant efforts by individuals in the Editorial Team. The team is much indebted to editorial assistants for their valuable assistance in preparation of the books. The team also would like to thank to the Directorate for Research and Public Services and Rector of University of Indonesia for their support to the book publications.

Eventually, we are aware that the publication may not be perfect and requires incessant improvements. We are dilated to receive any corrections and constructive suggestions from readers. It is our intentions to maintain the book to be published periodically. We would like to extend our sincere appreciation to all parties, whom we cannot mention one by one, who have contributed for the publication of the third edition of the Indonesia Energy Outlook and Statistics. Pengkajian Energi Universitas Indonesia Chief Editor, Dr. Ir. Widodo Wahyu Purwanto, DEA

v

FOREWORD

I am sincerely delighted to welcome the publication of the 2006 edition of

“Indonesia Energy Outlook and Statistics”. Referring to the title, I presume that the book signifies two parts of the information, i.e. on the statistical data of energy sectors in Indonesia and the forecast of energy sector in the future. The success of national development program aiming to improve people’s quality of life and welfare inevitably relies on the development of energy sectors. In fact, almost all aspects of human life such as residential, commercial, transportation and industrial can not be separated from the need of energy.

Indonesia has abundant primary energy reserves for some types but limited reserves for others. The availability of the current energy data and forecast is important for securing energy supply. The energy outlook and statistics can support the development of new policies intend to maintain the sustainability of energy sector as well as the development of all sectors associated with energy.

I hope this book could be used as a reference for any institution or individual involved in energy research, studies and policy development either in upstream or downstream of energy sectors. The book could also be an important reference for those, who work in both public and private academic institution interested in energy development.

Finally, I would like to extend my sincere appreciation to the Editorial Team for their commitments to continuously improve and publish this important series on regular basis. My appreciation is also extended to other parties for their contributions to the content of the book as well as to several companies for providing financial assistance, through which, without them it would be difficult to publish this book.

University of Indonesia

Rector,

Prof. dr. Usman Chatib Warsa PhD. SpMK

vi

CONTENT

PREFACE .................................................................................................................iii

FOREWORD ................................................................................................................. v

CONTENT ................................................................................................................ vi

I. ENERGY OUTLOOK AND ANALYSIS OF INDONESIA ............................................1

OVERVIEW OF INOSYD................................................................................................3

(Indonesia Energy Outlook by System Dynamic)............................................................3

ENERGY PROJECTION OF INDONESIA BY INOSYD.................................................6

Figure 1.2 Population...............................................................................................6

Figure 1.3 Gross Domestic Product.........................................................................7

Figure 1.4 Petroleum Fuels Consumption by Sector ...............................................8

Figure 1.5 Natural Gas Consumption by Sector ......................................................9

Figure 1.6 Coal Consumption by Sector................................................................10

Figure 1.7 Electricity Consumption by Sector........................................................11

Figure 1.8a Total Energy Consumption by Sector (including Biomass) .................12

Figure 1.8b Total Energy Consumption by Sector (excluding Biomass) .................13

Figure 1.9 Industrial Energy Consumption by Type...............................................14

Figure 1.10 Commercial Energy Consumption by Type .........................................15

Figure 1.11 Residential Energy Consumption by Type (include Biomass) ..............16

Figure 1.12 Transportation Energy Consumption by Type ......................................17

Figure 1.13 Electricity Energy Consumption by Type..............................................18

Figure 1.14a Total Energy Consumption by Type (including Biomass).....................19

Figure 1.14b Total Energy Consumption by Type (excluding Biomass)....................20

Figure 1.15 Total Energy Consumption by GDP Scenario ......................................21

Figure 1.16 Crude Oil Balance ................................................................................22

Figure 1.17 Natural Gas Balance ............................................................................23

Figure 1.18 Coal Balance ........................................................................................24

Figure 1.19 Energy Production by Type ..................................................................25

Figure 1.20 Total Energy Balance ...........................................................................26

Figure 1.21 Reserves-Production Ratio of Crude Oil ..............................................27

vii

Figure 1.22 Reserves-Production Ratio of Natural Gas ..........................................27

Figure 1.23 Reserves-Production Ratio of Coal ......................................................28

Table 1.1 R/P Ratio of Crude Oil, Gas, Coal ........................................................28

Figure 1.24 CO2 Emission per Sector .....................................................................29

Figure 1.25 NOx Emission per Sector .....................................................................30

Figure 1.26 SOx Emissions per Sector....................................................................31

Figure 1.27 Total Capacity of Oil Refinery...............................................................32

Figure 1.28 Total Capacity of Gas Refinery.............................................................32

Figure 1.29 Total Capacity of Power Generator ......................................................33

Figure 1.30 Investment Cost of Oil ..........................................................................33

Figure 1.31 Investment Cost of Gas ........................................................................34

Figure 1.32 Investment Cost of Coal .......................................................................34

Figure 1.33 Investment Cost of Electricity ...............................................................34

Table 1.2 Intensity of Total Energy Consumption.................................................35

Table 1.3 GDP Elasticity of Energy Consumption ................................................36

Table 1.4 Emissions per GDP ..............................................................................37

Table 1.5 Emissions per Capita............................................................................38

Figure 1.34 Contribution of Primary Energy Supply ................................................39

Figure 1.35 Contribution of Final Energy Consumption...........................................40

ENERGY ANALYSIS, PERSPECTIVE, and POLICY..................................................41

1.1 Oil and Gas .....................................................................................................41

1.2 Coal.................................................................................................................46

1.3 Renewable Energy..........................................................................................48

1.4 Electricity.........................................................................................................51

II. SELECTED ECONOMIC INDICATORS OF INDONESIA........................................55

Table 2.1 Population, GDP, Energy Consumption, Energy Intensity, and Energy

Consumption per Capita, 1990 – 2005.................................................57

Table 2.2 Average Rates of Foreign Currencies and Gold in Market, 1997-2005

..............................................................................................................57

Table 2.3 Description of Indonesia Macroeconomics, 1997 – 2005.....................58

viii

Table 2.4 Gross Domestic Product based on Current Market Prices by Industry

Origin, 1999-2005.................................................................................59

Table 2.5 Gross Domestic Product based on Constant 2000 Market Prices by

Industry Origin, 2002-2005 ...................................................................60

Table 2.6 Figures of Indonesian Oil & Gas Export and Import, 1990-2005..........61

Table 2.7 Investment in Oil and Gas, 1997-2004 .................................................61

Table 2.8a Ratio of Electrification and Electricity Consumption per Capita, 2003..62

Table 2.8b Ratio of Electrification and Electricity Consumption per Capita, 2004..63

Table 2.8c Ratio of Electrification and Electricity Consumption per Capita, 2005..64

III. ENERGY PRICES IN INDONESIA ..........................................................................65

Table 3.1 Average of Indonesian Crude Oil Prices, 1998-2005 ...........................67

Table 3.2 Average of Selected Crude Oil Prices, 1999-2005...............................67

Table 3.3a Indonesian Crude Oil Prices by Type, 2003 .........................................68

Table 3.3b Indonesian Crude Oil Prices by Type, 2004 .........................................69

Table 3.3c Indonesian Crude Oil Prices by Type, 2005 .........................................70

Table 3.4 Domestic Fuel Prices, 2003-April 2006 ................................................71

Table 3.5a Domestic Avgas Selling Prices, 2005...................................................73

Table 3.5b International Avgas Selling Prices, 2005 ..............................................74

Table 3.6a Pertamina Domestic Avtur Selling Prices, 2005 ...................................75

Table 3.6b International Avtur Selling Prices, 2005................................................76

Table 3.7 Fuel Oil Subsidy, 1995-2005 ................................................................77

Table 3.8 Gas Domestic Prices, Jan 2006 .........................................................77

Table 3.9a International Coal Price Trend..............................................................78

Table 3.9b Indonesian Coal Export Price Trend....................................................78

Table 3.10 Averaged Generation Cost of PLN Power Plants, 1993-2005..............79

Table 3.11 Averaged Selling Price of Electricity by Type of Customer, 1992-2005

..............................................................................................................79

Table 3.12 Price of Fuels for Electricity, 1992-2005...............................................80

ix

IV. ENERGY RESERVES AND POTENTIALS OF INDONESIA .................................81

Table 4.1 Oil and Gas Reserves, 1995-2005 .......................................................83

Table 4.2 Coal Reserves by Province, 2005 ........................................................84

Table 4.3 Potential and Installed Capacities of Geothermal Energy in Sumatra,

December 2004 ....................................................................................87

Table 4.4 Potential and Installed Capacity of Geothermal Energy in Java,

December 2004 ....................................................................................89

Table 4.5 Potential and Installed Capacity of Geothermal Energy in East Region

of Indonesia, December 2004 .............................................................91

Table 4.6 Potential of Microhydro Energy > 20 kVA (15 kW) (measured by PLN)93

Table 4.7 Potential of Microhydro Energy > 20 kVA (15 kW) (measured by non

PLN) in Sumatera and Java ................................................................94


PLN) in Kalimantan and Sulawesi ........................................................95


PLN) in East Region of Indonesia ........................................................96

Table 4.10 Potential of Solar Energy......................................................................97

Table 4.11 Potential of Wind Energy in West Region of Indonesia measured by

BMG) ....................................................................................................98

Table 4.12 Potential of Wind Energy in East Region of Indonesia (measured by

BMG) ....................................................................................................99

Table 4.13 Potential of Biomass Energy ..............................................................100

Table 4.14 Potential of Biogas Energy .................................................................101

Table 4.15 Potential of Peat Energy.....................................................................102

V. ENERGY PRODUCTION AND CONSUMPTION IN INDONESIA .........................103

Table 5.1 Production of Energy, 1997-2005.......................................................105

Table 5.2 Energy Supply by Type of Primary Energy, 1990-2004 .....................106

Table 5.3 Energy Consumption by Type of Final Energy, 1990 – 2004 .............107

Table 5.4 Final Energy Consumption by Sector, 1990 – 2004 ...........................108

Table 5.5 Petroleum Fuel Consumption by Sector, 1990 – 2004.......................109

Table 5.6 Gas Consumption by Sector, 1990 – 2004.........................................110

Table 5.7 Coal Consumption by Sector, 1990-2004...........................................111

x

Table 5.8a Petroleum Fuel Sales in Residential Sector, 2000-2005 ....................112

Table 5.8b Petroleum Fuel Sales in Transportation Sector, 2000-2005...............112

Table 5.8c Petroleum Fuel Sales in Industry Sector, 2000-2005 .........................113

Table 5.8d Petroleum Fuel Sales in Electricity Sector, 2000-2005 ......................113

Table 5.9a Petroleum Fuel Sales per Region, 2003.............................................114

Table 5.9b Petroleum Fuel Sales per Region, 2004.............................................115

Table 5.9c Petroleum Fuel Sales per Region, 2005.............................................116

Table 5.10 Crude Oil Production by Production Schemes, 1995 – 2005 .............117

Table 5.11 Condensate Production by Production Scheme, 1995 – 2005...........118

Table 5.12 Production of Naphtha and LSWR by Refinery, 1996 – 2005 ............119

Table 5.13a Production of various Fuels by Refinery, 2003...................................120

Table 5.13b Production of various Fuels by Refinery, 2004...................................121

Table 5.13c Production of various Fuels by Refinery, 2005...................................122

Table 5.14a Production of Oil and Gas by Refinery, 2003 .....................................123

Table 5.14b Production of Oil and Gas by Refinery, 2004 .....................................124

Table 5.14c Production of Oil and Gas by Refinery, 2005 .....................................125

Table 5.15 Natural Gas Production by Production Scheme, 1995 – 2005 ...........126

Table 5.16 Production and Utilization of Natural Gas, 1999-2005 .......................127

Table 5.17 Production of LNG, 1999 – 2005 ........................................................128

Table 5.18 Production of LPG, 2001 – 2005 ........................................................129

Table 5.19 Gas Sales of PT. PGN (Persero) by Sector, 1995 – 2005 .................130

Table 5.20 Coal Production by Company, 1999-June 2006.................................131

Table 5.21 Domestic Coal Sales by Company , 1998 -2004................................133

Table 5.22 Domestic Coal Sales by Industry, 1998-2004 ....................................135

Table 5.23 Coal Quality by Company...................................................................136

Table 5.24 Electricity Production by Type of Power Plant of PLN, 1992 – 2005.137

Table 5.25 Fuel Consumption for PLN Power Plant, 1989-2005..........................138

Table 5.26 Own-Uses, Losses, and Factors in PLN Electricity, 1993-2005 .........138

Table 5.27 Electricity Sold by PLN by Sector, 1996-2005....................................139

Tabel 5.28a Load Balance of PLN Electricity, 2003 ...............................................140

Tabel 5.28b Load Balance of PLN Electricity, 2004 ...............................................141

Table 5.28c Load Balance of PLN Electricity, 2005 ...............................................142

xi

VI. EXPORTS AND IMPORTS OF ENERGY IN INDONESIA....................................143

Table 6.1 Export of Energy, 1997 – 2005...........................................................145

Table 6.2 Import of Energy, 1995 – 2005 ...........................................................146

Table 6.3 Import of Crude Oil by Type, 2000 – 2005 .........................................147

Table 6.3 Import of Crude Oil by Type, 2000 – 2005 (Continued)......................148

Table 6.4 Import of Refinery Products, 2000 – 2005..........................................149

Table 6.5 Export of Crude Oil by Destination Country, 1997 – 2005..................150

Table 6.6 Export of Condensate by Destination Country, 1997 – 2005 .............151

Table 6.7 Export of Refinery Product, 1999– 2005 ...........................................152

Table 6.8 Export of Refinery Product by Destination Country, 1999 –2005 .......153

Table 6.9 Export of LNG by Destination Country, 1995 –2005 ..........................154

Table 6.10 Export of LPG by Destination Country, 2000 – 2005..........................155

Table 6.11 Coal Export by Company, 1999 – 2005..............................................156

Table 6.12 Coal Export by Destination Country, 1999 – 2005 .............................157

VII. INFRASTRUCTURE OF ENERGY IN INDONESIA.............................................159

Table 7.1 Installed Capacities of Oil Refinery Plants, 1999 – 2005....................161

Table 7.2a Fuel Oil Sales & Distribution Channels of Pertamina and Partner .....161

Table 7.2b Non-Fuel Oil Sales & Distribution Channels of Pertamina and

Partners ..............................................................................................162

Table 7.3 Oil Fuel Pipeline .................................................................................162

Table 7.4 Number of Oil Fuels Public Station and Kerosene Agents .................163

Table 7.5 Oil Fuel Storage Tanks of PT PERTAMINA (Persero) in Sumatera and

Java ....................................................................................................164

Table 7.6 Oil Fuel Storage Tanks of PT PERTAMINA (Persero) in Kalimantan,

Sulawesi, and Papua..........................................................................165

Table 7.7 Distribution Gas Pipeline of PT PGN (Persero) ..................................165

Table 7.8 Gas Pipeline .......................................................................................166

Table 7.9 Transacted Gas Pipeline Project in 2005 & 2006...............................166

Table 7.10 Design and Production Capacities of LNG Plant...............................167

Table 7.11 Main Coal Harbor ...............................................................................167

Table 7.12 Number of PLN Power Plants, 1992 – 2005.......................................168

xii

Table 7.13 Installed and Rated Capacities of PLN Power Plants, 1992 – 2005...169

Tabel 7.14a Captive Power Plants, 2003 ...............................................................170

Tabel 7.14b Captive Power Plants, 2004 ...............................................................171

Table 7.14c Captive Power Plants, 2005 ...............................................................172

VIII. SELECTED WORLD ENERGY STATISTICS.....................................................173

Table 8.1 World Oil Proven Reserves; 1985, 1995, 2004, 2005 ........................175

Table 8.2 World Oil Production, 2000 – 2005.....................................................176

Table 8.3 World Oil Consumption, 2000 – 2005.................................................177

Table 8.4 World Oil Refinery Capacities, 2000 – 2005.......................................179

Table 8.5 World Natural Gas Proven Reserves; 1985, 1995, 2004, 2005 .........180

Table 8.6 World Natural Gas Production, 1997 – 2005......................................181

Table 8.7 World Natural Gas Consumption, 1997 – 2005..................................182

Table 8.8 World Coal Proven Reserves by Type, 2005 .....................................184

Table 8.9 World Coal Production, 1995-2005 ....................................................185

Table 8.10 World Coal Consumption, 1997-2005 ................................................186

Table 8.11 World Primary Energy Production by Source, 1980-2004..................188

Table 8.12 World Primary Energy Consumption, 1997-2005 ...............................189

Table 8.13 World Primary Energy Consumption by Fuel, 2004-2005 ..................191

Table 8.14 World Hydroelectricity Consumption, 2000-2005 ...............................193

Table 8.15 World Spot Crude Oil Prices, 1980 – 2005.........................................195

Table 8.16 World Average Gas Prices, 1984 – 2005 ...........................................196

Table 8.17 World Average Coal Prices, 1987 – 2005 ..........................................197

IX. CURRENT AND FUTURE ENERGY TECHNOLOGY ..........................................199

9.1 Petroleum Technology........................................................................201

9.2 Natural Gas Technology.....................................................................206

9.3 Coal Technology.................................................................................210

9.4 Renewable Energy Technology..........................................................215

9.5 Electricity Technology.........................................................................226

xiii

X. ECONOMICS OF ALTERNATIVE FUELS AND ELECTRICITY GENERATION ..229

XI. ENERGY REGULATIONS ....................................................................................237

XII. ENERGY CONSERVATION ................................................................................243

APPENDICES .............................................................................................................253

A1. Gross Energy Content ..........................................................................................253

A.2 Conversion Factor ................................................................................................255

A3. Glossary ............................................................................................................257

REFERENCES ...........................................................................................................269

PROFILE OF EDITORS .............................................................................................273

SPONSORS .............................................................................................................275

I. ENERGY OUTLOOK AND ANALYSIS OF INDONESIA

PENGKAJIAN ENERGI UNIVERSITAS INDONESI

ENERGY OUTLOOK & ANALYSIS

3

OVERVIEW OF INOSYD (Indonesia Energy Outlook by System Dynamic)

Indonesia Energy Outlook by System Dynamic (INOSYD) has been developed by

Pengkajian Energi Universitas Indonesia (PEUI) since 1997. The INOSYD model is written in

dynamic simulation software called POWERSIM. Modeling framework of INOSYD illustrated in

Figure I consists of three basic sub-models: (1) Energy system sub-model, (2) Macro-economic

sub-model, and (3) Environmental sub-model.

Figure 1.1 INOSYD model framework

The energy system sub-model consists of supply and demand of energy services including

infrastructures. The supply side of primary energy production such as oil, natural gas and coal

are modeled dynamically, except for the renewable. The demand side of the energy services is

divided into several sectors including industry, commercial, domestic and transportation, as well

as electricity sector and modeled using econometric approach. The supply and demand sides

are linked using a Reference Energy System (RES) module. The conversion, transportation and

end-use technology aspects, the cost and performance characteristics of these technologies

that are potentially available for use in the energy system are considered in the RES. The

macro-economic sub-model is developed based on Indonesia’s Social Accounting Matrix

(SAM), and completed with the population growth, GDP and energy prices which are considered

as exogenous variables. The environmental sub-model considers the interaction between

energy system and the emission from the activities for energy conversion, production and use.

Energy Resources

Primary Energy

Energy conversion

Power generation,refineries

Transmission and

DistributionPiping, cable, tankers,

Ports, and storage

Final energy

Energy infrastructure

Energy demand

Sectors and types

Social accounting

matrix (SAM)GDP

-

Technology, Emission coefficient

ENVIRONMENT SUB MODEL-

Energy Resources

Primary Energy

Energy conversion

Power generation,refineries

Transmission and

DistributionPiping, cable, tankers,

Ports, and storage

Final energy

Energy infrastructure

Energy demand

Sectors and types

ENERGY SUB MODEL

Socialaccounting

matrix (SAM)GDP

MACROECONOMIC SUB MODEL

Technology, Emission coefficient

4

Supply of energy module comprises national energy balance as network of energy flows

(RES) starting from supply of different forms of primary energy such as crude oil, gas, coal and

renewable resources i.e. biomass, geothermal, and hydro etc., primary energy conversion into

final energies via power generations and refineries, transmission and distribution as well as

storage to end-user devices for each demand sector. Each link of the network represents some

activities relating to an energy efficiency coefficient and losses.

Mathematically, RES is divided in sequential vectors representing stages of energy

transformation. We start from right to left or from total demand by sector to supply of primary

energy. Vn is calculated from its predecessor, Vn-1, by the following form:

Vn = T x V n-1 (1)

where T is a transformation matrix of RES with the coefficient of efficiency and losses

as elements of matrix.

For the supply of primary energy especially fossil fuels, the INOSYD model allows the

calculation of remaining reserves and reserve to production ratio of each fossil fuel. In addition,

reserve to production ratio can be set at a constant value for the policy proposes, and then the

demand will be fulfilled by imports.

Energy infrastructure module consists of existing energy infrastructure, capital

expenditures and O&M cost of energy conversion technologies (power generation, refineries)

and transmission and distribution systems for oil, gas, coal and electricity, associated with

learning curve of capital expenditure of emerging energy technologies. Infrastructures in this

sub module are oil and gas refinery, depot, gas pipeline, coal railroad, coal harbor and power

generator. This sub model can estimate the investment of energy infrastructures and the costs

of energy supply or production of final energy such as electricity and petroleum products, and

LNG.

Development of energy demand module is critical element at both the aggregate

sectors at national level such as industrial, transportation, commercial, residential both

electricity and fuels and aggregate fuel types. In the earlier approach, demand model is

developed by dynamic approach, but the results were not satisfied due to insufficient data for

energy demand sectors. Thus, currently we use an econometric approach resulting in more

simplified model. Typically equation is written as follows:

Dn = f (GDP, population, price, intensity or elasticity) (2)

It should be noted that to simulate the price impacts, demand model must include

energy price in the equation above. However, in the most cases it is difficult to estimate

demands due to the fact that relationship between demand and price is inconsistent. In addition,

we should consider that the energy demand is also affected by the limitation of energy

5

infrastructures. Hence, the potential demand can be greater than the current demand and the

shape of energy market is still developing.

Concerning environment sub-model, it is constructed based only on emission

coefficients taken from Intergovernmental Panel on Climate Change (IPCC) guidelines 1996 for

different types of energy technologies for energy conversion units and end-user devices.

Emission consists of CO2, SOx and NOx.

Macroeconomic sub-model is developed based on Indonesia’s Social Accounting Matrix

(SAM) in 1999 with dimension of 109 x 109 sectors and reduced to 58 x 58 sectors. By using

SAM, the impact energy policy i.e. energy price shock and change of share of energy supply on

GDP can be simulated.

Having specified assumed levels of energy demands, INOSYD can be used as

optimization tool using POWERSIM Solver to determine the combination of technologies which

meet those needs at overall least cost of energy supply with some constraints added.

In the simulation context, INOSYD can be operated in top-down approach and bottom-

up approach models. Typical top-down approaches are impact of GDP growth rate on supply

and demand of energy and environment, and impact of energy price shock on energy system

and environments. On the other hands, a bottom-up approach may describe impacts of energy

technology on macroeconomic and environment.

The GDP projection uses the assumption of 6% growth per year for the base case;

while the population projection uses an assumption of 1.20% growth. For making a projection

until 2025, INOSYD uses data mostly from years 1990 through 2005.

6

ENERGY PROJECTION OF INDONESIA BY INOSYD

Figure 1.2 Population

175

200

225

250

275

300

1990 1995 2000 2005 2010 2015 2020 2025

(Million Persons)

Data Projection

(Million)

Year Population 1990 179.248 1991 181.763 1992 184.278 1993 186.794 1994 189.309 1995 191.825 1996 194.340 1997 199.837 1998 202.873 1999 203.047 2000 205.843 2001 208.647 2002 212.003 2003 215.276 2004 217.854 2005 220.923 2006 223.574 2007 226.257 2008 228.972 2009 231.720 2010 234.501 2011 237.315 2012 240.162 2013 243.044 2014 245.961 2015 248.912 2016 251.899 2017 254.922 2018 257.981 2019 261.077 2020 264.210 2021 267.380 2022 270.589 2023 273.836 2024 277.122 2025 280.447

7

Figure 1.3 Gross Domestic Product

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

1990 1995 2000 2005 2010 2015 2020 2025

(Billion Rupiah) at constant price 2000

Data Base Case

(Billion Rupiah at constant price of year2000) Gross Domestic Product Year Base Case

1990 875,025 1991 936,400 1992 999,721 1993 1,151,729 1994 1,238,570 1995 1,340,380 1996 1,445,173 1997 1,513,095 1998 1,314,475 1999 1,324,874 2000 1,389,770 2001 1,442,985 2002 1,506,124 2003 1,579,559 2004 1,660,579 2005 1,753,571 2006 1,851,771 2007 1,953,618 2008 2,061,067 2009 2,184,731 2010 2,315,815 2011 2,454,764 2012 2,602,050 2013 2,758,173 2014 2,923,663 2015 3,099,083 2016 3,285,028 2017 3,482,130 2018 3,691,058 2019 3,912,521 2020 4,147,273 2021 4,396,109 2022 4,659,875 2023 4,939,468 2024 5,235,836 2025 5,549,986

8

Figure 1.4 Petroleum Fuels Consumption by Sector

0

100

200

300

400

500

600

700

800

900

1,000

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)

Industry Commercial Residential Transportation Electricity

(Million BOE)

Year Industry Commercial Residential Transportation Electricity 1990 39.33 2.34 39.45 93.42 35.79 1991 40.39 3.03 40.00 101.46 40.50 1992 46.49 3.88 40.50 110.87 43.95 1993 52.55 4.97 41.10 120.28 47.91 1994 56.10 5.49 41.86 124.11 28.61 1995 61.53 5.96 42.65 135.10 22.48 1996 62.35 6.50 43.49 149.10 25.10 1997 64.84 6.85 46.47 157.12 34.63 1998 68.31 5.75 48.98 148.89 31.17 1999 79.72 5.83 50.85 154.02 35.41 2000 85.24 6.13 52.79 163.41 37.57 2001 87.51 6.22 55.09 170.35 39.22 2002 87.36 6.32 57.91 176.50 50.33 2003 79.44 6.41 60.14 184.64 54.70 2004 88.65 6.51 60.86 198.25 60.78 2005 92.11 6.92 63.07 208.26 70.45 2006 95.43 7.24 65.38 216.57 61.39 2007 98.93 7.59 67.80 225.40 51.08 2008 104.13 8.11 70.99 238.63 40.18 2009 108.36 8.54 73.78 249.38 26.64 2010 112.75 8.99 76.68 260.60 11.11 2011 117.31 9.46 79.68 272.30 11.54 2012 122.05 9.96 82.80 284.50 12.03 2013 126.98 10.48 86.03 297.23 12.53 2014 132.09 11.02 89.39 310.50 13.04 2015 137.41 11.59 92.86 324.33 13.57 2016 142.93 12.19 96.46 338.75 14.10 2017 148.66 12.81 100.20 353.79 14.63 2018 154.62 13.47 104.07 369.45 15.17 2019 160.81 14.16 108.09 385.78 15.71 2020 167.23 14.87 112.25 402.79 16.25 2021 173.90 15.63 116.57 420.51 16.79 2022 180.82 16.41 121.04 438.96 17.32 2023 188.01 17.23 125.68 458.18 17.84 2024 195.47 18.09 130.48 478.20 18.34 2025 203.21 18.99 135.46 499.04 18.82

9

Figure 1.5 Natural Gas Consumption by Sector

0

50

100

150

200

250

300

350

400

450

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)


(Million BOE)


10

Figure 1.6 Coal Consumption by Sector

0

100

200

300

400

500

600

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)


(Million BOE)


11

Figure 1.7 Electricity Consumption by Sector

0

50

100

150

200

250

300

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)

Industry Commercial Residential Transportation

(Million BOE)

Year Industry Commercial Residential Transportation 1990 10.48 2.78 5.52 0.01 1991 11.69 3.14 6.33 0.01 1992 13.73 3.37 7.15 0.01 1993 14.22 3.82 8.08 0.01 1994 13.90 4.17 8.97 0.01 1995 15.01 4.89 10.46 0.01 1996 17.04 5.78 11.99 0.02 1997 18.44 6.65 13.91 0.02 1998 17.67 7.61 15.24 0.02 1999 19.22 8.04 16.47 0.02 2000 21.86 8.94 18.73 0.03 2001 21.82 9.55 20.44 0.03 2002 22.58 9.97 20.84 0.03 2003 22.37 11.15 21.92 0.03 2004 24.72 12.99 23.61 0.03 2005 26.77 14.15 24.51 0.04 2006 28.90 15.37 25.40 0.04 2007 31.30 16.76 26.21 0.04 2008 34.66 18.67 27.63 0.05 2009 37.73 20.45 28.62 0.05 2010 41.07 22.39 29.58 0.06 2011 44.70 24.50 30.55 0.07 2012 48.63 26.78 31.51 0.07 2013 52.89 29.26 32.47 0.08 2014 57.53 31.93 33.42 0.09 2015 62.55 34.81 34.35 0.10 2016 68.02 37.92 35.25 0.11 2017 73.97 41.26 36.13 0.12 2018 80.44 44.85 36.96 0.13 2019 87.51 48.69 37.73 0.14 2020 95.23 52.79 38.43 0.16 2021 103.67 57.16 39.04 0.17 2022 112.95 61.78 39.53 0.19 2023 123.16 66.66 39.86 0.21 2024 134.43 71.78 40.00 0.23 2025 146.68 77.12 40.13 0.26

12

Figure 1.8a Total Energy Consumption by Sector (including Biomass)

0

500

1,000

1,500

2,000

2,500

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)


( Million BOE)


13

Figure 1.8b Total Energy Consumption by Sector (excluding Biomass)

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)


( Million BOE)


14

Figure 1.9 Industrial Energy Consumption by Type

0

100

200

300

400

500

600

700

800

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)

Petroleum Fuels Natural Gas Coal Renewable Electricity

( Million BOE)

Year Petroleum Fuels Natural Gas Coal Renewable Electricity 1990 39.33 11.11 10.58 11.35 10.48 1991 40.39 11.41 10.86 11.66 11.69 1992 46.49 12.29 12.05 11.97 13.73 1993 52.55 11.98 13.69 12.26 14.22 1994 56.10 18.67 14.15 12.56 13.90 1995 61.53 19.64 16.60 12.72 15.01 1996 62.35 18.31 15.47 12.88 17.04 1997 64.84 23.46 16.06 13.02 18.44 1998 68.31 17.94 17.83 13.17 17.67 1999 79.72 32.12 26.86 13.30 19.22 2000 85.24 37.75 36.22 13.43 21.86 2001 87.51 47.89 37.51 12.94 21.82 2002 87.36 45.86 38.80 12.59 22.58 2003 79.44 44.21 40.14 12.45 22.37 2004 88.65 68.66 55.34 12.04 24.72 2005 92.11 72.20 58.27 12.17 26.77 2006 95.43 75.83 61.29 12.36 28.90 2007 98.93 79.69 64.51 12.55 31.30 2008 104.13 85.04 68.94 12.92 34.66 2009 108.36 89.71 72.83 13.15 37.73 2010 112.75 94.63 76.94 13.37 41.07 2011 117.31 99.81 81.27 13.58 44.70 2012 122.05 105.28 85.84 13.77 48.63 2013 126.98 111.04 90.67 13.96 52.89 2014 132.09 117.11 95.75 14.13 57.53 2015 137.41 123.50 101.12 14.29 62.55 2016 142.93 130.25 106.78 14.42 68.02 2017 148.66 137.35 112.76 14.54 73.97 2018 154.62 144.84 119.06 14.64 80.44 2019 160.81 152.73 125.70 14.71 87.51 2020 167.23 161.04 132.71 14.76 95.23 2021 173.90 169.80 140.11 14.77 103.67 2022 180.82 179.02 147.90 14.75 112.95 2023 188.01 188.75 156.12 14.70 123.16 2024 195.47 198.99 164.79 14.61 134.43 2025 203.21 209.78 173.94 14.48 146.68

15

Figure 1.10 Commercial Energy Consumption by Type

0

20

40

60

80

100

120

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)


( Million BOE)


16

Figure 1.11 Residential Energy Consumption by Type (include Biomass)

0

100

200

300

400

500

600

700

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)


( Million BOE)


17

Figure 1.12 Transportation Energy Consumption by Type

0

100

200

300

400

500

600

700

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)


( Million BOE)


18

Figure 1.13 Electricity Energy Consumption by Type

0

100

200

300

400

500

600

700

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)

Petroleum Fuels Natural Gas Coal Renewable

( Million BOE)

Year Petroleum Fuels Natural Gas Coal Renewable 1990 35.79 2.84 16.67 2.69 1991 40.50 2.73 18.72 2.95 1992 43.95 2.62 17.99 3.69 1993 47.91 11.96 16.59 3.20 1994 28.61 32.94 19.34 3.36 1995 22.48 45.07 19.55 3.88 1996 25.10 59.97 27.71 4.10 1997 34.63 46.65 34.74 3.35 1998 31.17 45.49 37.18 4.95 1999 35.41 48.41 39.86 4.92 2000 37.57 46.51 45.56 12.08 2001 39.22 43.91 47.26 13.15 2002 50.33 37.88 47.09 11.68 2003 54.70 35.99 50.85 11.13 2004 60.78 34.27 51.09 14.29 2005 70.45 25.65 55.71 15.16 2006 61.39 28.53 65.91 14.68 2007 51.08 31.71 77.20 17.76 2008 40.18 35.95 91.65 21.63 2009 26.64 40.02 106.19 25.59 2010 11.11 44.46 122.26 30.03 2011 11.54 47.10 131.49 31.87 2012 12.03 50.15 142.14 34.01 2013 12.53 53.40 153.65 36.28 2014 13.04 56.85 166.07 38.71 2015 13.57 60.53 179.49 41.29 2016 14.10 64.44 193.98 44.05 2017 14.63 68.60 209.63 46.99 2018 15.17 73.02 226.52 50.12 2019 15.71 77.73 244.76 53.46 2020 16.25 82.73 264.45 57.01 2021 16.79 88.06 285.71 60.80 2022 17.32 93.72 308.66 64.85 2023 17.84 99.74 333.43 69.15 2024 18.34 106.14 360.17 73.74 2025 18.82 112.94 389.03 78.62

19

Figure 1.14a Total Energy Consumption by Type (including Biomass)

0

500

1,000

1,500

2,000

2,500

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)


(Million BOE)


20

Figure 1.14b Total Energy Consumption by Type (excluding Biomass)

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)


(Million BOE)


21

Figure 1.15 Total Energy Consumption by GDP Scenario

0

500

1,000

1,500

2,000

2,500

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)

Data Base Case

(Million BOE) Year Total Energy Consumption 1990 409 1991 425 1992 450 1993 474 1994 493 1995 520 1996 540 1997 568 1998 566 1999 613 2000 655 2001 684 2002 697 2003 705 2004 777 2005 810 2006 843 2007 878 2008 928 2009 970 2010 1,015 2011 1,062 2012 1,111 2013 1,162 2014 1,217 2015 1,273 2016 1,333 2017 1,396 2018 1,462 2019 1,531 2020 1,604 2021 1,680 2022 1,761 2023 1,845 2024 1,934 2025 2,028

22

Figure 1.16 Crude Oil Balance

0

100

200

300

400

500

600

700

800

900

1,000

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)

Production Domestic Consumption Export Import

(Million BOE) Year Production Domestic Consumption Export Import 1990 534 223 330 58 1991 581 240 330 44 1992 551 262 293 49 1993 558 278 283 56 1994 588 269 324 62 1995 586 280 302 69 1996 583 298 284 72 1997 577 324 289 63 1998 569 319 280 72 1999 546 342 285 102 2000 517 355 224 80 2001 489 369 240 120 2002 457 389 217 137 2003 419 386 189 150 2004 401 420 179 192 2005 336 434 160 220 2006 339 453 152 236 2007 335 461 145 243 2008 328 476 138 264 2009 324 486 132 273 2010 322 495 126 280 2011 321 516 120 304 2012 321 538 114 328 2013 322 561 109 353 2014 322 585 104 380 2015 323 611 99 408 2016 325 637 94 437 2017 328 664 90 466 2018 331 692 86 497 2019 335 721 82 528 2020 340 752 78 560 2021 346 784 74 594 2022 352 816 71 628 2023 359 851 68 664 2024 366 886 64 701 2025 374 923 61 739

23

Figure 1.17 Natural Gas Balance

0

200

400

600

800

1,000

1,200

1,400

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)


(Million BOE) Year Production Domestic Consumption Export Import 1990 508 33 230 0 1991 443 34 230 0 1992 464 36 241 0 1993 478 41 246 0 1994 528 75 268 0 1995 539 90 253 0 1996 586 94 269 0 1997 569 100 267 0 1998 535 86 264 0 1999 551 125 285 0 2000 521 137 263 0 2001 504 166 235 0 2002 546 157 255 0 2003 567 153 293 0 2004 544 208 284 0 2005 544 221 266 0 2006 519 235 302 0 2007 534 251 303 0 2008 555 272 305 0 2009 586 291 318 0 2010 557 311 270 0 2011 590 333 284 0 2012 637 356 310 0 2013 686 381 335 0 2014 736 407 361 0 2015 764 435 363 0 2016 794 465 366 0 2017 826 497 368 0 2018 859 531 371 0 2019 896 567 374 0 2020 934 606 377 0 2021 975 646 380 0 2022 1,018 690 384 0 2023 1,065 736 388 0 2024 1,114 785 392 0 2025 1,166 838 396 0

24

Figure 1.18 Coal Balance

0

200

400

600

800

1,000

1,200

1,400

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)


(Million BOE)

Year Production Domestic Consumption Export Import 1990 47 29 18 0 1991 60 31 28 0 1992 102 33 70 0 1993 109 31 78 0 1994 136 34 102 0 1995 172 38 134 0 1996 198 42 156 0 1997 232 53 178 0 1998 263 59 204 0 1999 308 71 237 0 2000 344 94 250 0 2001 374 95 279 0 2002 413 96 317 0 2003 474 108 366 0 2004 537 136 401 0 2005 602 148 454 0 2006 648 156 492 0 2007 673 172 501 0 2008 704 193 512 0 2009 734 212 522 0 2010 762 230 532 0 2011 788 245 543 0 2012 816 262 554 0 2013 845 280 565 0 2014 876 300 576 0 2015 902 315 588 0 2016 935 336 599 0 2017 970 358 611 0 2018 1,006 382 624 0 2019 1,044 408 636 0 2020 1,084 435 649 0 2021 1,125 464 662 0 2022 1,170 495 675 0 2023 1,216 527 688 0 2024 1,265 562 702 0 2025 1,316 600 716 0

25

Figure 1.19 Energy Production by Type

0

200

400

600

800

1,000

1,200

1,400

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)

Crude oil Natural Gas Coal Renewable

(Million BOE) Year Crude Oil Natural Gas Coal Renewable 1990 534 508 47 196 1991 581 443 60 199 1992 551 464 102 203 1993 558 478 109 206 1994 588 528 136 209 1995 586 539 172 211 1996 583 586 198 213 1997 577 569 232 217 1998 569 535 263 222 1999 546 551 308 224 2000 517 521 344 236 2001 489 504 374 240 2002 457 546 413 242 2003 419 567 474 246 2004 401 544 537 251 2005 336 544 602 258 2006 339 519 648 276 2007 335 534 673 285 2008 328 555 704 298 2009 324 586 734 310 2010 322 557 762 322 2011 321 590 788 331 2012 321 637 816 341 2013 322 686 845 351 2014 322 736 876 362 2015 323 764 902 373 2016 325 794 935 384 2017 328 826 970 396 2018 331 859 1,006 408 2019 335 896 1,044 420 2020 340 934 1,084 433 2021 346 975 1,125 447 2022 352 1,018 1,170 461 2023 359 1,065 1,216 475 2024 366 1,114 1,265 490 2025 374 1,166 1,316 505

26

Figure 1.20 Total Energy Balance

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

1990 1995 2000 2005 2010 2015 2020 2025

(Million BOE)

Energy Production Demand of Energy Export of Energy Import of Energy

(Million BOE) Year Energy Production Demand of Energy Export of Energy Import of Energy 1990 1,285 480 579 58 1991 1,283 503 589 44 1992 1,321 532 603 49 1993 1,351 556 608 56 1994 1,462 586 694 62 1995 1,508 619 688 69 1996 1,580 646 709 72 1997 1,594 693 735 63 1998 1,589 684 748 72 1999 1,629 761 807 102 2000 1,619 818 736 80 2001 1,607 865 754 120 2002 1,659 880 790 137 2003 1,705 889 849 150 2004 1,733 1,011 864 192 2005 1,741 1,055 879 220 2006 1,782 1,116 945 236 2007 1,828 1,163 949 243 2008 1,886 1,232 954 264 2009 1,954 1,290 972 273 2010 1,962 1,346 928 280 2011 2,030 1,413 947 304 2012 2,115 1,485 978 328 2013 2,204 1,561 1,009 353 2014 2,296 1,640 1,041 380 2015 2,362 1,718 1,050 408 2016 2,438 1,806 1,060 437 2017 2,519 1,898 1,070 466 2018 2,604 1,995 1,080 497 2019 2,695 2,097 1,092 528 2020 2,791 2,205 1,104 560 2021 2,893 2,318 1,117 594 2022 3,000 2,438 1,130 628 2023 3,114 2,563 1,144 664 2024 3,234 2,696 1,159 701 2025 3,362 2,836 1,174 739

27

Figure 1.21 Reserves-Production Ratio of Crude Oil

0

2

4

6

8

10

12

14

1990 1995 2000 2005 2010 2015 2020 2025

(Year)

Data

Projection with INOSYD's scenario,where Reserve to Production Ratio of Crude Oil is fixed at 12 years

Projection with INOSYD's scenario, without R/P constraint

Figure 1.22 Reserves-Production Ratio of Natural Gas

0

5

10

15

20

25

30

35

1990 1995 2000 2005 2010 2015 2020 2025

(Year)

Data Projection

28

Figure 1.23 Reserves-Production Ratio of Coal

0

100

200

300

400

500

600

700

800

900

1991 1996 2001 2006 2011 2016 2021

Data Projection

Table 1.1 R/P Ratio of Crude Oil, Gas, Coal (Year)

Crude Oil Crude Oil Natural Gas Coal Year Unfixed Fixed at 12 years Fixed at 15 years Fixed at 35 years 1990 11 11 0 0 1991 10 10 26 837 1992 11 11 25 495 1993 10 10 25 467 1994 9 9 27 378 1995 8 8 24 303 1996 8 8 24 265 1997 8 8 24 228 1998 9 9 26 203 1999 10 10 30 174 2000 10 10 33 156 2001 10 10 33 144 2002 10 10 30 131 2003 11 11 29 114 2004 11 11 32 101 2005 9 12 29 90 2006 9 12 31 84 2007 8 12 31 80 2008 8 12 29 76 2009 7 12 28 73 2010 7 12 29 70 2011 6 12 28 67 2012 6 12 26 65 2013 5 12 24 62 2014 5 12 23 59 2015 4 12 22 57 2016 4 12 21 55 2017 4 12 20 52 2018 3 12 19 50 2019 3 12 18 48 2020 2 12 17 45 2021 2 12 17 43 2022 2 12 16 41 2023 2 12 15 39 2024 1 12 14 36 2025 1 12 13 34

29

Figure 1.24 CO2 Emission per Sector

0

200

400

600

800

1,000

1,200

1,400

1990 1995 2000 2005 2010 2015 2020 2025

(Million Ton)


(Million tons)


30

Figure 1.25 NOx Emission per Sector

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

1990 1995 2000 2005 2010 2015 2020 2025

(Thousand Ton)


(Thousand tons)

Year Industry Commercial Residential Transportation Electricity 1990 83.72 1.73 132.61 402.59 84.78 1991 85.98 2.24 134.44 437.24 95.62 1992 96.46 2.92 136.27 477.79 100.97 1993 106.49 3.78 138.16 518.41 100.49 1994 118.43 4.18 139.92 534.91 98.72 1995 130.32 4.54 141.52 587.80 104.46 1996 128.09 4.96 142.94 648.67 121.60 1997 137.34 5.24 147.37 682.80 146.37 1998 139.20 4.38 150.97 645.17 151.75 1999 183.04 4.45 153.44 663.26 163.07 2000 211.84 4.69 156.92 710.35 177.25 2001 226.67 4.74 160.53 742.61 180.96 2002 226.54 4.81 164.71 768.78 189.32 2003 217.65 4.87 168.40 805.91 201.90 2004 279.67 4.93 170.66 866.99 225.37 2005 292.59 5.23 175.43 908.62 240.12 2006 305.62 5.50 187.83 951.44 256.12 2007 319.47 5.79 192.93 994.38 270.18 2008 339.09 6.22 200.09 1,057.25 291.49 2009 355.81 6.59 206.01 1,109.68 309.53 2010 373.36 6.97 212.11 1,164.68 321.24 2011 391.77 7.37 218.39 1,222.39 343.24 2012 411.09 7.80 224.86 1,282.93 368.60 2013 431.35 8.25 231.51 1,346.45 395.80 2014 452.62 8.73 238.37 1,413.07 424.98 2015 474.94 9.23 245.42 1,482.97 445.69 2016 498.36 9.77 252.69 1,556.29 476.89 2017 522.93 10.33 260.17 1,633.20 510.20 2018 548.71 10.93 267.87 1,713.87 545.78 2019 575.76 11.56 275.80 1,798.50 583.77 2020 604.14 12.22 283.97 1,887.26 624.33 2021 633.92 12.92 292.37 1,980.35 667.22 2022 665.17 13.66 301.03 2,078.00 712.98 2023 697.96 14.44 309.94 2,180.41 761.80 2024 732.36 15.27 319.11 2,287.81 813.89 2025 768.46 16.14 328.56 2,400.46 869.44

31

Figure 1.26 SOx Emissions per Sector

0

200

400

600

800

1,000

1,200

1,400

1990 1995 2000 2005 2010 2015 2020 2025

(Thousand Ton)


(Thousand tons)


32

Figure 1.27 Total Capacity of Oil Refinery

175

375

575

775

975

1,175

1,375

1985 1990 1995 2000 2005 2010 2015 2020 2025 2030

(Million BOE)

Data Projection

Figure 1.28 Total Capacity of Gas Refinery

175

225

275

325

375

425

475

1985 1990 1995 2000 2005 2010 2015 2020 2025 2030

(Million BOE)

Data Projection

33

Figure 1.29 Total Capacity of Power Generator Total Capacity of Power Generator

0

20

40

60

80

100

120

140

1985 1990 1995 2000 2005 2010 2015 2020 2025 2030

(GW)

Data Projection

Figure 1.30 Investment Cost of Oil

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024

(Million USD)

Oil Refinery Depo

34

Figure 1.31 Investment Cost of Gas

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024

(Million USD)

Gas Refinery Gas Pipeline

Figure 1.32 Investment Cost of Coal

0

200

400

600

800

1,000

1,200

1,400

1,600

2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024

(Million USD)

Coal Railroad Coal Harbor

Figure 1.33 Investment Cost of Electricity

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024

(Million USD)

Power Generator Transmission & Distribution

35

Table 1.2 Intensity of Total Energy Consumption

Primary Energy Consumption per GDP Primary Energy Consumption per Capita Year

TOE/Million USD (at constant price of 2000) TOE/Person 1990 67.01 0.37 1991 63.77 0.38 1992 65.04 0.39 1993 58.98 0.41 1994 57.81 0.42 1995 56.40 0.44 1996 54.59 0.45 1997 55.98 0.47 1998 63.61 0.46 1999 70.19 0.51 2000 71.88 0.54 2001 73.28 0.57 2002 71.37 0.57 2003 68.75 0.56 2004 74.36 0.63 2005 73.53 0.65 2006 73.60 0.68 2007 72.74 0.70 2008 73.02 0.73 2009 72.13 0.76 2010 71.04 0.78 2011 70.34 0.81 2012 69.73 0.84 2013 69.13 0.88 2014 68.55 0.91 2015 67.75 0.94 2016 67.16 0.98 2017 66.59 1.02 2018 66.03 1.05 2019 65.49 1.10 2020 64.96 1.14 2021 64.43 1.18 2022 63.91 1.23 2023 63.41 1.28 2024 62.91 1.33 2025 62.43 1.38

36

Table 1.3 GDP Elasticity of Energy Consumption

Annual Growth Rate (%) Year

Energy Consumption GDP GDP Elasticty

1990 1991 3.99 7.01 0.57 1992 5.92 6.76 0.88 1993 5.24 15.21 0.34 1994 4.10 7.54 0.54 1995 5.40 8.22 0.66 1996 3.87 7.82 0.49 1997 5.27 4.70 1.12 1998 -0.39 -13.13 0.03 1999 8.37 0.79 10.57 2000 6.85 4.90 1.40 2001 4.35 3.83 1.14 2002 1.98 4.38 0.45 2003 1.16 4.88 0.24 2004 10.18 5.13 1.98 2005 4.21 5.60 0.75 2006 4.07 5.60 0.73 2007 4.16 5.40 0.77 2008 5.70 6.30 0.90 2009 4.57 6.30 0.73 2010 4.59 6.30 0.73 2011 4.61 6.50 0.71 2012 4.62 6.50 0.71 2013 4.64 6.50 0.71 2014 4.66 6.50 0.72 2015 4.67 6.50 0.72 2016 4.69 6.50 0.72 2017 4.71 6.50 0.72 2018 4.72 6.50 0.73 2019 4.74 6.50 0.73 2020 4.76 6.50 0.73 2021 4.77 6.50 0.73 2022 4.79 6.50 0.74 2023 4.81 6.50 0.74 2024 4.82 6.50 0.74 2025 4.84 6.50 0.74

37

Table 1.4 Emissions per GDP

CO2 Emission per GDP NOx Emission per GDP SOx Emission per GDP Year CO2 Ton/Million USD

(2000 Prices) NOx Ton/Million USD

(2000 Prices) SOx Ton/Million USD

(2000 Prices) 1990 248.81 0.72 0.28 1991 236.06 0.72 0.27 1992 238.56 0.73 0.26 1993 214.93 0.67 0.23 1994 205.11 0.65 0.21 1995 198.67 0.65 0.20 1996 192.63 0.65 0.19 1997 196.01 0.66 0.20 1998 227.05 0.74 0.23 1999 241.48 0.79 0.24 2000 246.06 0.81 0.25 2001 244.92 0.82 0.25 2002 240.41 0.81 0.24 2003 234.42 0.79 0.24 2004 244.22 0.83 0.25 2005 241.20 0.83 0.25 2006 241.98 0.83 0.25 2007 238.55 0.82 0.25 2008 238.76 0.82 0.25 2009 235.27 0.81 0.24 2010 230.77 0.80 0.24 2011 227.61 0.80 0.24 2012 224.76 0.79 0.23 2013 222.00 0.78 0.23 2014 219.32 0.78 0.23 2015 215.55 0.77 0.22 2016 212.85 0.76 0.22 2017 210.22 0.76 0.22 2018 207.66 0.75 0.21 2019 205.16 0.74 0.21 2020 202.72 0.74 0.21 2021 200.32 0.73 0.21 2022 197.98 0.72 0.20 2023 195.71 0.72 0.20 2024 193.48 0.71 0.20 2025 191.32 0.71 0.20

38

Table 1.5 Emissions per Capita

CO2 Emission per Capacity NOx Emission per Capacity SOx Emission per Capacity Year

CO2 Ton/Person NOx Ton/Person SOx Ton/Person 1990 1.35599 0.00394 0.00150 1991 1.39684 0.00416 0.00154 1992 1.44486 0.00442 0.00157 1993 1.47948 0.00464 0.00157 1994 1.49812 0.00473 0.00155 1995 1.54983 0.00505 0.00156 1996 1.59915 0.00538 0.00159 1997 1.65691 0.00560 0.00166 1998 1.64237 0.00538 0.00168 1999 1.75905 0.00575 0.00177 2000 1.85468 0.00613 0.00189 2001 1.89104 0.00630 0.00190 2002 1.90675 0.00639 0.00192 2003 1.92024 0.00650 0.00196 2004 2.07825 0.00710 0.00212 2005 2.13740 0.00734 0.00218 2006 2.23747 0.00763 0.00230 2007 2.29956 0.00788 0.00237 2008 2.39933 0.00827 0.00248 2009 2.47640 0.00858 0.00257 2010 2.54429 0.00886 0.00264 2011 2.62838 0.00920 0.00272 2012 2.71862 0.00956 0.00282 2013 2.81257 0.00993 0.00291 2014 2.91041 0.01032 0.00301 2015 2.99615 0.01068 0.00309 2016 3.09892 0.01109 0.00319 2017 3.20577 0.01152 0.00330 2018 3.31686 0.01197 0.00341 2019 3.43239 0.01243 0.00353 2020 3.55254 0.01291 0.00365 2021 3.67698 0.01341 0.00378 2022 3.80641 0.01394 0.00391 2023 3.94105 0.01448 0.00405 2024 4.08112 0.01504 0.00419 2025 4.22684 0.01563 0.00434

39

Figure 1.34 Contribution of Primary Energy Supply

*) with Biomass and Hydro **) without Biomass and Hydro

Natural Gas31.26%

Coal34.58%

Renewable*14.83%

Crude Oil19.32%

Natural Gas36.57%

Coal40.45%

Renewable**0.38% Crude Oil

22.60%

1,740.75 Million BOE 1,488.26 Million BOE

Year: 2005 Year: 2005

Natural Gas32.33%

Coal38.20%

Renewable*15.78%

Crude Oil13.69%

Natural Gas38.09%

Coal45.01%

Renewable**0.76% Crude Oil

16.13%


Year: 2015 Year: 2015

Natural Gas34.69%

Coal39.15%

Renewable*15.02%

Crude Oil11.14%

Natural Gas40.42%

Coal45.61%

Renewable**0.98%

Crude Oil12.98%


Year: 2025 Year: 2025

40

Figure 1.35 Contribution of Final Energy Consumption

Electricity10.44%

Coal14.13%

Natural Gas13.71%

Petroleum Fuel61.72%

627.43 Million BOE

Year: 2005

Natural Gas16.19%

Electricity12.50%

Coal17.07%


1,054.83 Million BOE

Year: 2015


Electricity14.66%

Coal19.14%

Natural Gas18.20%

1,802.03 Million BOE Year: 2025

41

ENERGY ANALYSIS, PERSPECTIVE, and POLICY

Aftermath economic crisis in 1998, energy sector in Indonesia experienced dynamic

changes signified by considerable growth of energy demand and amendment of legislations and

regulations of energy compounded by oil price hikes. Since then, we are aware that in the future

there would be a turning point where Indonesia becomes a net energy importer rather than a net

energy exporter. Currently Indonesia is a net oil importer as the oil production nationally steadily

declines. It should be noted that natural gas production follows oil to decline. As a result,

Indonesia is no longer a largest LNG exporter in the near future. It is a high time to look closely

the sustainability of national energy supply while improving the utilization of energy alternatives

which are more sustained.

Facing such unfavorable situation, government of Indonesia prioritizes improvement of

national energy supply security by issuing Blue Print Energy Policy 2005 and national energy

policy by issuing Presidential Decree 5/2006. Measures to ensure the supply security include

diversification of energy sources, rationalization of energy pricing and improvement of energy

efficiency. In addition to that, the government will propose an energy bill. However, the success

of the supply security is also dependent on the readiness of supporting policies and all energy

stake-holders. Some further analysis on each energy sector will be addressed in the following

sections.

1.1 Oil and Gas

Current Conditions

In 2005, Indonesia’s oil reserves are around 8.63 billion barrels, with proven reserves of

4.19 billion barrels corresponding to 0.4% of world proven reserves, and potential reserves of

4.44 billion barrels. A large amount of proven oil reserve is located onshore. Central Sumatra

is the largest oil producing province (e.g. the Duri and Minas oil fields). Other major fields are

located in East Kalimantan, Northwestern Java, and the Natuna Sea.

Indonesian crude oil production including condensate is about 342 million barrels in

2005. This production gradually declined 33% from year of 2000 due to ageing oil fields and

lack of investment for exploration and development. The total revenue from crude oil export has

increased to US$ 8.2 billion in 2005 compared to US$ 6.3 billion in 2000 due to higher price of

crude oil though the export volume was lower in 2005. While the import value of crude was US$

6.5 billion in 2005.

At present Indonesia have nine refineries, with a total installed capacity of 1.1 million

barrel per day (bpd). The largest refineries are in Cilacap – Central Java of 348,000 bpd, in

Balikpapan – Kalimantan of 260,000 bpd, and in Balongan – East Java of 125,000 bpd.

However, since the installed capacity of the refineries is unchanged as opposed to the

42

increasing domestic fuel consumption, the import value of petroleum product has augmented

significantly. The import figure of petroleum products in 2005 was about 158 million barrels

corresponding to US$ 10.3 billion. For comparison, the import volume in 2000 was only 87

million barrels or US$ 2.9 billion. In the same time Indonesia export refined products was about

US$ 2.05 billion. So the net financial balance of oil is minus US$ 6.6 billion.

Domestic petroleum fuels consumption increased to 354 million barrels in 2005 from

293 million barrels in 2000, corresponding with share of 62% of total final energy consumption.

Most of domestic fuel consumption is used by transportation (30%), industry (44%) and

household (16%) sectors.

In 2005, domestic fuel prices are still the subsidized price mainly for kerosene except

high grade petroleum fuels and for industrial proposed. This policy is intended to minimize the

impact of fuel price to the lower income groups. However, since the amount of fuel subsidy has

reached a staggering value of Rp. 68 trillion in 2001, the government is planning to ease the

budget by limiting the subsidy to ~ Rp. 30 trillion in 2003. A new pricing policy was introduced in

which the domestic fuel price is gradually set to follow the trend of the international fuel price.

However, in 2005, crude oil prices increased significantly up to ~ 60 US$/barrel that cause re-

increasing fuel subsidies at level Rp. 99.5 trillion that extremely costly to economy.

Indonesia’s natural gas reserves in 2005 are 185.8 trillion cubic feet (tcf). About 97.3 tcf

is proven and 88.5 tcf is probable reserves. This corresponds to almost 2.7 % of world proven

natural gas reserves. More than 70 % of natural gas reserves are located offshore which far

from demand centre, with the largest reserves are in East Kalimantan, Natuna Island, Papua,

Aceh, and South Sumatra. The most promising new finds are Wiriagar, Berau, and Muturi fields

located in Papua, with total proven reserves of about 14.4 tcf, and Donggi, Centre of Sulawesi.

Indonesia’s natural gas gross production decreased slightly to 2.98 tcf in 2005 from

3.15 tcf in 2003. For liquefied natural gas (LNG), total production capacity of LNG Plants at

Arun and Bontang are 12.85 and 21.64 billion ton per year, respectively. The current

Indonesia’s LNG and LPG production are 23.7 million metric tons and 1.8 million metric tons per

year, respectively. The major markets for Indonesian LNG are Japan, South Korea and Taiwan.

An export through pipeline to Singapore and Malaysia accounted for about 4.8% of the total

natural gas production. The development of BP’s Tangguh gas field in Papua is intended for

markets in China. The total revenue for LNG export has increased to US$ 9.1 billion in 2005

compared with US$ 6.8 billion in 2000 due to higher price of LNG.

Most of the natural gas produced (about 60 %) was processed into liquefied natural gas

(LNG) for export purposes. The rest is consumed domestically, mainly for industries and

electricity. Increasing gas domestic demand however not follows by development of natural gas

production, domestic infrastructures and appropriate gas pricing policy. The sign of tightening

supply of natural gas was observed when faced supply shortages gas for domestic utilization

such as fertilizer industry, ceramic industry and electricity as well as the deferment of some LNG

cargoes for export.

43

Projection The projections for oil and gas sectors for time horizon up to 2025 are as follows. For

reserves-to-production ratio (R/P) equal to 10 years. Total domestic demand of crude oil will

reach 923 million BOE at 2025 which is 2.1 times the consumption in 2005. In 2012 the crude

production is expected to equalize the crude import where the import contributes 61% of the oil

domestic consumption. The contribution will increase to reach 80% or 739 million BOE in 2025.

As to balance of natural gas, it is interesting that at year of 2009 the domestic natural

gas consumption reaches to value of natural gas exports (~300 million BOE). At period of 2005-

2025, domestic natural gas consumption production attain 838 million BOE with average growth

rate per year is almost 6.8% driven mainly by the growth in industrial and electricity sectors.

Currently Indonesia is expected to remain the world’s biggest LNG exporter in the next few

years however LNG production capacity is to decline in the long term due to declining natural

gas reserves and increasing domestic utilization.

In twenty years, the total primary energy consumption originating from oil and gas at

2025 will increase significantly close to 2.1 times for oil (923 million BOE) and 3.8 times for gas

(838 million BOE) compared to the 2005’s figures. The rate of energy consumption (oil and gas)

is still higher than the finding rate of new oil and gas reserves. In 2025, the total final energy

consumption will still be dominated by oil fuels and gas (66.2%) compared to about 75% in 2005

(excluded biomass). In the near future, the roles of oil and gas sector are still important in

securing national energy supply.

The total emission of CO2, NOx, and SOx in 2025 will reach a value of 1,200 million ton,

4.4 million ton, and 3.7 million ton compared to 450 million ton, 1.7 million ton, and 2 million ton

in 2005, respectively.

Regarding oil and gas infrastructures at 2025, Indonesia needs to construct new

petroleum refineries with capacity 2 times to current refinery capacity, correspond to 2.2 million

b/d capacities with an assumption of no imported petroleum fuels. This corresponds to

accumulative investment of US$ 35 billion. An additional storage facility requires new

investment around US$ 10.5 billion. For natural gas infrastructure, estimated total investment ~

US$ 10 billion including gas refineries and pipeline gas. All estimated investments are

calculated based only on capital expenditures.

Policy

The dynamic situation of Indonesia’s oil and gas sector is occurring, reflected by the

introduction oil and gas law (UU No. 22 tahun 2001) As consequences oil and gas industries are

deregulated whereas dominant state-own companies that have monopoly characteristics are

changed toward competitive oil and gas industry structure.

The fact that the implementation of oil and gas law has some limitations due to lack of

clarity in transition policy to become fully deregulated, in action plans and in other supporting

policy instruments. In addition, new institutions such as BPMIGAS (Oil and Gas Upstream

44

Executing Body) and BPH MIGAS (Oil and Gas Downstream Regulatory Body) need to have

clear authorities and Directorate General of Oil and Gas, however, needs better job coordination

with BPMIGAS and BPH MIGAS. Ideally, a regulator in its role can bring in more investments in

the oil and gas. The regulator should be autonomous and independent. The rules of games

should be transparent with minimal external interference. The regulator should balance the

interests of the customers, the producers, and other stakeholders.

In the upstream of oil and gas sector, the government would set a competitive fiscal

terms to attract investors for development of mature and frontier areas including marginal and

depleting fields. The role of national entrepreneurs in exploration activity is smalls; the

government would make the indigenous companies enter into exploration activities so that more

benefits will come to Indonesia. The government should reform to enhance good practice of

government agencies in interacting with investors.

In the downstream oil and gas sector, the Indonesian faces a number of obstacles

mainly limited infrastructures of energy in conversion, transportation, distribution and storage

and disincentives in the pricing of domestic petroleum products and gas as well as supply

shortage of kerosene and gas for domestic purposes.

In downstream oil sector, the capacity of petroleum refineries and storage capacity

should be increased to accommodate the growing domestic demand. Reform in lifestyle of

energy consumption especially kerosene and LPG usages must be performed. Kerosene is high

quality fuel and expensive, its properties close to jet fuels. It is necessary to make real efforts to

promote the consumption of non-oil fuels such as gas, briquette and biofuels to substitute

kerosene, simultaneously by eliminating the oil-based fuel subsidies. For the short term, LPG is

an alternative solution to substitute kerosene, however for the long term LPG usage for urban

area fuels is expensive if city gas pipelines are available. LPG is commonly used in remote

areas in which gas networks unavailable and in the future LPG is vital feedstock for

petrochemical industry since source of naphtha is limited.

Petroleum market reform can proceed from the supply chain into the retail market and

result in competing wholesale distributors and retail outlets. However, some obstacles to the

market reform are appeared such as domestic petroleum fuels are still subsidizes and disparity

of consumption between regions (Java and Sumatra vs. other inlands). The fact shows that any

subsidy given by the government does not immediately give benefits to low-income

communities. Instead, it raises irregularities in communities leading to the scarcity of kerosene

in the fields. A campaign to improve public awareness and care should be launched so that they

will appreciate the use of non-renewable energy and eventually they start opting to use energy

alternatives.

Certain key conditions need to be met to achieve reform in the petroleum product

market are transport and storage facilities must be sufficient to cope with the demand,

requirements for investors to enter the market must be simplified and prices need to reflect

differences in regional transport costs and market size. Barriers to enter the market need to be

45

abolished, in particular, unnecessary legal and administrative procedures. Open access needs

to be introduced to monopolistic facilities (such as marine terminals, storage facilities, and

pipelines) through nondiscriminatory tariffs and quality standards need to be set for products

that take into account the market characteristics and maximize the number of supply sources.

Proper fiscal terms and incentives are needed to promote private investment to participate in

infrastructure development.

In gas sector, Indonesian traditional gas market is still dominated by LNG export

commodity. Unfortunately, the current global LNG market is greater choice of suppliers such as

Australia, Malaysia, Qatar, and many others. The LNG business is growing and globalizing

rapidly, driven by its increasing cost competitiveness and increasing gas demand. On the other

hand, contribution of Indonesian natural gas domestic market is still limited. The utilization is

mainly for power generation, fertilizer, and industry as well as flare. Despite of higher domestic

gas demand, an old paradigm that natural gas development is aimed to increase the

government revenue rather than to increase economic growth still persists. The development

should lead to enhancing economic trickle down effects to maximize gas value chains. The

domestic price of natural gas is still low so that there is reluctancy of gas producers to meet

domestic lack of natural gas supply. This is also related to the prices of fertilizers and electricity

which haven’t reached their economic values.

In the future, government should adjust its policy in natural gas especially gas pricing

policy, the development of reliable integrated gas network/logistic by considering gas balance in

the future and, the development of new options of infrastructure through the application of

emerging technologies such as LNG CNG, GTL, GTC, and GTW and complementary

integration to traditional pipeline gas. This new market is aimed to provide support for national

security of energy supply, to achieve more efficient energy consumption in more

environmentally responsible manner, and to encourage the use of cleaner alternative fuels and

high gas values added. The role of government to assure direction of gas market transformation

is extremely essential. This can be done by establishing gas market and sector reforms through

clear and transparent regulatory process, rational pricing framework, and introducing clear and

innovative scheme providing special incentives such as fiscal and rational wellhead gas price to

facilitate new investment for natural gas development.

Finally, a good understanding of the enormous interests of the oil and gas industry and

a well-defined and articulated political commitment are essential for structural reform. Prices

usually need to be corrected, a new regulatory framework put in place, and certain key

conditions met during a transition period to ensure that a truly competitive market is established.

As a nation we should be responsible to improve national productivities for each calory of oil

and gas used. It is unethic if we only used it to fullfil our current life style in energy comsumption

or to pay our debt without concerning in its sustainability for future generation. The national

energy policy needs to be more integrative by considering all type of energy resources and

more sustainable energy approach.

46

1.2 Coal Current Conditions

Coal reserves in Indonesia are characterised by thick seams, often 5-15 meter thick

across substantial areas and up to 70 meter thick in places. Most of the coal seams are close to

the surface. Consequently, around 95% of Indonesia’s coal are at present produced from

surface mining operation. As indicated by the Directorate of Coal, Ministry of Energy and

Mineral Resources, Indonesia has significant coal resources of 38.8 billion million tons of

identified coal deposits, of which 11.5 billion tons are classified as measured resources and

27.3 billion tons as indicated, inferred and hypothetical resources, with 5.4 billion tons classified

as commercially exploitable reserves. Major coal resource areas are Kalimantan and Sumatra,

estimated at 21.2 billion tons and 17.5 billion tons, respectively. The coal mined in Indonesia

generally has heat values ranging between 5,000 and 7,000 kcal/ kg, with low ash and sulfur

levels. The average sulfur content of commercially produced Indonesian coals is below 1.0

percent.

The Indonesia’s coal producers include: (a) the state-owned mines operated by PTBA,

(b) coal contractors, (c) coal mining authorization, and (d) coal operatives. From mine to port or

barge loading facilities, coal is transported by conveyor belt, as most of the coal deposits are

usually close to the coast or navigable waterway. The major existing coal loading infrastructures

include approximately 640 km single railway track in Sumatera and 18 coal harbors in Sumatera

and Kalimantan with a combined loading capacity of over 75 million tons per year. Most of the

terminals are classified as small and medium capacity (5,000 - 6,000 DWT) while four terminals

classified as large capacity (150,000 – 200,000 DWT) are located in East and South

Kalimantan.

Indonesia’s coal production increased sharply from 77 million tons in 2000 to 150 million

tons in 2005. Indonesia’s domestic demand for coal is currently small relative to its production.

Of the 2005 coal production figure, about 40 million tons was consumed domestically, mainly for

power generation of about 25 million tons and the rest for cement production. The remaining

110 million tons which represented about 73% of total production was exported.

The share of coal in Indonesia’s primary energy supply rose from 15 percent in 2000 to

18.5 percent in 2005, primarily due to the development of coalfired power plants. Coal is

preferable as an energy source due to its relatively low price compared with oil and natural gas.

Projection INOSYD projections for coal sector for time horizon up to 2025 are as follows. In 2025,

coal production will reach 346 million tons per year, of which a half would be consumed

domestically. In 2025, the share of coal to total primary energy supply will reach about 30 % and

up to 60 % for electricity generation. Electricity generation is expected to continuously dominate

domestic coal consumption in 2025. The 2025’s figure for coal production (more than doubling

the 2005’s figures) will only be possible to achieved by furthering exploration activities and

47

massive investments in coal infrastructures and conducive mining policy. Without such

investments in coal exploration, due to sharp increase in coal production, the reserves to

production ratio for coal may fall below 50 years in 2025.

According to INOSYD projection, new development of coal infrastructures including

double tracking of Sumatra’s rail line and railways infrastructures in Kalimantan require

accumulative investment amounts to about US$1,500 million.

Policy

The dynamic situation of Indonesia’s mining including coal mining sector is occurring,

reflected by the introduction of Autonomy laws passed in 1999, law No. 22 on political autonomy

and its revision (law No. 32/2004), law No. 33/2004 on financial arrangement between

government and local governments, PP 75/2001 on mining contract at regional level and PP No.

104/2001 on royalty arrangement in mining sector, law No. 41 of 1999 on forestry and its

revision (Perpu No. 1 Tahun 2004). Currently new law on

The economic crisis and the dynamic situation in mining sector has affected the coal

sector as shown by the declined of coal investment (foreign and domestic) which was declined

from $778 million in 1997 to $135 million in 2001. Between 2002 and 2003, according to the

Energy Ministry, coal investment did rise, from $61 million to $90 million, primarily due to higher

coal prices. Other aspects to be considered are as follows: (i) the overlapping of land usage for

forestry and mining sectors as reflected by the introduction of Perpu No. 1 of 2004 to revise law

No. 41 of 1999; (ii) there is no national stocks to secure energy and electricity supply; (iii) most

of Indonesian coal is considered as lower rank coal which is preferable for domestic usage; (iv)

the existing coal infrastructure limits further extensions of coal exploration and mining activities.

Despite dynamic situations, it is expected that coal share in domestic electricity

generation and cement production will follow an increased trend. Coal would provide a

significant contribution in replacing Indonesia’s dependence on oil and natural gas, particularly,

for power generation and industrial sectors. This will be a consequence of the changing pattern

of energy production in Indonesia, and a government policy of diversifying domestic energy

consumption away from oil in order to preserve Indonesian’s oil declining reserves. However, in

securing a smooth transition to greater coal utilizations, Indonesia would require strategic policy,

considerations and clear measures to meet the challenges. Some of crucial policies to be

considered are as follows:

Securing domestic coal supply by coal national stock and integrated coal production

planning at national level.

Increasing exploration activities to improve coal deposit status and coal infrastructure

development.

Creating conducive climate for new investments (direct foreign and domestic) in coal

mining activities, by introduction of comprehensive mining law, clear regulations and

policies that promotes the clean and rational development of coal sector.

48

Greater usage of locally available fuels for regional development such as by mine-

mouth power-plant fueled by low rank coals.

Introduction of coal up-grading technology for greater use of low rank coals as well as to

increase its economic values.

Promoting cleaner coal technology research and development activities as well as

underground mine activities.

Promoting good coal mining and handling practices through out coal life cycles

including post mining site reclamation.

activities.

1.3 Renewable Energy

Current Conditions Indonesia is a vast archipelago located in the globe equator. Since Indonesia lies in the

equator, the average daily radiation in most places is quite intense (approximately 4 kWh/m2)

and therefore solar energy have abundant potential. Indonesia also has great potential of other

renewable energy resources such as geothermal, hydropower, wind energy, and biomass.

The total of potential of geothermal energy is 19,658 MW. Approximately 30 percent of

the reserves (8,100 MW) are located in Java. The remaining is situated in Sumatera (4,885

MW), Sulawesi, and in other islands. Total installed capacity of geothermal power plant is 903

MW or 4.01 % of its potential.

The total hydropower potential is estimated to be 75,000 MW, 34,000 MW of which is

exploitable. About 60 percent of these resources are located in Kalimantan and Papua.

The potential of microhydro energy is found in West Sumatra, Bengkulu, West

Kalimantan and Central Sulawesi, while the large installed capacities of the micro hydro

potential are found in North Sumatra, Bengkulu, Center of Java and West Java. The micro

hydro (PLTM) potential in Indonesia is estimated as 459.91MW. The PLTM has benefited for

power generation in the remote areas (20.85 MW or 4.54 % of the potential).

Total installed capacity of solar energy in Indonesia, especially photovoltaic, is about

6.5 MW. This total capacity is used to supply electricity for water pumps, vaccine refrigerators,

or lighting (solar home system). The solar home system installation is the most dominant

application, which comprises about 5.5 MW. Solar home system is a lighting system using

photovoltaic energy producing about 50 watt for each family and built in remote areas where

electricity grids are not available.

The wind speed in Indonesia is approximately between 2 to 6 m/s. This speed range is

suitable for small (10 kW) to medium scale (10 kW to 100 kW) power generations used as

energy sources for lighting, water pump, television, radio, and aeration in earthen dam, etc. The

main wind energy potential areas are located in East and West Nusa Tenggara which have the

49

average wind speeds of more than 5 m/s. The approximate wind power potential in Indonesia is

about 9,286.61 MW and only 0.5 MW of which has been used for generating power.

Biomass is biological power source, mainly originated from the waste of forest,

agriculture, and plantation commodities. Based on the phases, biomass can be grouped into

solid biomass, biogas, and liquid biomass. Solid biomass potential spreads across Indonesia as

follows: Papua (6,8 GW), East Java (5.4 GW), Central Java (4 GW), West Java (3,7 GW), East

Kalimantan (3,2 GW), Central Kalimantan (3 GW), South Sulawesi (92,5 GW), North Sumatra

(2,4 GW), West Kalimantan (2,2 GW), South Sumatera (1,8 GW), Lampung (1,7 GW), Riau (1,6

GW), Aceh (1,3 GW), West Sumatra, Jambi, South Kalimantan, Central Sulawesi, NTT &

Maluku (each 1 GW).

Biogas energy potential from droppings of cows, buffaloes, and pigs can be found in all

provinces with different quantities. Province of East Java has the most biogas energy potential

of 125,9 MW and followed by Central Java (63 MW), NTT (56,7 MW), North Sumatra (46,8

MW), Aceh (42,7 MW), South Sulawesi (26,8 MW), West Java (40,1 MW), Bali (32 MW), NTB

(28,2 MW), South Sumatra (26,8 MW), and West Sumatra. Provinces of Central Sulawesi, West

Kalimantan, North Sulawesi, Lampung and Southeast Sulawesi have biogas energy potential

between 10 MW until 19 MW each. In other provinces the potential of biogas energy is less than

10 MW.

Peat potentials spread across Sumatra, Kalimantan, and Papua with thickness

variability. Sumatera peat can reach deepest about 17 m. According to Directorate General of

Electricity and Energy Development, Ministry of Energy and Mineral Resources, the potential of

peat in Indonesia amounts to 97.93 X 1012 MJ. The huge potential is located in Riau (39.06

x1012 MJ), West Kalimantan (16.22 x 1012 MJ), & Central Kalimantan (12.23 x 1012 MJ). Other

regions such as Aceh, North Sumatra, South Sumatra, South Kalimantan, East Kalimantan and

East Sulawesi respectively have peat potentials of less than 7 x 1012 MJ.

Projection INOSYD projections for renewable energy sector up to 2025 are as follows. In 2025,

total renewable consumption (including biomass) will reach 505 million BOE or almost double

the 2004’s consumption figure (251.35 million BOE). By excluding biomass component in

renewable energy consumption, the total demand of renewable energy was 9.29 million BOE in

2005 and projected to rise to 49.55 Million BOE in 2025. However, in terms of the proportion of

renewable energy (including biomass) in Indonesia’s energy mix, its figure is projected to

decline from 28.69% in 2004 to 21.63% in 2025. If we exclude the biomass component from the

renewable energy consumption, the proportion of renewable energy in Indonesia’s energy mix is

projected to be about 2.64% in 2025. Comparison between both projections above shows that

biomass energy has predominating role in the utilization of renewable energy in Indonesia.

In the projection using INOSYD, each sector (industrial, commercial, residential and

transportation sectors) uses typical types of renewable energy as final energy. Transportation

sector is projected to utilize biodiesel and biethanol in forthcoming years. Residential sector

particularly in rural areas consume wood waste from harvesting activities and from forests for

50

cooking. In industrial sector small- and medium-sized industries may use to some extent wood

waste for their industry’s process. For generating electricity, it is projected that contribution of

renewable energy predominantly comes from hydrothermal and geothermal energy.

In comparison to other types of energy (petroleum fuels, coals and natural gas), in

industrial sector, the contribution of renewable energy to final energy consumption from years

2004 to 2025 reduces from 4.83% to 1.94%, though its consumption quantity increases from

12.04 to 14.48 million BOE. In commercial sector, the contribution of renewable energy also

reduces from 7.51% in 2004 to 2.70% in 2025 with its consumption quantity increasing from

1.60 million BOE in 2004 to 2.94 million BOE in 2025. In residential sector, the contribution

slightly reduces from 72.52% in 2004 to 69.24% in 2025 with its consumption quantity

increasing from 223.42 million BOE to 408.95 million BOE. A contrary situation occurs in

transportation sector where the contribution of renewable energy slightly increases from none in

2004 to 8.84% in 2025 thanks to the introduction of biofuels in transportation.

As a final energy for electricity generation, the contribution of renewable energy

increases in terms of quantity from 14.29 million BOE in 2004 to 78.62 million BOE in 2025. In

terms of proportion in energy mix for electricity generation, its contribution also increases from

8.91% in 2004 to 13.05% in 2025. As a primary energy, the contribution of renewable energy to

the whole energy mix increases from 251.35 million BOE in 2004 to 504.99 million BOE in 2025

and its proportion in the whole energy mix 28.69% in 2004 to 21.62% in 2025.

Policy

The future of Indonesia’s renewable energy usage in the next decade will depend on

government policy on this energy sector. Some crucial policies for renewable energy sector to

be considered are as follows:

Reform on regulation framework to boost the utilization of renewable energy in

households, industry and electricity generation.

Increasing the use of small-scale electricity power generation using local renewable

energy sources.

Creating clear policy on investment and funding schemes, such as (i) wider roles of

private sector, BUMN, BUMD, and cooperatives in the development of renewable

energy; (ii) incentive policy making; (iii) creative funding mechanism.

Policy in human resource developments through education and training, and knowledge

and technology transfer.

Increasing infrastructure and supporting industries related to the development of

renewable energy sector.

Accelerating adjustment of the price of fossil fuel energy towards its economic price.

51

1.4 Electricity Current Condition

In 2006 the average growth of electricity demand in Indonesia is about 7.5% per year.

This growth figure doesn’t show a normal growth rate due to two main reasons. Firstly, the

government subsidizes the electricity, and secondly, the growth number actually only shows the

electric company’s capability to fill the electricity demands from the consumers. In fact, there are

still huge numbers of waiting lists for the electricity.

The average elasticity for electricity is around 1.5 showing that the major part of

electricity usage in Indonesia is still not productive and efficient. This means an increase of 1

percent in economic growth requires 1.5 percent growth in electricity consumption.

In 2005, Indonesia’s electrical generating capacity (PLN only) is 22,515 MW with more

than 30 million consumers. In Java alone, the installed capacity in year 2005 was 16,355 MW

with peak load of 14,824 MW. The peak load for Indonesia is considered to be about 19,263

MW. This peak load figure is not the real peak load since it was determined from the total of

region’s peak load. The real peak load should come from an interconnected system. Therefore,

the planning for Indonesia’s peak load is supposed to be made per regions which are

interconnected, not based on the number of Indonesian peak burden. The electricity sold by

PLN in Indonesia is 107,032 GWh, where Java consumes 83,3% of total electricity sold. In

2005, electrification ratio was still low at 54 percent for Indonesia, 57 percent for Java and 48

percent for outside Java.

Projection In the period of 2025, electricity demand is reaching 440.5 GWh corresponds to 270

million BOE, with 83% fueled by coal and natural gas. Contribution of renewable energy is only

13.1%. The highest electricity consumptions are projected to be industrial sector of 55% and

household sector of 29.2 %. In comparison to current total installed capacity of power

generation, in the year 2025, around 70,000 MW new power plants are needed to support the

economic and social growth. The cost for adding the power plant infrastructure to 2025 is

projected to be about US$ 55,000 Million.

Policy Main problems of Indonesian electricity sector are electricity shortages in some regions;

high oil price resulting in huge government subsidy; limited spare capacity of electricity

infrastructures, i.e. the power generation and transmission network capacities. One factor that

may cause lack of new investment in this sector is the fact that electricity tariff applied is yet

from its economic price that may be due to considered to attracted new investments in this

sector. In general, due to unreliability in electricity transmission and distribution, some potential

customers provide their own self-generation plants.

52

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

6 8 10 12 14 16 18 20 22 24 2 4 6

Time

Elec

tric

ity c

onsu

mpt

ion

(MW

)

HouseholdCommercialIndustryTOTAL

Figure 1.36 Typical daily load curve of Java – Madura – Bali system [PLN, 2006]

According to the daily load curve of electricity demand (Figure 1.36), the peak load

occurs in the evening and mainly contributed by household sector. During the peak load time,

PLN adds the electricity supply by operating oil based electricity generation plants, such as gas

turbine, diesel engine, etc. In 2005, Indonesia managed to reduce subsidies for oil products.

Indonesia began to set up mechanisms to formulate industrial oil product prices and high grade

oil product prices for transportation reflecting price changes in the world oil market. However,

since oil based power plants are still widely used to supply electricity demand during peak

hours, the sharp increase in oil prices since 2005 has forced the government to provide huge

subsidy to electricity sector. In 2005, about IDR 12.5 trillion (US$ 1.38 billion) of government

expenditure went to electricity subsidies.

The electricity policies to be considered in the near future are :

For well-established areas the provision of electricity can be undertaken efficiently

through competition and transparency in a healthy business climate with regulations

that provide the same treatment to all business players and provide benefits fairly and

evenly to consumers.

Priorities for new investments and developments of more efficient and environmentally

friendly power generation plants and electricity transmission.

53

The greatest utilization of domestically produced goods and services that are

competitive and yield added value so as to result in the development of the national

electricity industry; Initiave to tackle the existing electricity crisis in several regions. Based on partnership program in energy audit for buiding and industrial sectors, energy

saving up to 25 percent is possible. Thus, effective energy conservation measures for

building and industries are recommended as part of demand side management. Easy access to the grid with contracts for transmission must not present a barrier.

Removal of regulatory barriers to competition in generation and distribution.

Rationalization of electricity sale price

Reducing the dependency to oil fuels and increasing the role of natural gas, coal and

renewable energy sources for power generation.

55

II. SELECTED ECONOMIC INDICATORS OF INDONESIA


SELECTED ECONOMIC INDICATORS

57

Table 2.1 Population, GDP, Energy Consumption, Energy Intensity, and Energy Consumption per Capita, 1990 – 2005

Population GDP Energy Consumption

Energy Intensity

Energy Consumption

per Capita

Million Growth (%)

Billion Rp.

Growth (%)

Million BOE

Growth (%)

Million TOE/ Million Rupiah

GDP

Million TOE/ Million People

Year

1 2 3 4 5 6 (7) = (5)/(3) (8) = (5)/(1)

1990 179.25 875,025 411 0.0635 0.3102 1991 181.76 1.40 936,400 7.01 428 3.90 0.0618 0.3183 1992 184.28 1.38 999,721 6.76 454 5.65 0.0613 0.3327 1993 186.79 1.37 1,151,729 15.21 478 5.06 0.0561 0.3458 1994 189.31 1.35 1,238,570 7.54 498 4.07 0.0544 0.3556 1995 191.83 1.33 1,340,380 8.22 526 5.24 0.0530 0.3704 1996 194.34 1.31 1,445,173 7.82 547 3.84 0.0511 0.3802 1997 199.84 2.83 1,513,095 4.70 575 4.98 0.0514 0.3891 1998 202.87 1.52 1,314,475 -13.13 573 -0.38 0.0589 0.3818 1999 203.05 0.09 1,324,874 0.79 621 7.74 0.0634 0.4134 2000 205.84 1.38 1,389,770 4.90 664 6.45 0.0646 0.4359 2001 208.65 1.36 1,442,985 3.83 693 4.14 0.0649 0.4486 2002 212.00 1.61 1,505,216 4.50 707 1.99 0.0635 0.4505 2003 215.28 1.54 1,577,171 4.78 715 1.16 0.0613 0.4488 2004 216.38 1.30 1,656,826 5.05 787 9.19 0.0642 0.4917 2005 219.21 1.30 1,749,547 5.60

Source: Statistical Year Book of Indonesia, 2000-2005, Indonesian Bureau of Statistics (Processed) Table 2.2 Average Rates of Foreign Currencies and Gold in Market,

1997-2005

Rupiah 1997 1998 1999 2000 2001 2002 2003 2004* 2005

US Dollar 4,650 8,025 7,100 9,595 10,400 8,940 8,465 9,290 9,900 English Pound 7,709 13,336 11,495 14,299 15,080 14,334 15,076 17,888 17,358 Australian Dollar 3,040 4,923 4,622 5,318 5,309 5,065 6,347 7,242 7,335 Malaysia Ringgit 1,198 2,112 1,868 2,525 2,736 2,353 2,258 2,445 2,650 Jepang Yen 2,422 7,497 6,901 7,874 8,408 7,441 7,449 - - Hong Kong Dollar 600 1,036 914 1,230 1,333 1,146 1,090 1,195 1,303 Uni Europe Euro - - 8,288 7,820 9,141 8,783 9,602 - - Gold 28,457 84,511 66,208 71,875 80,000 85,000 100,000 97,500 n.a * Data at October 2004 except gold Sources:

- Statistical Year Book of Indonesia, 2000-2005, Indonesian Bureau of Statistics - Bank Indonesia, www.bi.go.id

58

Table 2.3 Description of Indonesia Macroeconomics, 1997 – 2005 Description Unit 1999 2000 2001 2002 2003 2004* 2005

Population million 203.047 205.843 208.647 212.003 215.276 217.840 219.205

Unemployment % 6.4 6.1 8.1 9.2 9.5 9.9

Growth of real GDP % 0.79 4.90 3.83 4.38 4.88 5.13 n.a

Growth of real GDP (non oil-gas) % 1.09 5.31 5.11 5.09 5.80 6.17 n.a

GDP billion Rp. 1,324,874 1,389,770 1,442,985 1,506,124 1,579,559 1,660,579 1,749,547

Inflation rate % 2.01 9.35 12.55 10.03 6.79 6.06

Nominal exchange rate Rp/US$ 7,100.00 9,595.00 10,400.00 8,940.00 8,465.00 9,290.00 9,900.00

Export Million US$ 48,665.40 62,124.00 56,320.90 57,158.80 61,058.20 71,584.60 85,660.00

Export of non oil-gas commodities Million US$ 38,873.20 47,757.40 43,684.60 45,046.10 47,406.80 55,939.30 66,428.40

Import Million US$ 240,033.00 33,514.80 30,962.10 31,288.90 32,550.70 46,524.50 57,700.90 Import of non oil-gas commodities Million US$ 20,322.20 27,495.30 25,490.30 24,763.10 24,939.80 34,792.50 40,243.20

Government Budget

- Revenues billion Rp. 219,604 152,900 263,200 301,900 336.200 349.900 380,400

- Expenditure billion Rp. 219,604 197,000 315,700 344,000 370.600 374.300 397,800

- Surplus/Deficit billion Rp. 0 -44,100 -52,500 -42,100 -34.400 -24.400 -17,400

Realization of Government Budget

- Revenues billion Rp. 245,325 205,000 301,100 300,200 342.800 407.800 495,400

- Expenditure billion Rp. 245,192 221,000 341,600 327,900 377.200 435.700 509,400

- Surplus/Deficit billion Rp. 133 -16,000 -40,500 -27,700 -34.400 -27.900 14,000 Difference of Budgeted and Realization

- Revenues billion Rp. -25,721 -52,100 -37,900 1,700 -6.600 -57.900 -115,000

- Expenditure billion Rp. -25,588 -24,000 -25,900 16,100 -6.600 -61.400 -111,600

Current Account Million US$ 5,782 7.99 6.901 7.822 8.107 2.337

Service Net Million US$ -14,859 -17.051 -15,795 -15.69 -16.456 -13.604

Capital Transaction Million US$ -4,569 -7.896 -7.617 -1.103 -950 584

Foreign Assets Million US$ 27,054 29,394 28,016 32.039 36.296 34.802

Domestic investment billion Rp. 53,550.0 17,496.5 58,816.0 25,307.6 48,484.8 37,140.4

Foreign investment million US$ 10,890.5 6,087.0 15,055.9 9,789.1 13,207.2 10,279.8

Inflation rate % 2.01 9.35 12.55 10.03 6.79 6.06

Demand Deposits billion Rp. 115,566 175,508 190,317 204,067 224.759 247.143

Time Deposits billion Rp. 387,071 390,543 446,198 447,480 433.127 421.288

Saving Deposits billion Rp. 122,981 154,328 172,611 193,468 244.44 296.647

* Data at October 2004 Sources:

- Statistical Year Book of Indonesia, 2004, Indonesian Bureau of Statistics - Bank Indonesia, www.bi.go.id

59

Table 2.4 Gross Domestic Product based on Current Market Prices by Industry Origin, 1999-2005

1999 2000 2001 2002 2003 2004 2005 Agriculture, Livestock, Forestry, & Fishery 215,686.7 217,897.9 263,327.9 298,876.8 35,653.7 354,435.3 365,559.6 Mining & Quarrying 109,925.3 175,262.5 182,007.8 161,023.8 169,535.6 196,892.4 285,086.6 a. Crude Petroleum & Natural Gas 72,424.9 129,220.9 115,335.1 93,092.0 94,780.4 120,640.5 168,132.4 b. Non Oil & Gas Mining 27,696.1 34,495.7 52,560.3 51,277.5 55,659.7 54,533.9 90,392.2 c. Quarrying 9,804.3 11,545.9 14,112.4 16,654.3 19,095.5 21,718.0 26,562.0 Manufacturing Industry 285,873.9 314,918.4 506,319.6 553,746.6 590,051.3 652,729.5 765,966.7 a. Oil & Gas Manufacturing 35,127.6 54,279.9 63,344.6 69,660.0 78,641.0 86,981.9 133,984.0 b. Non Oil & Gas Manufacturing 250,746.3 260,638.5 442,975.0 484,086.6 511,410.3 565,747.6 631,982.7

Electricity, Gas, & Water Supply 13,429.1 16,519.3 10,854.8 15,392.0 19,540.9 22,855.4 24,993.2 a. Electricity 11,201.4 13,797.1 7,640.8 10,822.5 13,985.7 15,556.8 17,097.4 b. City Gas 353.2 462.1 1,614.8 2,022.3 2,317.5 3,089.3 3,749.8 c. Water Supply 1,874.5 2,260.1 1,599.2 2,547.2 3,237.7 4,209.3 4,146.0 Construction 67,616.2 76,573.4 89,298.9 101,573.5 112,571.3 134,388.1 173,440.6 Trade, Hotel, and Restaurant 175,835.4 199,110.4 267,656.1 314,646.7 337,840.5 372,340.0 426,994.0 Transport & Communication 55,189.6 62,305.6 77,187.6 97,970.3 118,267.3 140,604.2 180,968.7 Financial, Ownership, Business Services 71,220.2 80,459.9 135,369.8 154,442.2 174,323.6 194,542.2 228,107.9 Services 104,955.3 121,871.4 152,258.0 165,602.8 198,069.3 234,244.4 275,640.9 Gross Domestic Product 1,099,731.7 1,264,918.8 1,684,280.5 1,863,274.7 2,045,853.5 2,303,031.5 2,729,708.2 Source: Statistical Year Book of Indonesia, 2000-2005, Indonesian Bureau of Statistics

60

Table 2.5 Gross Domestic Product based on Constant 2000 Market Prices by Industry Origin, 2002-2005

(Billion Rupiah)

2002 2003 2004 2005

Agriculture, Livestock, Forestry, & Fishery 231,613.5 240,387.3 248,222.8 254,391.3

Mining & Quarrying 169,932.0 167,603.8 160,100.4 162,642.0

a. Crude Petroleum & Natural Gas 108,130.6 103,087.2 98,636.3 96,473.4

b. Non Oil & Gas Mining 49,066.5 51,007.3 46,947.1 50,588.6

c. Quarrying 12,734.9 13,509.3 14,517.0 15,580.0

Manufacturing Industry 419,387.8 441,754.9 469,952.4 491,699.5

a. Oil & Gas Manufacturing 52,179.5 52,609.3 51,583.9 48,849.4

b. Non Oil & Gas Manufacturing 367,208.3 389,145.6 418,368.5 442,850.1

Electricity, Gas, & Water Supply 9,868.2 10,349.2 10,889.8 11,596.6

a. Electricity 6,769.1 7,104.1 7,468.5 7,988.3

b. City Gas 1,358.4 1,498.6 1,639.5 1,745.8

c. Water Supply 1,740.7 1,746.5 1,781.8 1,862.5

Construction 84,469.8 89,621.8 96,333.6 103,403.8

Trade, Hotel, and Restaurant 243,266.6 256,516.6 271,104.9 294,396.3

Transport & Communication 76,173.1 85,458.4 96,896.7 109,467.1

Financial, Ownership, Business Services 131,523.0 140,374.4 151,187.8 161,959.6

Services 138,982.4 145,104.9 152,137.3 159,990.7

Gross Domestic Product 1,505,216.4 1,577,171.3 1,656,825.7 1,749,546.9 Source: Statistical Year Book of Indonesia, 2005, Indonesian Bureau of Statistics

61

Table 2.6 Figures of Indonesian Oil & Gas Export and Import, 1990-2005

(million US$)

Year Export Import

1990 11,071.1 1,956.4

1991 10,894.9 2,310.3

1992 10,670.9 2,115.0

1993 9,745.8 2,170.4

1994 9,693.6 2,367.4

1995 10,464.4 2,910.8

1996 11,721.80 3,595.5

1997 11,622.5 3,924.1

1998 7,872.1 2,653.7

1999 9,792.2 3,681.1

2000 14,366.6 6,019.5

2001 12,636.3 5,471.8

2002 12,112.7 6,525.8

2003 13,651.4 7,610.9

2004 15,645.3 11,732.0

2005 19,231.6 17,457.7 Source: Statistical Year Book of Indonesia, 2004, Indonesian Bureau of Statistics

Table 2.7 Investment in Oil and Gas, 1997-2004

(Million US$)

Exploration Development Production Administration Total

1997 1,048 792 2,435 497 4,772

1998 1,080 988 2,303 47 4,418

1999 520 790 2,250 488 4,048

2000 428 583 2,442 478 3,931

2001 425 733 2,615 429 4,202

2002 574 983 3,374 507 5,438

2003 244 1,165 3,458 438 5,305

2004 779 2,097 3,931 685 7,492 Source: Petrominer, No. 09/Sept 15, 2005

62

Table 2.8a Ratio of Electrification and Electricity Consumption per Capita, 2003

PLN Unit/Province Population (x 1000)

Number of Households (x

1000)

Number of Electrified

Households Electrification

Ratio (%) kWh Sold per

Capita

Region of Naggroe Aceh. D 4,097.3 1,003.6 569,988.0 56.8 141.0

Region of North Sumatera 12,093.0 2,819.8 1,868,503.0 66.3 343.2

Region of West Sumatera 4,322.1 1,071.0 648,652.0 60.6 322.9

Region of Riau 5,153.7 1,292.4 450,018.0 34.8 235.0

Region of South Sumatera, Jambi & Bengkulu North Sumatera 11,636.6 2,693.4 1,002,852.0 37.2 163.7 - South Sumatera

7,393.8 1,642.0 633,391.0 38.6 173.4 - Jambi

2,538.4 652.0 201,080.0 30.8 166.3 - Bengkulu

1,704.5 399.4 168,381.0 42.2 118.0 Region of Bangka Belitung

925.0 231.4 127,377.0 55.1 235.7 Regionof Lampung

6,969.5 1,770.8 642,552.0 36.3 159.3 Region of West Kalimantan

4,291.4 1,000.2 418,115.0 41.8 173.7 Region of South & Central Kalimantan 5,134.5 1,407.6 679,752.0 48.3 238.3 - South Kalimantan

3,110.9 853.4 497,687.0 58.3 296.3 - Central Kalimantan

2,023.6 554.2 182,065.0 32.9 149.2 Region of East Kalimantan

2,660.9 699.6 351,926.0 50.3 390.3 Region North, Central Sulawesi & Gorontalo 5,295.0 1,402.3 617,426.0 44.0 159.5 - North Sulawesi

2,078.4 598.9 316,203.0 52.8 236.6 - Gorontalo

872.6 239.1 83,623.0 35.0 110.6 - Central Sulawesi

2,344.1 564.3 217,600.0 38.6 109.3 Region of South & Southeast Sulawesi 10,396.6 2,434.7 1,254,546.0 51.5 192.1 - South Sulawesi

8,402.1 1,966.1 1,093,423.0 55.6 214.2 - South East Sulawesi

1,994.5 468.7 161,123.0 34.4 98.9 Region of Maluku

1,908.1 407.5 189,159.0 46.4 111.4 - Maluku

1,166.1 249.5 126,306.0 50.6 123.6 - North Maluku

742.0 158.0 62,853.0 39.8 92.3 Region of Papua

2,430.6 644.7 161,914.0 25.1 150.3 Distribution of Bali

3,270.9 872.8 569,807.0 65.3 510.6 Region of West Nusa Tenggara 4,224.5 1,131.9 311,073.0 27.5 91.1 Region of East Nusa Tenggara 4,007.5 855.5 188,372.0 22.0 53.5 PT PLN Batam

459.9 141.4 94,721.0 67.0 1,426.7 Total Non Java 89,277.0 21,880.7 10,146,753.0 46.4 223.1 Distribution East Java

35,452.0 10,064.3 5,697,684.0 56.6 405.1 Distribution Central Java

35,250.8 9,406.6 5,317,719.0 56.5 281.1 - Central Java

32,066.7 8,414.4 4,723,057.0 56.1 273.7 - Yogyakarta

3,184.2 992.1 594,662.0 59.9 355.1 Distribution West Java

43,871.0 12,484.7 6,138,618.0 49.2 560.5 - West Java

37,890.1 10,544.5 5,628,781.0 53.4 527.0 - Banten

5,980.9 1,940.2 509,837.0 26.3 773.0 Distribution Jaya & Tangerang

11,301.6 2,726.4 2,696,780.0 98.9 1,916.7 Total Java 125,875.4 34,682.0 19,850,801.0 57.2 560.2

Total Indonesia 215,152.4 56,562.7 2,997,554.0 53.0 420.4 Source: PLN Statistics 2003, PT PLN (Persero)

63

Table 2.8b Ratio of Electrification and Electricity Consumption per Capita, 2004

PLN Unit/Province Population

(x 1000)

Number of Households (x

1000)



Ratio (%) kWh Sold

per Capita Region of Naggroe Aceh. D 4,089.1 1,024.5 602,401 58.80 171.55 Region of North Sumatera 12,123.4 2,861.4 1,929,419 67.43 366.23 Region of West Sumatera 4,535.5 1,079.1 676,977 62.74 323.44 Region of Riau 5,157.4 1,363.7 473,671 34.73 274.34 Region of South Sumatera, Jambi & Bengkulu North Sumatera 10,802.9 2,756.1 1,069,134 38.79 197.41 - South Sumatera 6,628.4 1,678.4 666,454 39.71 215.9 - Jambi 2,625.3 667.0 226,233 33.92 180.59 - Bengkulu 1,549.1 410.6 176,447 42.97 146.84 Region of Bangka Belitung 1,023.8 234.9 127,746 54.39 228.78 Regionof Lampung 7,063.8 1,806.5 638,284 35.33 171.19 Region of West Kalimantan 4,033.2 1,027.8 437,973 42.61 197.57 Region of South & Central Kalimantan

5,097.5 1,444.1 706,915 48.95 243.53 - South Kalimantan 3,226.9 868.5 515,549 59.36 284.49 - Central Kalimantan 1,870.6 575.6 191,366 33.25 172.87 Region of East Kalimantan 2,612.0 691.0 378,435 54.77 470.31 Region North, Central Sulawesi & Gorontalo 5,308.5 1,440.3 648,132 45.00 179.39 - North Sulawesi 2,158.6 611.7 327,095 53.48 256.32 - Gorontalo 897.3 246.0 88,317 35.90 118.13 - Central Sulawesi 2,252.6 582.6 232,720 39.94 130.07 Region of South & Southeast Sulawesi

10,291.8 2,488.8 1,269,812 51.02 209.37 - South Sulawesi 8,369.1 2,001.7 1,105,720 55.24 230.97 - South East Sulawesi 1,922.7 487.1 164,092 33.69 115.36 Region of Maluku 2,116.7 412.4 208,693 50.61 127.45 - Maluku 1,243.9 252.9 136,126 53.83 141.78 - North Maluku 872.8 159.5 72,567 45.50 107.03 Region of Papua 2,516.3 674.5 168,993 25.05 158.23 Distribution of Bali 3,397.3 886.0 587,705 66.33 558.03 Region of West Nusa Tenggara 4,083.7 1,237.6 313,246 25.31 101.72 Region of East Nusa Tenggara 4,155.9 872.3 192,983 22.12 55.19 PT PLN Batam 554.3 138.2 109,112 78.93 1,341.98 PT PLN Tarakan 153.6 30.3 23,662 78.08 685.82 Total Non Java 89,116.7 22,469.5 10,563,293 247.21 Distribution East Java 36,481.8 10,144.4 5,831,893 57.49 450.11 Distribution Central Java 35,766.3 9,497.6 5,552,216 58.46 303.17 - Central Java 32,542.8 8,497.6 4,928,259 58.00 294.96 - Yogyakarta 3,223.5 1,000.6 623,957 62.36 386.04 Distribution West Java 46,239.7 13,364.1 6,360,947 47.60 590.04 - West Java 38,610.9 11,324.1 5,821,886 51.41 563.87 - Banten 7,628.9 2,040.0 539,061 26.42 724.70 Distribution Jaya & Tangerang 10,249.7 2,775.0 2,787,621 100.45 2,292.99 Total Java 128,737.5 35,781.1 20,532,677 57.38 606.4

Total Indonesia 217,854.2 58,250.6 31,095,970 53.38 459.47 Source: PLN Statistics 2004, PT PLN (Persero)

64

Table 2.8c Ratio of Electrification and Electricity Consumption per Capita, 2005

PLN Unit/Province Population (x 1000)

Number of Households

(x 1000)



Ratio (%) kWh Sold

per Capita

Region of Naggroe Aceh. D 4,037.9 1,051.2 606,222 57.67 173.09

Region of North Sumatera 12,326.7 2,923.6 2,002,956 68.51 374.26

Region of West Sumatera 4,595.2 1,093.4 695,167 63.58 343.91

Region of Riau 5,887.7 1,241.8 497,537 40.07 264.2 Region of South Sumatera, Jambi & Bengkulu 11,011.4 2,836.4 1,119,564 39.47 217.73

- South Sumatera 6,755.9 1,725.9 696,620 40.36 240.02

- Jambi 2,657.3 686.1 239,670 34.93 196.87

- Bengkulu 1,598.2 424.4 183,274 43.18 158.14

Region of Bangka Belitung 1,061.0 240.0 127,869 53.28 253.23

Regionof Lampung 7,166.5 1,851.8 696,809 37.63 186.78

Region of West Kalimantan 4,098.5 1,061.5 455,255 42.89 186.78

Region of South & Central Kalimantan 5,144.2 1,490.8 738,413 49.53 205.43

- South Kalimantan 3,240.1 889.5 538,746 60.56 259.27

- Central Kalimantan 1,904.1 601.2 199,667 33.21 303.52

Region of East Kalimantan 2,810.9 749.6 396,049 52.83 183.96 Region North, Central Sulawesi & Gorontalo 5,376.6 1,487.4 679,041 45.65 464.99

- North Sulawesi 2,181.9 628.8 338,586 53.85 189.69

- Gorontalo 909.7 254.4 93,413 36.71 267.93

- Central Sulawesi 2,285.0 604.2 247,042 40.89 128.26

Region of South & Southeast Sulawesi 10,452.4 2,317.2 1,288,909 55.62 139.44

- South Sulawesi 8,493.7 1,808.6 1,119,963 61.93 219.42

- South East Sulawesi 1,958.7 508.6 168,946 33.22 120.5

Region of Maluku 2,145.0 417.5 228,845 54.81 145.17

- Maluku 1,259.4 255.5 147,937 57.89 164.16

- North Maluku 885.6 162.0 80,908 49.95 118.16

Region of Papua 2,518.4 708.9 173,022 24.41 170.56

Distribution of Bali 3,432.1 906.9 607,287 66.97 610.33

Region of West Nusa Tenggara 4,143.5 1,303.1 317,952 24.40 109.07

Region of East Nusa Tenggara 4,218.8 893.2 199,390 22.32 61.28

PT PLN Batam 616.4 142.6 123,692 86.76 1,336.39

PT PLN Tarakan 157.7 31.2 25,529 81.72 749.61

Total Non Java 91,200.5 22,748.1 10,979,508 48.27 260.27 Distribution East Java 36,695.1 10,296.3 5,956,586 57.85 483.21

Distribution Central Java & Yogyakarta 36,194.8 9,658.0 5,724,255 59.27 327.49

- Central Java 32,914.6 8,639.8 5,080,088 58.80 319.65

- Yogyakarta 3,280.2 1,018.2 644,167 63.26 406.13

Distribution West Java & Banten 48,375.7 14,357.6 6,636,034 46.22 597.16

- West Java 39,066.7 11,853.7 6,060,583 51.13 598.17

- Banten 9,309.0 2,503.9 575,451 22.98 592.92

Distribution Jaya & Tangerang 8,860.8 2,454.6 2,878,539 117.27 2,801.42

Total Java 130,126.4 36,766.5 21,195,414 57.65 640.11 Total Indonesia 221,326.9 59,514.6 32,174,922 54.06 483.59

Source: PLN Statistics 2005, PT PLN (Persero)

65

III. ENERGY PRICES IN INDONESIA


ENERGY PRICES

67

Table 3.1 Average of Indonesian Crude Oil Prices, 1998-2005

(US$/Barrel)

Year Months

1998 1999 2000 2001 2002 2003 2004 2005

January 14.51 11.04 24.40 24.41 18.57 31,35 30.97 42.39

February 13.46 10.56 26.08 25.83 18.80 32,04 30.96 44.74

March 12.14 12.07 27.04 25.37 22.39 30,36 33.16 53.00

April 13.20 15.12 24.04 26.83 24.88 27,41 32.89 54.88

May 12.92 15.94 27.65 27.85 25.01 26,51 37.53 48.72

June 12.09 15.95 29.87 27.25 23.87 26,15 36.12 52.92

July 12.51 12.51 29.71 24.72 24.88 26,92 37.10 55.42

August 12.07 12.07 30.08 24.36 25.60 28,46 42.61 61.09

September 12.09 12.09 32.99 24.55 26.85 26,88 44.31 61.36

October 12.93 12.93 32.09 19.59 27.40 29,21 49.21 58.11

November 11.85 11.85 31.14 18.17 26.42 29,48 40.63 53.96

December 9.99 9.99 25.58 17.68 30.22 30,50 35.51 54.64 Sources :

- Indonesia Oil and Gas Statistics 1996-2004, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

- Ministry of Energy and Mineral Resources, www.esdm.go.id

Table 3.2 Average of Selected Crude Oil Prices, 1999-2005

(US$/Barrel)

1999 2000 2001 2002 2003 2004 2005

ICP 17.52 28.47 23.88 24.58 28.77 37 53.43a)

Basket OPEC 17.34 27.55 23.24 24.32 28.02 36.05 50.64

Arabian Light 17.43 26.76 23.18 24.30 27.52 34

Minas 17.69 28.70 24.40 25.51 29.57 36 48.27b)

WTI 19.27 30.36 26.02 26.11 30.90 41.44 56.51

Brent 17.88 28.38 24.59 24.98 28.70 38.23 54.44

Dubai 17.22 26.20 22.02 23.82 26.90 33.66 49.36 a) Estimated b) Estimated from www.eia.doe.gov Sources:

- Oil & Gas Statistics of Indonesia, 1999-2005 Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

- Ministry of Energy and Mineral Resources, www.esdm.go.id - Energy Information and Administration. www.eia.doe.gov

68

Table 3.3a Indonesian Crude Oil Prices by Type, 2003

(US$/Barrel) Months

No Crude Oil Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

1 SLC 31,94 31,41 30,16 28,89 27,83 26,82 27,06 28,03 26,44 29,16 29,64 31,10

2 Arjuna 30,99 32,69 30,63 26,25 25,43 25,78 27,26 29,33 27,77 29,58 29,75 30,20

3 Attaka 31,71 33,47 31,31 26,96 26,11 26,22 27,70 29,86 28,34 30,44 30,18 30,59

4 Cinta 30,69 30,85 29,25 27,51 26,59 25,94 26,23 27,13 25,82 28,20 28,46 29,75

5 Duri 29,91 30,49 28,78 26,06 25,73 25,26 25,58 26,51 24,65 26,66 27,18 28,51

6 Widuri 30,78 30,96 29,28 27,53 26,62 25,93 26,27 27,11 25,80 28,16 28,38 29,75

7 Belida 31,43 33,15 31,19 26,93 25,92 25,68 27,35 29,54 28,23 30,46 30,10 30,35

8 Senipah Cond. 31,40 33,26 31,30 26,80 25,86 25,96 27,26 29,43 28,12 30,14 30,03 30,53

9 Anoa 32,11 33,87 31,71 27,36 26,51 26,62 27,10 30,26 28,74 30,84 30,58 30,99

10 Arun condensate 31,40 33,26 31,30 26,80 25,86 25,96 27,26 29,43 28,12 30,14 30,03 30,53

11 Arimbi 29,84 31,54 29,48 25,10 24,28 24,63 26,11 29,18 26,62 28,43 28,60 29,05

12 Badak 31,71 33,47 31,31 26,96 26,11 26,22 27,70 29,86 28,34 30,44 30,18 30,59

13 Bekapai 31,71 33,47 31,31 26,96 26,11 26,22 27,70 29,86 28,34 30,44 30,18 30,59

14 Bentayan 29,98 29,45 28,20 26,93 25,87 24,86 25,10 26,07 24,48 27,20 27,68 29,14

15 Bontang R.Cond. 31,64 36,69 34,25 23,42 23,27 26,10 27,25 29,22 27,49 30,00 32,00 34,06

16 Bula 29,41 29,99 28,28 25,56 25,23 24,76 25,08 26,01 24,15 26,16 26,68 28,01

17 Bunyu 31,94 31,41 30,16 28,89 27,83 26,82 27,06 28,03 26,44 29,16 29,64 31,10

18 Camar 31,37 33,07 31,01 26,63 25,81 26,16 27,64 29,71 28,15 29,96 30,13 30,58

19 Geragai 32,13 31,60 30,35 29,08 28,02 27,01 27,25 28,22 26,63 29,35 29,83 31,29

20 HandilMix 31,14 32,84 30,78 26,40 25,58 25,93 27,41 29,48 27,92 29,73 29,90 30,35

21 Jambi 32,13 31,60 30,35 29,08 28,02 27,01 27,25 28,22 26,63 29,35 29,83 31,29

22 Jatibarang/Cemara/ Cepu 30,93 30,40 29,15 27,88 26,82 25,81 26,05 27,02 25,43 28,15 28,63 30,09

23 Kaji 32,34 31,81 30,56 29,29 28,23 27,22 27,46 28,43 26,84 29,56 30,04 31,50

24 Kerapu 31,09 32,81 30,85 26,59 25,58 25,34 27,01 29,20 27,89 30,12 29,76 30,01

25 Klamono 29,41 29,99 28,28 25,56 25,23 24,76 25,08 26,01 24,15 26,16 26,68 28,01

26 Komp.P.SIt/ Tap/ Jene Serdang 31,94 31,41 30,16 28,89 27,83 26,82 27,06 28,03 26,44 29,16 29,64 31,10

27 Lalang 31,99 31.46 30,21 28,94 27,88 26,87 27,11 28,08 26,49 29,21 29,69 31,15

28 Langsa 31,31 33.07 30,91 26,56 25,71 25,82 27,30 29,46 27,94 30,04 29,78 30,19

29 Link 31,83 31,30 30,05 28,78 27,72 26,71 26,95 27,92 26,33 29,05 29,53 30,99

30 Madura 31,12 32,82 30,76 26,38 25,56 25,91 27,39 29,46 27,90 29,71 29,88 30,33

31 Mudi 30,69 32,39 30,33 25,95 25,13 25,48 26,96 29,03 27,47 29,28 29,45 29,90

32 NSC/Katapa/Arbei 31,60 33,36 31,20 26,85 26,00 26,11 27,59 29,75 28,23 30,33 30,07 30,48

33 Pagerungan Kond. 30,65 32,51 30,55 26,05 25,11 25,21 26,51 28,68 27,37 29,39 29,28 29,78

34 Pam. Sanga-Sanga Mix 32,04 31,51 30,26 28,99 27,93 26,92 27,16 28,13 26,54 29,26 29,74 31,20

35 Ramba/Tempino 32,13 31,60 30,35 29,08 28,02 27,01 27,25 28,22 26,63 29,35 29,83 31,29

36 Rimau 31,84 31,31 30,06 28,79 27,73 26,72 26,96 27,93 26,34 29,06 29,54 31,00

37 Sangatta 31,94 31,41 30,16 28,89 27,83 26,82 27,06 28,03 26,44 29,16 29,54 31,10

38 Selat Panjang 31,84 31,41 30,16 28,89 27,83 26,82 27,06 28,03 26,44 29,16 29,64 31,10

39 Sembilang 31,74 31,21 29,96 28,69 27,63 26,62 26,86 27,83 26,24 28,96 29,44 30,90

40 Sep. Yak. Mix. 30,99 32,69 30,63 26,25 25,43 25,78 27,26 29,33 27,77 29,58 29,75 30,20

41 Tanjung 32,13 31,60 30,35 29,08 28,02 27,01 27,25 28,22 26,63 29,35 29,83 31,29

42 Walio Mix 31,74 31,21 29,96 28,69 27,63 26,62 26,86 27,83 26,24 28,96 29,44 30,90

Average 31,35 32,04 30,36 27,41 26,51 26,15 26,92 28,46 26,88 29,21 29,48 30,50

Source : Indonesia Oil and Gas Statistics, 2003, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

69

Table 3.3b Indonesian Crude Oil Prices by Type, 2004

(US$/Barrel) Months


1 SLC 30.16 29.36 32.28 32.12 37.09 36.30 36.28 41.42 43.56 49.04 37.36 33.99

2 Arjuna 31.95 33.33 34.79 34.40 38.67 36.92 28.74 43.58 44.91 50.53 44.98 37.32

3 Attaka 32.49 33.73 35.48 35.10 39.37 37.61 40.04 46.43 47.81 52.53 46.91 38.88

4 Cinta 29.20 28.63 31.49 31.53 36.13 34.97 35.58 40.69 42.31 47.35 36.48 33.06

5 Duri 28.24 27.42 28.78 28.37 33.58 30.37 30.74 37.39 39.52 39.56 30.81 30.16

6 Widuri 29.25 28.65 31.52 31.53 36.18 35.00 35.58 40.68 42.32 47.39 36.60 33.10

7 Belida 32.22 33.45 35.14 34.75 38.90 37.25 39.75 46.11 47.10 52.06 46.35 38.52

8 Senipah Cond. 32.48 33.74 35.16 34.62 38.93 37.40 39.39 45.43 46.72 51.49 45.96 38.08

9 Anoa 32.89 34.13 35.88 35.41 39.77 38.01 40.44 46.83 48.21 52.93 47.31 39.28

10 Arun condensate 32.48 33.74 35.16 34.62 38.93 37.40 39.39 45.43 46.72 51.49 45.96 38.08

11 Arirnbi 30.80 32.18 33.64 33.25 37.52 35.77 37.59 42.43 43.76 49.38 43.83 36.17

12 Badak 32.49 33.73 35.48 35.01 39.37 37.61 40.04 46.43 47.81 52.53 46.91 38.88

13 Bekapai 32.49 33.73 35.48 35.01 39.37 37.61 40.04 46.43 47.81 52.53 46.91 38.88

14 Bentayan 28.20 27.40 30.32 30.16 35.13 34.34 34.32 39.46 41.60 47.08 35.40 32.03

15 Bontang R. Cond. 39.12 33.71 35.50 36.09 39.22 37.14 37.75 43.67 43.50 48.49 46.95 42.33

16 Bula 27.84 26.92 28.28 27.87 33.08 29.87 30.24 36.89 39.02 39.06 30.31 29.66

17 Bunyu 30.16 29.36 32.28 32.12 37.09 36.30 36.28 41.42 43.56 49.04 37.36 33.99

18 Camar 32.33 33.71 35.17 34.78 39.05 37.30 39.12 43.96 45.29 50.91 45.36 37.70

19 Geragai 30.35 29.55 32.47 32.31 37.28 36.49 36.47 41.61 43.75 49.23 37.55 34.18

20 Handil Mix 32.10 33.48 34.94 34.55 38.82 37.07 38.89 43.73 45.06 50.68 45.13 37.47

21 Jambi 30.35 29.55 32.47 32.31 37.28 36.49 36.47 41.61 43.75 49.23 37.55 34.18

22 Jatibarang/Cemara/ Cepu 29.15 28.35 31.27 31.11 36.08 35.29 35.27 40.41 42.55 48.03 36.35 32.98

23 Kaji 30.56 29.76 32.68 32.52 37.49 36.70 36.68 41.82 43.96 49.44 37.76 34.39

24 Kerapu 31.88 33.11 34.80 34.41 38.56 36.91 39.41 45.77 46.76 51.72 46.01 38.18

25 Klamono 27.84 26.92 28.28 27.87 33.08 29.87 30.24 36.89 39.02 39.06 30.31 29.66

26 Komp.P.SIt/Tap/ Jene/ Serdang 30.16 29.36 32.28 32.12 37.09 36.30 36.28 41.42 43.56 49.04 37.36 33.99

27 Lalang 31.21 29.41 32.33 32.17 37.14 36.35 36.33 41.47 43.61 49.09 37.41 34.04

28 Langsa 32.09 33.33 35.08 34.61 38.97 37.21 39.64 46.03 47.41 52.13 46.51 38.48

29 Lirik 30.05 29.25 32.17 32.01 36.98 36.19 36.17 41.31 43.45 48.93 37.25 33.88

30 Madura 32.08 33.46 34.92 34.53 38.80 37.05 38.87 43.71 45.04 50.66 45.11 37.45

31 Mudi 31.65 33.03 34.49 34.10 38.37 36.62 38.44 43.28 44.61 50.23 44.68 37.02

32 NSC/Katapa Arbei 32.38 33.62 35.37 34.90 39.26 37.50 39.93 46.32 47.70 52.42 46.80 38.77

33 Pagerungan Kond. 31.73 32.99 34.41 33.87 38.18 36.65 38.64 44.68 45.97 50.74 45.21 37.33

34 Pam. Sanga-Sanga Mix 30.26 29.46 32.38 32.22 37.19 36.40 36.38 41.52 43.66 49.14 37.46 34.09

35 Ramba/Tempino 30.35 29.55 32.47 32.31 37.28 36.49 36.47 41.61 43.75 49.23 37.55 34.18

36 Rimau 30.06 29.26 32.18 32.02 36.99 36.20 36.18 41.32 43.46 48.94 37.26 33.89

37 Sanggata 30.16 29.36 32.28 32.12 37.09 36.30 36.28 41.42 43.56 49.04 37.36 33.99

38 Selat Panjang 30.16 29.36 32.28 32.12 37.09 36.30 36.28 41.42 43.56 49.04 37.36 33.99

39 Sembilang 29.96 29.16 32.08 31.92 36.89 36.10 36.08 41.22 43.36 48.84 37.16 33.79

40 Sep. Yak. Mix. 31.95 33.33 34.79 34.40 38.67 36.92 38.74 43.58 44.91 50.53 44.98 37.32

41 Tanjung 30.35 29.55 32.47 32.31 37.28 36.49 36.47 41.61 43.75 49.23 37.55 34.18

42 Walio Mix 29.96 29.16 32.08 31.92 36.89 36.10 36.08 41.22 43.36 48.84 37.16 33.79

Average 30.97 30.96 33.16 32.89 37.53 36.12 37.10 42.61 44.31 49.21 40.63 35.51

Source: Indonesia Oil and Gas Statistics, 2004, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

70

Table 3.3c Indonesian Crude Oil Prices by Type, 2005

(US$/Barrel) Months


1 SLC 41.48 44.13 53.29 55.22 49.50 53.60 55.11 60.35 60.36 57.10 52.80 62.74

2 Arjuna 43.78 46.94 54.21 56.24 49.68 54.12 57.60 63.24 62.76 60.05 55.51 56.72

3 Attaka 45.36 48.46 55.56 57.02 50.18 54.98 58.89 65.58 67.08 62.30 66.48 58.18

4 Cinta 40.23 42.10 51.67 51.92 48.66 51.37 52.44 57.24 58.06 54.93 60.97 52.11

5 Duri 38.51 38.36 43.52 47.89 41.40 46.28 49.03 53.25 53.66 50.55 48.81 48.22

6 Widuri 40.27 42.18 51.76 54.08 48.70 51.52 52.47 57.24 58.00 54.79 51.02 52.29

7 Belida 44.94 48.15 55.74 55.98 49.94 54.46 58.48 65.24 66.76 62.16 58.55 58.07

8 Senipah Condensate 43.95 46.94 54.49 54.90 48.42 52.61 55.58 62.58 64.56 59.88 55.11 56.46

9 Anoa 45.76 48.88 55.98 67.42 50.58 55.38 59.29 65.98 67.49 62.70 56.88 58.58

10 Arun Condensate 43.95 46.94 54.49 54.90 48.42 52.61 55.58 62.58 64.56 59.88 55.11 56.46

11 Arimbi 42.63 48.79 53.06 55.09 48.53 52.97 56.45 62.09 61.61 58.90 54.46 55.57

12 Badak 45.38 48.46 55.56 57.02 50.18 54.98 58.89 65.58 67.09 62.30 54.48 68.18

13 Bekapal 45.35 48.46 55.56 57.02 50.18 54.98 58.89 65.58 67.09 62.30 56.48 58.18

14 Bentayan 39.98 42.17 51.33 53.26 47.54 51.64 53.15 59.39 58.40 55.14 50.64 51.78

15 Bontang R. Cond. 40.61 43.69 50.06 49.51 44.44 45.36 49.07 67.07 61.65 57.55 53.26 63.12

16 Bula 38.01 34.86 43.02 47.19 40.90 45.78 48.53 52.75 53.16 50.05 45.11 47.72

17 Bunyu 41.94 44.13 63.29 65.22 49.50 53.60 55.11 60.35 60.36 57.10 52.60 53.74

18 Camar 44.16 47.32 54.69 56.62 50.08 54.50 57.98 63.62 63.14 60.43 55.99 57.10

19 Cepu 40.93 43.12 52.28 54.21 48.49 42.59 54.10 59.34 59.35 56.09 51.89 62.73

20 Geragal 42.13 44.32 53.48 55.41 49.69 53.79 55.30 60.54 60.55 57.29 52.79 53.93

21 Handil mix 43.93 47.09 54.36 56.39 49.83 54.27 57.75 63.39 62.91 60.20 55.76 56.87

22 Jambi 42.18 44.32 53.48 55.41 49.69 53.79 55.30 60.54 60.55 57.29 52.72 33.93

23 Jatibarang 41.94 44.13 53.29 55.22 49.50 53.60 55.11 60.35 60.36 57.10 52.60 53.74

24 Kaji 42.34 44.53 53.69 55.52 49.80 54.00 55.51 60.75 60.76 57.50 53.00 54.14

25 Kerapu 44.60 47.81 55.40 55.55 49.60 54.12 58.14 64.90 66.42 61.82 56.21 57.73

26 Klamono 38.01 34.88 43.02 47.19 40.90 45.78 48.53 52.75 53.18 50.05 46.11 47.72

27 Komp.PLB.SLT/TAP/ Jene/Serdang 41.94 44.13 53.29 55.22 49.50 53.60 55.11 60.35 60.36 57.10 52.60 53.74

28 lalang 41.99 44.18 53.34 55.27 49.55 53.65 55.16 60.40 60.41 57.15 52.65 53.79

29 Langsa 44.95 48.06 55.16 56.82 49.78 54.58 58.49 55.18 55.89 61.90 56.08 57.78

30 Lirik 41.83 44.02 53.18 55.11 49.39 53.49 55.00 60.24 60.25 58.99 52.49 53.63

31 Madura 43.91 47.07 54.34 56.37 49.81 54.25 57.73 63.37 62.89 60.18 56.74 56.85

32 Mudi 43.48 46.64 63.19 55.94 49.38 53.82 57.30 62.94 62.46 59.75 55.31 56.42

33 NSC/Katapa/Arbai 45.25 48.35 55.45 58.91 50.07 54.87 58.78 65.47 66.98 62.19 56.37 58.07

34 Pagerungan Cond. 43.20 46.19 53.74 54.15 47.67 51.86 54.83 61.83 63.81 59.13 54.38 55.71

35 Pam. sanga2 Mix 42.04 44.23 53.39 55.32 49.60 53.70 55.21 60.45 60.46 57.20 52.70 53.84

36 Ramba/Tempina 42.13 44.32 53.48 55.41 49.69 43.79 55.30 60.54 60.55 57.29 52.79 53.93

37 Rimau/Taruhan 41.84 44.03 53.19 55.12 49.40 53.50 55.01 60.25 60.26 57.00 52.60 53.64

38 Sangatta 41.94 44.13 23.29 55.22 46.50 53.60 55.11 60.35 60.36 57.10 52.60 53.74

39 Selat Panjang 41.94 44.13 53.29 55.22 49.50 53.60 55.11 60.35 60.36 57.10 52.60 53.74

40 Sembilang 41.74 43.93 53.09 55.02 46.30 53.40 54.91 60.15 60.16 56.90 52.40 53.54

41 Sep. Yakin Mix 43.78 46.94 54.21 56.24 49.68 54.12 57.60 63.24 62.76 60.05 55.61 56.72

42 Tanjung 42.13 44.32 53.48 55.41 46.69 53.79 55.30 60.54 60.55 57.29 52.79 53.93

43 Walio Mix 41.74 43.93 53.09 55.02 46.30 53.40 54.91 60.16 60.16 56.90 52.40 53.54

Average 42.39 44.74 53.00 54.88 48.72 52.92 55.42 61.09 61.36 58.11 53.96 54.64

Source: Ministry of Energy and Mineral Resources, www.esdm.go.id

71

Table 3.4 Domestic Fuel Prices, 2003-April 2006

(Rupiah/Liter)

Since Avgas Avtur Pertamax Plus Pertamax Premium Kerosene ADO IDO Fuel

Oil

700 Subsidies Prices 02.01.03 n.a n.a 2600 2300 1810

1970 1890 1860 1560

Market Prices


1800 1650 1650 1560

Market Prices


1800 1650 1650 1560

Market Prices

1810 1800 1650 1650 1560 Subsidies Prices 01.01.04 - - 2600 2300

2100 2200 2100 2050 1560 Market Prices


2100 2200 2100 2050 1560 Market Prices


2100 2200 2100 2050 1560 Market Prices


2100 2200 2100 2050 1560 Market Prices


2100 2200 2100 2050 1590 Market Prices

1810 1800 1650 1650 1560 Subsidies Prices 01.06.04 5,808 3,014 2750 2450

2100 2200 2100 2050 1600 Market Prices


2100 2200 2100 2050 1600 Market Prices


2100 2200 2100 2050 1600 Market Prices


2100 2200 2100 2050 1600 Market Prices


2100 2200 2100 2050 1600 Market Prices


2100 2200 2100 2050 1600 Market Prices

1810 1800 1650 1650 1560 Subsidies Prices 01.12.04 * * 2750 2450

2100 2200 2100 2050 1600 Market Prices


2100 2200 2100 2050 1600 Market Prices


2100 2200 2100 2050 1600 Market Prices


2100 2200 2100 2050 1600 Market Prices


2870 2790 2700 2660 2300 Market Prices

72

Table 3.4 Domestic Fuel Prices, 2003-April 2006 (Continued)

(Rupiah/Liter)

Since Avgas Avtur Pertamax Plus Pertamax Premium Kerosene ADO IDO Fuel

Oil


2870 2790 2700 2660 2300 Market Prices


2870 2790 2700 2660 2360 Market Prices


4060 4940 4740 4560 2900 Market Prices


4640 5490 5480 5240 3150 Market Prices


5160 5600 5350 5130 3150 Market Prices

4500a) 2000a) 4300a) - - Subsidies Prices 01.10.05 * * 5900 5700

5160 5600 5350 5130 3150 Market Prices


6290 6400 6000 5780 3810 Market Prices


5890 6480 6170 5940 3870 Market Prices


5890 6480 6170 5940 3870 Market Prices


5150 6480 5340 5180 3680 Market Prices

4500a) 2000a) 4300a) - - Subsidies Prices

5180b) 5020b) 3640b) 01.01.06 * * n.a n.a 4780 5320

4950c) 4810c) 3480c) Market Prices


5440b) 3640 01.02.06 * * n.a n.a 4930 5740

5200c) 5020

Market Prices


5273.19b) 3603.83 01.03.06 * * n.a n.a 4898.69 5747.96

5043.92c) 4900.4

Market Prices


5362.31b) 3672.74 01.04.06 * * n.a n.a 5098.57 5507.06

5129.16c) 4983.1

Market Prices

* not single price a) Premium, Kerosene and ADO Prices based on Perpres No. 55/2005 b) Transportation c) Industry Sources :

- Patra Propen Volume XXXI-February 2002 - Indonesia Oil and Gas Statistics 2001-2002, Directorate General of Oil and Gas. Ministry of Energy and

Mineral Resources - Ministry of Energy and Mineral Resources, www.esdm.go.id - PT Pertamina (Persero), www.pertamina.com

73

Table 3.5a Domestic Avgas Selling Prices, 2005

(Rupiah per Liter)

No Location/Airport Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

1 Polonia 9,328 9,350 10,461 11,748 12,309 11,451 12,045 13,156 14,025 16,511 14,641 13,002

2 S. M. Badarudin II 8,624 8,635 9,746 11,022 11,572 10,714 11,308 12,397 13,266 15,719 13,849 12,232

3 Halim PK 9,537 9,548 10,659 11,957 12,518 11,660 12,254 13,376 14,245 16,742 14,861 13,222

4 Achmad Yani 8,822 8,833 9,955 11,231 11,781 10,923 11,517 12,617 13,486 15,950 14,069 12,452

5 Juanda 8,624 8,635 9,746 11,022 11,572 10,714 11,308 12,397 13,266 15,719 13,849 12,232

6 Iswahyudi 8,921 8,932 10,054 11,330 11,880 11,033 11,627 12,727 13,596 16,060 14,190 12,562

7 Ngurah Rai 9,328 9,350 10,461 11,748 12,309 11,451 12,045 13,156 14,025 16,511 14,641 13,002

8 Eltari 9,537 9,548 10,659 11,957 12,518 11,660 12,254 13,376 14,245 16,742 13,739 13,222

9 Instalasi Surabaya Group 8,525 8,525 9,647 10,923 11,462 10,604 11,198 12,298 13,156 15,609 14,410 12,111

10 Supadio 9,130 9,141 10,252 11,539 12,100 11,242 11,836 12,936 13,816 16,291 14,410 12,782

11 Depot Pontianak 9,130 9,141 10,252 11,539 12,100 11,242 11,308 12,936 13,816 16,291 13,849 12,782

12 Sepinggan 8,624 8,635 9,746 11,022 11,572 10,714 11,627 12,397 13,266 15,719 14,190 12,232

13 Syamsuddin Noor 8,921 8,932 10,054 11,330 11,880 11,033 12,045 12,727 13,596 16,060 14,641 12,562

14 Juwata 9,328 9,350 10,461 11,748 12,309 11,451 11,836 13,156 14,025 16,511 14,410 13,002

15 Termindung 9,130 9,141 10,252 11,539 12,100 11,242 11,836 12,936 13,816 16,291 13,739 12,782

16 Depot Balikpapan 8,525 8,525 9,647 10,923 11,462 10,604 11,198 12,298 13,156 15,609 13,959 12,111

17 Instalasi Makassar 8,723 8,734 9,845 11,121 11,671 10,813 11,407 12,507 13,376 15,840 14,861 12,342

18 Depot Jayapura 9,537 9,548 10,659 11,957 12,518 11,660 12,254 12,376 14,245 16,742 15,081 13,222

19 Depot Manokwari 9,735 9,757 10,868 12,155 12,727 11,869 12,474 13,585 14,456 16,973 16,973 13,442 Tax included Source: www.pertamina.com

74

Table 3.5b International Avgas Selling Prices, 2005

(US$ Cent per Liter)

No LocationAirport Jan Feb Mar* Apr* May* Jun* Jul Aug Sep Oct Nov Dec

1 Polonia 92.08 91.39 112.83 125.114 128.799 119.658 113.75 121.75 128.82 145.50 130.26 117.20

2 S. M. Badarudin II 85.08 84.39 105.13 117.414 121.099 111.958 106.75 114.75 121.82 138.50 123.26 110.20

3 Halim PK 94.08 93.39 115.03 127.314 130.999 121.858 115.75 123.75 130.82 147.50 132.26 119.20

4 Achmad Yani 87.08 86.39 107.33 119.614 123.299 114.158 108.75 116.75 123.82 140.50 125.26 112.20

5 Juanda 85.08 84.39 105.13 117.414 121.099 111.958 106.75 114.75 121.82 138.50 123.26 110.20

6 Iswahyudi 88.08 87.39 108.43 120.714 124.399 115.258 109.75 117.75 124.82 141.50 126.26 113.20

7 Ngurah Rai 92.08 91.39 112.83 125.114 128.799 119.658 113.75 121.75 128.82 145.50 130.26 117.20

8 Eltari 94.08 93.39 115.03 127.314 130.999 121.858 115.75 123.75 130.82 147.50 132.26 119.20

9 Instalasi Surabaya Group 84.08 83.39 104.03 116.314 119.999 110.858 105.75 113.75 120.82 137.50 122.26 109.20

10 Supadio 90.08 89.39 110.63 122.914 126.599 117.458 111.75 119.75 126.82 143.50 128.26 115.20

11 Depot Pontianak 90.08 89.39 110.63 112.914 126.599 117.458 106.75 119.75 126.82 143.50 128.26 115.20

12 Sepinggan 85.08 84.39 105.13 117.414 121.099 111.958 109.75 114.75 121.82 138.50 123.26 110.20

13 Syamsuddin Noor 88.08 87.39 108.43 120.714 124.399 115.258 113.75 117.75 124.82 141.50 126.26 113.20

14 Juwata 92.08 91.39 112.83 125.114 128.799 119.658 111.75 121.75 128.82 145.50 130.26 117.20

15 Termindung 90.08 89.39 110.63 122.914 126.599 117.458 111.75 119.75 126.82 143.50 128.26 115.20

16 Depot Balikpapan 84.08 83.39 104.03 116.314 119.999 110.858 105.75 113.75 120.82 137.50 122.26 109.20

17 Instalasi Makassar 86.08 85.39 106.23 118.514 122.199 113.058 107.75 115.75 122.82 138.50 124.26 111.20

18 Depot Jayapura 94.08 93.39 115.03 127.314 130.999 121.858 115.75 123.75 130.82 147.50 132.26 119.20

19 Depot Manokwari 96.08 95.39 117.23 129.514 133.199 124.658 117.75 125.75 132.82 149.50 134.26 121.20 * Tax included Source: www.pertamina.com

75

Table 3.6a Pertamina Domestic Avtur Selling Prices, 2005

(Rupiah per Liter)

No Location Airport Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

1 Region 1 Polonia, Sultan Iskandar Muda, Tabing, Simpang Tiga, Ranai 3,960 3,465 3,707 4,510 4,950 4,609 4,752 5,038 5,379 6,149 6,028 5,247

Pinang Kampai 3,520 3,432 3,674 4,488 4,917 4,576 4,719 5,005 4,346 6,545 6,424 5,775

Hang nadim 3,230 3,150 3,370 4,100 4,500 4,190 4,320 4,580 4,890 5,590 5,480 4,770

2 Region 2 Pangkal Pinang, Sultan Thaha, Padang Kemiling 3,564 1,476 3,380 4,521 4,961 4,620 4,763 5,049 5,390 6,149 5,480

SMB II 3,520 3,432 3,340 4,488 4,917 4,576 4,719 5,005 5,346 6,545 6,424 5,269

3 Region 3 Halim PK, Husien Sastranegara, Pondok Cabe 3,586 3,498 3,400 4,543 4,983 4,631 4,785 5,071 5,412 6,094 5,973 5,775

Soekarno Hatta 3,531 3,432 3,320 4,488 4,928 4,576 4,719 5,016 5,357 6,545 5,973 5,214

4 Region 4 Ahmad Yani, Adi Sucipto, Adi Sumarmo 3,553 3,465 3,370 4,510 4,950 4,609 4,752 5,038 5,379 6,314 6,424 5,214

Tunggul Wulung 3,553 3,465 3,370 4,510 4,950 4,609 4,752 5,038 5,379 6,545 6,204 5,775

5 Region 5 Sumbawa Besar, M Salahudin, Mau Hau, Wai Oti, Eltari, Selaparang, H Aroeboesman

3,608 3,509 3,410 4,565 5,005 4,653 5,016 5,313 5,742 6,776 6,644 5,324

Iswahyudi 3,608 3,509 3,410 4,565 5,005 4,653 5,016 5,313 5,742 6,776 5,973 5,775

Ngurah Rai 3,542 3,454 3,360 4,499 4,939 4,598 4,741 5,027 5,368 6,094 5,973 5,214

Juanda 3,553 3,465 3,370 4,510 4,950 4,609 4,752 5,038 5,379 6,094 6,204 5,214

6 Region 6 Syamsuddin Noor, Supadio, Juwata, Tjilik Riwut, Temindung, Iskandar 3,597 3,498 3,410 4,554 4,994 4,642 4,796 5,082 5,423 6,314 5,904 5,346

Sepinggan 3,520 3,432 3,340 4,499 4,917 4,576 4,719 5,005 5,346 6,094 5,973 5,214

7 Region 7 Hasanuddin, Mutiara, Lalos, Bubung, Jlaludin, Sam Ratulangi, Wolter Mongisidi 3,608 3,509 3,410 4,565 5,005 4,653 4,807 5,093 5,434 6,149 6,182 5,379

8 Region 8 Sentani, Rendani, Mopah, Frans kaiseipo, Paniai, Dumatubun, Pattimura, Babullah, Sorong Daratan, Utarom

3,630 3,531 3,430 4,587 5,027 4,675 5,016 5,313 5,786 6,435 6,314 5,544

9 All Depot Non DPPU 6,776 6,644 5,775

Tax included Source: www.pertamina.com

76

Table 3.6b International Avtur Selling Prices, 2005

(US$ Cent per Liter)

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

International Avtur Retail Price 37.55 39.32 38.79 46.18 49.60 46.21 46.21

Tax 10% (Exept Batam) 39.95 42.67 50.80 54.56 50.83

Regional 1-4 & Reg.6 47.32 49.12 51.37 54.63 54.15 46.98

Region 5 49.32 51.12 53.37 56.63 56.15 48.98

Region 7 48.32 50.12 52.37 55.63 55.15 47.98

Region 8 50.32 52.12 52.37 37.63 57.15 49.98

Ngurah Rai 47.32 49.12 52.37 54.63 54.15 47.18

1

Juanda 47.32 49.12 52.37 54.63 54.15 46.98

Sukarno Hatta Retail Price 38.49 45.88 49.30 47.28 2

Tax 10% 42.34 50.47 54.23 Source: www.pertamina.com

77

Table 3.7 Fuel Oil Subsidy, 1995-2005

(Billion Rupiah)

Year Oil Subsidy

1995/1996 0

1996/1997 1,416.10

1997/1998 9,814.20

1998/1999 27,534.0 (a)

1999/2000 37,572.7 (b)

2000 53,635.2 (c)

2001 68,380.8 (d)

2002 31,161.70

2003 30,037.90

2004 72,884.22

2005 99,487.66 Note : (a) : include oil subsidy deficit fiscal year 1997/1998 (b) : include oil subsidy deficit fiscal year 1999/1999 (c) : include oil subsidy deficit fiscal year 1999/2000 (d) : include oil subsidy deficit fiscal year 2000 Sources :

- Oil and Gas Data Information, 6th Ed., 2002, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

- Indonesia Oil and Gas Statistics 2003, Directorate General Oil and Gas, Ministry of Energy and Mineral Resources

- Directorat General Oil and Gas, Ministry of Energy and Mineral Resources

Table 3.8 Gas Domestic Prices, Jan 2006

US$/MMBTU Gas Prices

FUEL

Electricity 2.1 - 2.9

Industry 3

Refinery 1.7 - 2

FEEDSTOCK

Fertilizer 1.5 - 2.75

Methanol Plant 1.42 - 2

DISTRIBUTION 2.16-3 Source: Directorate General Oil and Gas, Ministry of Energy and Mineral Resources (Processed)

78

Table 3.9a International Coal Price Trend

40.85 39.85 38.936.35

34.35

40.3 40.337.65

34.5

29.95 28.75

34.5

28.7526.75

45

53

0

10

20

30

40

50

60

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Coa

l Pric

e (U

S$/to

n)

For 6700 Kcal/kg (GAD-Gross Air Dried) Source : Barlow-Jonker

Table 3.9b Indonesian Coal Export Price Trend

38.53 38.06 37.1534.72

32.81

38.49 38.4935.96

32.28

27.94 26.6828.90

27.02 25.80

42.97

50.40

0

10

20

30

40

50

60

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Coa

l Pric

e (U

S$/to

n)

For 6300 Kcal/kg (GAD-Gross Air Dried) Source : Ditjen MinerbaPabum, 2005

79

Table 3.10 Averaged Generation Cost of PLN Power Plants, 1993-2005

(Rupiah/kWh)

Year Hydro Power

Plant

Steam Power

Plant

Diesel Power

Plant

Gas Power Plant

Geothermal Power

Plant

Gas-Steam Power

Plant Average

1993/1994 16.01 59.29 151.35 170.06 61.86 103.36 73.03

1994 18.82 53.17 155.46 78.88 62.49 83.39 67.14

1995 20.13 55.87 157.05 131.52 83.44 69.76 74.82

1996 17.19 56.80 156.11 179.94 96.16 69.49 68.37

1997 18.39 69.47 186.16 253.11 120.48 95.73 87.43

1998 20.03 106.93 211.50 247.91 257.50 233.02 152.20

1999 29.55 116.08 221.36 224.38 275.26 192.63 146.79

2000 32.61 109.79 231.92 324.29 262.00 204.51 148.33

2001 36.31 149.09 408.15 592.06 319.95 265.36 203.71

2002 208.53 236.73 849.60 875.02 368.90 316.32 329.74

2003 128.81 265.47 701.89 791.29 400.42 362.88 339.29

2004 123.26 273.46 673.34 862.66 415.62 370.27 351.34

2005 114.71 316.72 925.18 953.79 514.70 560.78 469.78 2000: not included maintenance cost Source: PLN Statistics, 1993-2005, PT PLN (Persero)

Table 3.11 Averaged Selling Price of Electricity by Type of Customer, 1992-2005

(Rupiah/kWh)

Year Residential Industrial Business Social Government

Office Building

Public Street

Lighting

1992 128.85 122.83 237.81 106.88 180.93 131.42

1993 144.53 135.35 253.56 119.21 208.36 153.52

1994 146.57 137.75 255.49 122.78 214.25 154.25

1995 156.83 144.79 264.00 128.16 224.73 167.70

1996 158.91 146.16 266.04 130.60 225.63 169.05

1997 161.65 149.70 270.35 130.34 232.07 172.82

1998 184.40 201.01 305.83 193.32 294.02 238.97

1999 193.80 208.56 313.47 215.29 316.61 266.07

2000 207.34 302.52 380.51 231.50 491.93 439.08

2001 253.65 361.67 451.91 272.47 596.68 484.17

2002 392.79 442.94 592.77 421.28 692.33 515.37

2003 522.48 530.32 661.41 538.09 725.90 594.98

2004 557.76 559.15 682.32 568.65 712.47 638.99

2005 563.05 569.87 694.71 569.90 730.32 628.72 Source: PLN Statistics, 2004-2005, PT PLN (Persero)

80

Table 3.12 Price of Fuels for Electricity, 1992-2005

Oil (Rp/Liter)*) Year

HSD IDO MFO Average

Coal (Rp/Ton)

Natural Gas (Rp/MMSCF)

Geothermal (Rp/kWh)

1992 360.56 317.78 240.97 306.44 65.24 6,392.61 49.28

1993 384.59 376.83 255.30 338.91 68.66 4,951.88 69.02

1994 386.99 368.66 258.25 337.97 70.34 5,578.41 90.15

1995 401.86 372.23 257.45 343.85 72.91 6,288.19 90.15

1996 399.24 417.08 256.82 357.71 69.41 6,878.80 108.88

1997 388.07 371.65 256.82 338.85 60.02 6,874.79 99.12

1998 430.66 457.33 328.85 405.61 74.88 26,414.80 253.99

1999 553.59 509.21 378.27 480.36 140.73 21,065.44 246.19

2000 593.35 538.39 382.15 504.63 153.79 21,787.67 221.56

2001 878.52 797.01 654.72 776.75 199.60 26,073.78 269.54

2002 1,406.79 1,331.77 1,127.05 1,288.54 219.75 23,496.92 310.36

2003 1,740.91 1,705.10 1,595.15 1,680.39 230.82 21,550.40 316.28

2004 1,829.11 1,694.11 1,697.70 1,740.31 230.75 21,258.05 297.39

2005 2,819.15 2,485.99 2,418.19 2,574.44 251.55 25,323.76 461.70**) *) including the transportation cost **) Refer to Indonesia Power fuesl price Source: PLN Statistics, 2004-2005, PT PLN (Persero)

81

IV. ENERGY RESERVES AND POTENTIALS OF INDONESIA


ENERGY RESERVES AND POTENTIALS

83

Table 4.1 Oil and Gas Reserves, 1995-2005

Oil Gas

(Billion Barrel Oil) (Trillion Cubic Feet) Year

Proven Potential Total Proven Potential Total

1995 4.98 4.12 9.10 72.26 51.31 123.57

1996 4.73 4.25 8.98 77.19 58.73 135.92

1997 4.87 4.22 9.09 76.17 61.62 137.79

1998 5.10 4.59 9.69 77.06 59.39 136.45

1999 5.20 4.62 9.82 92.48 65.78 158.26

2000 5.12 4.49 9.61 94.75 75.56 170.31

2001 5.10 4.66 9.75 92.10 76.05 168.15

2002 4.72 5.03 9.70 90.30 86.29 176.59

2003 4.73 4.40 9.13 91.17 86.96 178.13

2004 4.30 4.31 8.61 97.81 90.53 188.34

2005 4.19 4.44 8.63 97.26 88.54 185.80

Sources :

- Data, Information Oil and Gas 6th Ed., 2002, (pages : 34), Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

- Oil and Gas Statistics of Indonesia 1999-2003, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

- Oil and Gas Statistics of Indonesia 2000-2004, Directorate of Oil and Gas Ministry of Energy and Mineral Resources

- Directorate of Oil and Gas Ministry of Energy and Mineral Resources

84

Table 4.2 Coal Reserves by Province, 2005

Quality Resource (million Ton)

No Province Class

Criteria (Cal/gr,

adb) Hypothetic Inferred Indicated Measured Total

Reserve (million

Ton)

Medium Calories

5100-6100 5.47 2.78 0.00 2.09 10.34 0.00

High Calories

6100 - 7100 0.00 2.97 0.00 0.00 2.97 0.00 1 Banten

5.47 5.75 0.00 2.09 1,331.00 0.00 Low Calories <5100 0.00 0.82 0.00 0.00 0.82 0.00 2 Central 0.00 0.82 0.00 0.00 0.82 0.00 Medium Calories

5100-6100 0.00 0.08 0.00 0.00 0.08 0.00 3 East java

0.00 0.08 0.00 0.00 0.08 0.00 Low Calories <5100 0.00 20.92 6.70 64.14 91.76 0.00

Medium Calories

5100-6100 0.00 325.43 6.70 26.26 358.39 0.00 4

Nangroe Aceh Darussalam

0.00 346.35 13.40 90.40 450.15 0.00 Low Calories <5100 0.00 0.00 0.00 19.97 19.97 0.00

Medium Calories

5100-6100 0.00 7.00 0.00 0.00 7.00 0.00 5 North

Sumatra

0.00 7.00 0.00 19.97 26.97 0.00 Low Calories <5100 0.00 1,345.69 0.00 268.06 1,613.75 0.00

Medium Calories

5100 - 6100 0.00 30.62 0.00 51.57 82.19 0.00

High Calories

6100 - 7100 12.79 359.60 0.00 16.99 389.38 16.54

6 Riau

12.79 1,735.91 0.00 336.62 2,085.32 16.54 Medium Calories

5100-6100 19.19 284.36 42.72 22.97 369.24 2.83

High Calories

6100-7100 5.76 164.58 0.00 144.20 314.60 19.24

Very High Calories

>7100 0.00 27.00 0.00 14.00 41.00 14.00

7 West Sumatra

24.95 475.94 42.72 181.20 7,243.00 36.07 Low Calories <5100 0.00 51.13 0.00 0.00 51.10 0.00

Medium Calories

5100 - 6100 190.84 1,200.09 36.32 90.20 1,517.40 18.00

High Calories

6100 - 7100 0.00 210.81 0.00 82.90 293.77 0.00

8 Jambi

190.84 1,462.03 363.00 173.20 18,623.00 18.00 Low Calories <5100 0.00 11.34 0.00 10.58 21.92 0.00

Medium Calories

5100-6100 0.00 0.81 0.00 5.86 6.67 3.79

High Calories

6100-7100 15.15 100.62 8.11 45.49 16,937.00 1,733.00

Very High Calories

>7100 0.00 0.32 0.00 37.00 0.69 0.00

9 Bengkulu

15.15 113.09 8.11 6,230.00 198.65 21.12

85

Table 4.2 Coal Reserves by Province, 2005 (Continued)


No Province Class

Criteria (Cal/gr,


Reserve (million

Ton)

Low Calories <5100 326.55 7,400.27 2,300.07 1,358.00 11,384.89 2,426.00

Medium Calories

5100-6100 198.93 1,629.28 9,139.87 366.01 11,334.10 186.00

High Calories

6100-7100 0.00 31.00 433.89 14.00 478.89 67.00

10 South Sumatra

525.48 906,055.00 11,873.83 1,738.01 23,197.88 2,679.00 High Calories

6100-7100 0.00 92.95 0.00 0.00 92.95 0.00

Medium Calories

5100 - 6100 0.00 14.00 0.00 0.00 14.00 0.00 11 Lampung

0.00 106.95 0.00 0.00 106.95 0.00 High Calories

6100 - 7100 42.12 378.60 0.00 0.00 420.72 0.00

Very High Calories

>7100 0.00 104.00 1.32 1.48 106.80 0.00 12 West Kalimantan

42.12 48,160.00 132.00 1.48 52,752.00 0.00 Low Calories <5100 0.00 483.92 0.00 0.00 483.92 0.00

Medium Calories

5100 - 6100 0.00 296.75 5.08 44.36 354.80 4.05

High Calories

6100 - 7100 114.11 262.72 0.00 72.6A 449.47 0.00

Very High Calories

>7100 0.00 247.62 0.00 77.02 324.64 44.54

13 Central Kalimantan

114.11 1,291.01 5.08 194.02 161,183.00 4,859.00 Low Calories <5100 0.00 370.87 0.00 600.99 971.86 53,633.00

Medium Calories

5100 - 6100 0.00 4,793.13 301.36 2,526.46 7,620.95 1,287.01

High Calories

6100 - 7100 0.00 336.19 33.12 109.64 478.95 4,436.00

Very High Calories

>7100 0.00 17.62 0.00 12.00 29.62 0.14

14 South Kalimantan

0.00 5,517.81 334.48 3,249.09 910,138.00 1,867.84 Low Calories <5100 0.00 201.93 13.76 89.83 30,532.00 0.00

Medium Calories

5100-6100 2,285.84 10,630.35 121.61 2,609.46 15,682.72 941.62

High Calories

6100-7100 502.96 2,611.07 191.77 1,558.62 4,918.92 1,064.82

Very High Calories

>7100 90.11 60.84 4.48 14.40 169.82 941.62

15 East Kalimantan

2,878.90 13,504.19 331.62 4,271.31 21,076.98 2,071.68 Medium Calories

5100-6100 0.00 131.03 32.31 53.10 216.44 0.06

High Calories

6100-7100 0.00 13.90 0.78 0.00 14.68 0.00 16 South

Sulawesi

0.00 144.93 33.09 53.10 231.12 0.06 Low Calories <5100 0.00 1.98 0.00 0.00 1.98 0.00 17 Central

Sulawesi 0.00 1.98 0.00 0.00 1.98 0.00

86

Table 4. 2 Coal Reserves by Province, 2005 (Continued)


No Province Class

Criteria (Cal/gr,


Reserve (million

Ton)

Low Calories <5100 0.00 2.13 0.00 0.00 2.13 0.00 18 North

Maluku 0.00 2.13 0.00 0.00 2.13 0.00 Medium Calories

5100 - 6100 89.40 30.95 0.00 0.00 120.35 0.00

High Calories

6100 - 7100 0.00 5.38 0.00 0.00 5.38 0.00

Very High Calories

>7100 0.00 25.53 0.00 0.00 25.53 0.00

19 West Papua

89.40 61.86 0.00 0.00 151.26 0.00 Total 3,899.22 34,323.06 12,679.98 10,371.74 61,273.99 6,756.90

1. Depth measured until 100 m 2. Coal quality based on Calorie Value (Keppres No. 13 Tahun 2000 renewed by PP No. 45 Tahun 2003)

a. Low Calorie < 5100 kal/gr b. Medium Calorie < 5100 - 6100 kal/gr c. High Calorie > 6100 - 7100 kal/gr d. Very High Calorie > 7100 kal/gr

Source: Directorate of Mineral Resources Inventory, Directorate General of Geology and Mineral Resources, Ministry of Energy Mineral Resources

87

Table 4.3 Potential and Installed Capacities of Geothermal Energy in Sumatra, December 2004

Resources (MWe) Reserve (MWe) No Area Regency/ City

Speculative Hypothetic Possible Probable Proven Installed (MWe)

Nangroe Aceh Darussalam 1 Lho Pria Lacrt Sabang 30 - - - - - 2 Kaneke Safoang 50 - - - - - 3 Iboih-Jaboi Sataang - 123 - - - - 4 le Seum-Krueng Raya Aceh Besar - 63 - - - - 5 Seulawah Agam Aceh Besar - - 282 - - - 6 Alur Canang Pidie 25 - - - - - 7 Alue Long-Bangga Pidie 100 - - - - - 8 Tangse Pidie 25 - - - - - 9 Rimba Raya Central Aceh 100 - - - - -

10 G. Geureudong Central Aceh - 120 - - - - 11 Simpang Balik Central Aceh 100 - - - - - 12 Silih Nara Central Aceh 100 - - - - - 13 Meranti East Aceh 25 - - - - - 14 Brawang Buaya East Aceh 25 - - - - - 15 Kafi Southeast Aceh 25 - - - - - 16 Gunung Kembar Southeast Aceh - 92 - - - - 17 Dolok Perkirapan Southeast Aceh 25 - - - - -

North Sumatera 18 Beras Tepu Karo - - - - - -

19 Lau Detauk-Debuk-Sibayak Karo - 70 131 - 39 2

20 Marike Karo 25 - - - - - 21 Dolok Marawa Simalungun 225 - - - - -

22 Pusuk Bukrt-Danau Toba North Tapanuli 225 - - - - -

23 Sirnbolon-Samosir North Tapanuli 225 - - - - - 24 Pagaran North Tapanuli 225 - - - - - 25 Helatoba North Tapanuli 25 - - - - - 26 Sipaholon Ria-Ria North Tapanuli 225 - - - - - 27 Sarula North Tapanuli - 100 200 - 80 - 28 Sibual-Buali South Tapanuli - - 556 - - - 29 Namora llangit North Tapanuli - - - - 210 - 30 Sibutauhan South Tapanuli 100 - - - - - 31 Sorik Marapi South Tapanuli - - 420 - - - 32 Sampuraga South Tapanuli 225 - - - - - 33 Roburan South Tapanuli - - 320 - - -

West Sumatera 34 Simisioh Pasaman 100 - - - - - 35 Cubadak Pasaman 100 73 - - - - 36 Talu Pasaman 50 - - - - - 37 Panti Pasaman 150 - - - - - 38 Lubuk Sikaping Pasaman 100 - - - - - 39 Situjuh Lima Puluh Koto 25 - - - - - 40 Bonjol Pasaman 100 - - - - - 41 Kota Baru-Marapi Bukit Tinggi 50 - - - - - 42 Maninjau Agam 25 - - - - - 43 Sumani Solok 25 - - - - - 44 Priangan Tanah Datar 25 - - - - - 45 Bukit Kili Solok - - 58 - - -

88

Table 4.3 Potential and Installed Capacities of Geothermal Energy in Sumatra, December 2004 (Continued)

Resources (MWe) Reserve (MWe)

No Area Regency/ City Speculative Hypothetic Possible Probable Proven

Installed (MWe)

West Sumatera

46 Surian Solok 75 - - - - -

47 Gunung Talang Solok - - 94 - - -

48 Muaralabuh Solok - - 194 - - -

49 Liki-Pinangawan Solok - - 412 - - -

Jambi

51 Gunung Kapur Kerinci 25 - - - - -

52 Gunung Kaca Kerinci 25 - - - - -

53 Sungai Betung Kerinci 100 - - - - -

54 Semurup Kerinci - - 208 - - -

55 Lempur Kerinci - - 150 15 40 -

56 Air Dikit Merangin 225 - - - . -

57 Graho Myabu Merangin - 185 - - - -

58 Sungai Tenang Sorolangun - 74 - - - -

Bengkulu

59 Tambang Sawah Rejang Lebong - 73 100 - - -

60 Bukit Gedang-Hulu Lais Rejang Letaong - 150 500 - - -

61 Suban Gergok Rejang Lebong 225 - - - - -

62 Lebong Simpang Rejang Lebong 225 - - - - -

Bangka Belitung

63 Sungai Liat Bangka 25 - - - - -

64 Pangkal Pinang Bangka 25 - - - - -

65 Air Tembaga Bangka 25 - - - - -

South Sumatera

66 Tanjungsakti Lahat 50 - - - - -

67 Rantau Dadap-Segamrt Muara Enim 225 - - - - -

68 Bukit Lumut Balai Ogan Komering Ulu - 235 600 - - -

69 Ulu Danau Ogan Komering Ulu 225 6 - - - -

70 Marga Bayur Ogan Komering Ulu - 145 194 - - -

71 Wai Selabung Ogan Komering Ulu 225 6 - - - -

Lampung

72 Wai Umpu North Lampung 100 - - - - -

73 Danau Ranau West Lampung - 185 222 - - -

74 Purunan West Lampung 25 - - - - -

75 Gunung Sekincau West Lampung - 100 130 - - -

76 Bacingot West Lampung 225 - - - - -

77 Suoh-Antatai West Lampung - 163 300 - - -

78 Fajar Bulan West Lampung 100 - - - - -

79 Natar South Lampung 25 - - - - -

80 Ulubelu Tanggamus - 156 380 - 20 -

81 Lempasing South Lampung 225 - - - - -

82 Wai Ratal South Lampung - 194 - - - -

83 Kaiianda South Lampung - 40 40 - - -

84 Pematang Belirang South Lampung 225 - - - - -

Source: Directorate of Mineral resources Inventory, Directorate general of Geology and Mineral Resources, Ministry of Energy Mineral Resources, December 2004

89

Table 4.4 Potential and Installed Capacity of Geothermal Energy in Java, December 2004



Installed (MWe)

Banten

85 Rawa Dano Serang - - 115 - - -

86 Gunung Karang Serang - - 170 - - -

87 Gunung Pulosari Serang - 100 - - - -

88 Gunung Endut Lebak 225 - - - - -

89 Pamancalan Lebak 225 - - - - -

West Java

90 Kawah Ratu Sukabumi - - 72 30 - -

91 Kiarataeres Sukabumi 225 - - - - -

92 Awi Bengkok Bogor - - 115 - 485 330

93 Ciseeng Bogor - 100 - - - -

94 Bujal-Jasinga Bogor 25 - - - - -

95 Cisukarame Sukabumi - - 83 - - -

96 Selabintana Sukabumi 25 - - - - -

97 Cisolok Sukataumi - 50 50 - - -

98 Gunung Pancar Bogor 50 - - - - -

99 Jampang Sukabumi 225 - - - - -

100 Tanggeung-Cibungur Cianjur 100 - - - - -

Saguling Bandung 25 - - - - -

102 Cilayu Garut 100 - - - - -

103 Kawah Cibuni Bandung - - 140 - - -

104 Gunung Patuha Bandung - 65 247 - 170 -

105 Kawah Ciwidey Bandung - 84 140 - - -

106 Maribaya Bandung 25 - - - - -

107 Tangkuban Parahu Bandung - 100 90 - - -

108 Sagalaherang Subang - 185 - - - -

109 Ciarinem Garut 25 - - - - -

110 Gunung Papandayan G£rut 225 - - - - -

111 Gunung Masigit-Guntur

Garut - - 70 - - -

112 Kamojang Garut - - - 73 260 140

113 Darajat Garut - - - 70 362 145

114 Gunung Tampomas Sumedang - - 100 - - -

115 Cipacing Bandung 25 - - - - -

116 Gunung Wayang-Wlndu

Bandung - 75 - 135 250 110

117 Gunung Talagabodas Tasikmalaya - 75 120 80 - -

118 Gunung Galunggung Tasikmalaya 100 - - - - -

119 Ciheuras Tasikmalaya 25 - - - - -

120 Cigunung Tasikmalaya 25 - - - - -

121 Cibalong Tasikmalaya 25 - - - - -

122 Gunung Karaha Tasikmalaya - 50 70 100 30 -

123 Gunung Sawal Tasikmalaya 25 - - - - -

124 Cipanas-Ciawi Tasikmalaya 50 - - - - -

125 Gunung Cakrabuana Tasikmalaya 25 - - - - -

126 Gunung Kromong Majalengka 25 - - - - -

127 Sangkan-Urip Kuningan 50 - - - - -

128 Subang Kuningan 50 - - - - -

129 Cibinbin Kuningan 25 - - - - -

90

Table 4.4 Potential and Installed Capacity of Geothermal Energy in Java, December 2004 (Continued)



Installed (MWe)

Central Java

130 Banyugaram Cilaeap 100 - - - - -

131 Bumiayu Banyumas 25 - - - - -

132 Baturaden Banyumas - - 185 - - -

133 Guci Pemalang - - 100 - - -

134 Mangunan-Wanayasa Banjarnegara - - 92 - - -

135 Candradimuka Wonosotao 25 - - - - -

136 Dieng Wonosobo - 200 185 115 280 60

137 Krakal Kebumen 25 - - - - -

138 Panulisan Cilacap 25 - - - - -

139 Gunung Ungaran Semarang - 50 52 - - -

140 Candi Umbul-Telomoyo

Semarang - 92 - - - -

141 Kuwuk Grobogan 25 - - - - -

142 Gunung Lawu Karang Anyar 25 - - - - -

143 Kiepu Semarang 25 - - - - -

East Java

145 Melati Pacitan 25 - - - - -

146 Rejosari Pacitan 25 - - - - -

147 Telaga Ngebel Ponorogo - - 120 - . -

148 Gunung Pandan Madiun 50 - - - - -

149 Gunung Arjuno-Welirang

Mojokerto - 38 92 - - -

150 Cangar Malang - - 100 - - -

151 Songgorrti Malang 25 - - - - -

152 Tirtosari Sumenep 12.5 - - - - -

153 lyang-Argopuro Protaolinggo - 110 185 - - -

154 Tiris Probolinggo - 55 92 - - -

155 Blawan-ljen Banyuwangi - 92 185 - - - Source: Directorate of Mineral Resources Inventory, Directorate General of Geology and Mineral Resources, Ministry of Energy Mineral Resources, December 2004

91

Table 4.5 Potential and Installed Capacity of Geothermal Energy in East Region of Indonesia, December 2004



Installed (MWe)

Bali 156 Banyuwedang Buleleng 12.5 - - - - - 157 Seririt Buleleng 12.5 - - - - - 158 Batukao Tabanan 25 - - - - - 159 Penebel Tabanan 25 - - - - - 160 Buyan-Bratan Buleleng - - 226 - - - East Husa Tenggara 164 Wai Sano Manggarai - 90 33 - - - 165 Ulumbu Manggarai - - 187.5 - 12.5 - 166 Wai Pesi Manggarai - - 54 - - - 167 Gou-lnelika Ngada - 28 - - - - 168 Mengeruda Ngada - 5 - - - - 169 Mataloko Ngada - 10 63.5 - 1.5 - 170 Komandaru Ende - 11 - - - - 171 Ndetusoko Ende - - 10 - - - 172 Sukoria Ende - 145 25 - - - 173 Jopu Ende - - 5 - - - 174 Lesugolo Ende - - 45 - - - 175 Oka - He Ange East Flares - - 40 - - - 176 Atadei Lembata - - 40 - - - 177 Bukapiting Alor - - 27 - - - 178 Roma-Ujelewung Lembata - 16 6 - - - 179 Oyang Barang East Flares - - 37 - - - 180 Sirung(lsiabang-Kuriali) Alor 100 48 - - - - 181 Adum Lembata - - 36 - - - 182 Alor Timur Alor 190 - - - - - West Kalimantan 183 Sibetuk Sintang 25 - - - - - 184 Jagoi Babang Sintang 12.5 - - - - - 185 Meromoh Bengkayang 12.5 - - - - - North Sulawesi 186 Air Madidi Minahasa 25 - - - - - 187 Lahendong Minahasa - 125 - 110 65 20 188 Tompaso Minahasa - - 130 - - - 189 Gunung Amtaang Bolaang Mongondow - - 225 - - - 190 Kotamobagu Bolaang Mongondow - - 185 - - - Gorontalo 191 Gorontalo Gorontalo - - 15 - - - 192 Pentadio Boalemo 25 - - - - - Central Sulawesi 193 Maranda Poso 25 - - - - - 194 Sapo Donggala 25 - - - - - 195 Langkapa Poso 25 - - - - - 196 Napu Poso 25 - - - - - 197 Torire Poso 25 - - - - - 198 Toare Donggala 25 - - - - - 199 Patalogumba Donggala 25 - - - - - 200 Marana Donggala - - 40 - - - 201 Bora Donggala - - 8 - - - 202 Pulu Donggala - - 58 - - - 203 Sedoa Donggala 25 - - - - - 204 Wliasa Poso 25 - - - - - 205 Watuneso Poso 25 - - - - - 206 Papanpulu Poso 25 - - - - -

92

Table 4.5 Potential and Installed Capacity of Geothermal Energy in East Region of Indonesia, December 2004 (Continued)



Installed (MWe)

South Sulawesi 207 Limbong Luwu 25 - - - - - 208 Pararra North Luwu - - 30 - - - 209 Mambosa Mamuju 25 - - - - - 210 Somba Majene 25 - - - - - 211 Mamasa Polewali Mamasa - - 2 - - - 212 Bituang Tana Toraja - - 17 - - - 213 Sangala Tana Toraja 25 - - - - - 214 Sengkang Sindenreng Rappang 25 - - - - - 215 Sulili Pinrang 25 - - - - - 216 Malawa Pangkajene 25 - - - - - 217 Baru Baru 25 - - - - - 218 Watampone Bone 25 - - - - - 219 Todong Bone 25 - - - - - 220 Sinjai Sinjai 25 - - - - - 221 Masepe Sindenreng Rappang 25 - - - - - 222 Danau Tempe Wajo 25 - - - - - South-East Sulawesi 223 Mangolo Kolaka - - 14 - - - 224 Parora Kendari 25 - - - - - 225 Puriala Kendari 25 - - - - - 226 Amoloha Kendari 25 - - - - - 227 Loanti Kendari 25 - - - - - 228 Laenia Kendari - - 36 - - - 229 Torah Buton 25 - - - - - 230 Kalende Buton 25 - - - - - 231 Kanale Buton 25 - - - - - 232 Wonco Buton 25 - - - - - 233 Gonda Baru Bau-Bau - - 1 - - - 234 Kabungka Buton 25 - - - - - 235 Sampolawa Buton 25 - - - - - North Maluku 236 Mamuya North Halmahera - 7 - - - - 237 Ibu West Halmahera 25 - - - - - 238 Akelamo North Halmahera 25 - - - - - 239 Jallolo West Halmahera - - 42 - - - 240 Keibesi West Halmahera 25 - - - - - 241 Akesahu Tidore 25 - - - - - 242 Indari South Halmahera 25 - - - - - 243 Labuha South Halmahera 25 - - - - - 244 Tonga Wayaua South Halmahera - 110 - - - - Maluku 245 Larike Ambon 25 - - - - - 246 Taweri Ambon 25 - - - - - 247 Tolehu Ambon - - 100 - - - 248 Oma Haruku Central Maluku 25 - - - - - 249 Saparua Central Maluku 25 - - - - - 250 Nusa Laut Central Maluku 25 - - - - - Papua 251 Makbau Sorong 25 - - - - - 252 Ransiki Manokwari 25 - - - - -

Source: Directorate of Mineral Resources Inventory, Directorate General of Geology and Mineral Resources, Ministry of Energy Mineral Resources, December 2004

93

Table 4.6 Potential of Microhydro Energy > 20 kVA (15 kW) (measured by PLN)

(kW)

No Location Province Number of Units Potential Measuring

Institution 1 Blangkejeren Aceh 1 2,050 PLN Region I 2 Tangse Aceh 2 1,250 PLN Region I 3 Sepakat Aceh 2 1,750 PLN Region I 4 Arul Ralem Aceh 1 378 PLN Region I 5 Sibundong-2 North Sumatera 2 2337 PLN Region II 6 Letter W West Sumatera 1 5,000 PLN Region III 7 Hinas Kanan South Sumatera 1 520 PLN Region IV 8 Lubuk Buntak South Sumatera 2 2,210 PLN Region IV 9 Purui South Sumatera 1 210 PLN Region IV 10 Merasap West Kalimantan 1 1,160 PLN Region V 11 Muara Kedihin South Kalimantan 1 500 PLN Region VI 12 Baras East Kalimantan 1 200 PLN Region VI 13 Tamako/U-Peliang North Sulawesi 1 1,090 PLN Region VII 14 Poigar North Sulawesi 2 2,500 PLN Region VII 15 Lobong North Sulawesi 2 1,500 PLN Region VII 16 Kolondom North Sulawesi 2 2,000 PLN Region VII 17 Kembera North Sulawesi 1 430 PLN Region VII 18 Toni North Sulawesi 1 300 PLN Region VII 19 Tawaeli North Sulawesi 1 1,270 PLN Region VII 20 Talise North Sulawesi 1 1,200 PLN Region VII 21 Mongango North Sulawesi 1 900 PLN Region VII 22 Wining North Sulawesi 2 1,600 PLN Region VIII 23 Bambalo/Poso Central Sulawesi 1 2,610 PLN Region VII 24 Kalumpang Central Sulawesi 1 700 PLN Region VII 25 Hanga-hanga-2 Central Sulawesi 2 1,670 PLN Region VII 26 Rongi Central Sulawesi 1 845 PLN Region VII 27 Mikuasi Central Sulawesi 2 1,060 PLN Region VII 28 Enrekang/Lewaja South Sulawesi 1 440 PLN Region VIII 29 Mamasa/Bala South Sulawesi 1 340 PLN Region VIII 30 Palangka South Sulawesi 1 1,500 PLN Region VIII 31 Bonelemo South Sulawesi 1 1,340 PLN Region VIII 32 Cennae South Sulawesi 1 590 PLN Region VIII 33 Usu Malili South Sulawesi 2 3,750 PLN Region VIII 34 Batu Sitanduk South Sulawesi 1 1,750 PLN Region VIII 35 Kadundung South Sulawesi 2 1,443 PLN Region VIII 37 Rante Balla South Sulawesi 1 612 PLN Region VIII 38 Hatu Maluku 1 528 PLN Region IX 39 Teminabuan Papua 1 150 PLN Region X 40 Wamena-3 Papua 2 1,000 PLN Region X 41 Werba Papua 1 1,650 PLN Region X 42 Tatui Papua 2 1,182 PLN Region X 43 Santong East Nusa Tenggara 1 545 PLN Region XI 44 Roa/Ende East Nusa Tenggara 1 700 PLN Region XI 45 Lokomboro/Waikabubak East Nusa Tenggara 1 860 PLN Region XI 46 Banjar Cahyana Central Java 1 1,490 PLN Region XI 47 Tapen Central Java 1 730 PLN Region XI

Total Potential 57,840 Source : Rencana Induk Pengembangan Energi Baru dan Terbarukan 1997, Directorate General of Electricity and Energy Development, Ministry of Energy and Mineral Resources

94

Table 4.7 Potential of Microhydro Energy > 20 kVA (15 kW) (measured by non PLN) in Sumatera and Java

(kW)

No River Location Sub District Regency Province Potential

1 Samalanga Samalanga Samalanga North Aceh Aceh 1,130.00 2 Kr. Inong Jim-jim Bandar Baru Pidie Aceh 458.40 3 Kr. Sabet Sabet Lamo West Aceh Aceh 1,274.00 4 Bt. Kumal Padang Bulan Pdg. Sidempuan South Tapanuli North Sumatera 684.00 5 Marpinggan Siponggol Pdg. Sidempuan South Tapanuli North Sumatera 240.00 6 Rantaupuran Gunung Tua-2 Penyambungan South Tapanuli North Sumatera 809.60 7 Batang Gadis Batang Gadis Batang Toru South Tapanuli North Sumatera 900.00 8 A. Pasariran Sipenggang Batang Toru South Tapanuli North Sumatera 1,200.00 9 Hutapungkut Alahan Kae Kota Nopan South Tapanuli North Sumatera 1,248.00

10 I. Eho I. Eho Teluk Dalam Nias North Sumatera 712.30 11 I. Gomo I. Gomo Teluk Dalam Nias North Sumatera 467.30 12 Indano Moi Indano Moi Perw. kec. Moi Nias North Sumatera 672.00 13 Aek Raisan Raisan-3 Pandan North Tapanuli North Sumatera 1,280.00 14 Aek Silang Silang-2 Dolok Sanggul North Tapanuli North Sumatera 1,152.00 15 Sungai Putih Sungai Putih Bayang Pesisir Selatan West Sumatera 1,113.60 16 Ludang Sawah Kerambil Terusan Pesisir Selatan West Sumatera 411.80 17 Bayang Bungo Koto Baharu Bayang Pesisir Selatan West Sumatera 499.20 18 Muara sako Muara Sako Pancung Soal Pesisir Selatan West Sumatera 3,880.40 19 Bt. Bayang Bayang Sani Bayang Pesisir Selatan West Sumatera 644.00 20 Bt. Sumani Sumani Gunung Talang Solok West Sumatera 600.00 21 Bt. Gumanti Pinti Kayu Lembah Gumanti Solok West Sumatera 8,840.00 22 Bt. Balangir Balangir Sangir Solok West Sumatera 480.00 23 Bt. Sangir Kubang Gajah Sangir Solok West Sumatera 7,488.00 24 Bt. A. Guntung Guntung Palupuh Agam West Sumatera 624.00 25 Sikarbau Sikarbau Lembah Melati Pasaman West Sumatera 770.00 26 Patimah Patimah Bonjol Pasaman West Sumatera 860.00 27 ~ Batu Hampar Bonjol Pasaman West Sumatera 608.00 28 A. Tenang Bedegung Tanjung Agung Muara Enim South Sumatera 968.00 29 Selabung Banding Agung 1 Banding Agung Oku South Sumatera 3,194.40 30 Selabung Banding Agung 2 Banding Agung Oku South Sumatera 3,194.50 31 Selabung Banding Agung 3 Banding Agung Oku South Sumatera 2,881.10 32 Campang Mutar Alam Sumber Jaya North Lampung Lampung 750.00 33 Rarem Sinar Mulia Bukit Kemuning North Lampung Lampung 1,044.00 34 Ilahan Way Ilahan Pulau Panggung South Lampung Lampung 1,700.00 35 Klingi Klingi 1 P. Ulak Tanding Rejang Lebong Bengkulu 480.00 36 Klingi Klingi 2 P. Ulak Tanding Rejang Lebong Bengkulu 998.00 37 Air Lang Kepala Curup 2 P. Ulak Tanding Rejang Lebong Bengkulu 1,792.00 38 Blimbing Cinta Mandi Perw. Kb. Agung Rejang Lebong Bengkulu 1,850.00 39 Ketaun Suka Negeri Pw. R. Pengadang Rejang Lebong Bengkulu 2,306.00 40 Cawang Kiri Bungin Tambun Kaur Utara South Bengkulu Bengkulu 3,404.80 41 Padang Guci Talang Genting Kaur Utara South Bengkulu Bengkulu 1,489.60 42 Mana Pulau Timun Pino South Bengkulu Bengkulu 4,059.20 43 Seluma Seluma Manna South Bengkulu Bengkulu 358.40 44 Sindur Talang Alai Perw. Sukaraja South Bengkulu Bengkulu 777.60 45 Palik Aur Gading Kirkap North Bengkulu Bengkulu 1,854.00 46 Lais Kuro Tidur Lais North Bengkulu Bengkulu 1,315.20 47 Lubuk Banyau Lubuk Banyau Lais North Bengkulu Bengkulu 773.60 48 Merangin Penetay Sungai Manau Sarko Jambi 841.60 49 Bt. Air Batu Perentak Sungai Manau Sarko Jambi 518.40 50 Sampean Sampean Baru Prajekan Bondowoso East Java 2,486.90

Total Potential 78,083.90

Source : Rencana Induk Pengembangan Energi Baru dan Terbarukan 1997, Directorate General of Electricity and Energy Development, Ministry of Energy and Mineral Resources

95

Table 4.8 Potential of Microhydro Energy > 20 kVA (15 kW) (measured by non PLN) in Kalimantan and Sulawesi

(kW)

1 Mempawah Tiang Aping Mempawah Pontianak West Kalimantan 530.00 2 Kalompe Kalompe Mempawah Pontianak West Kalimantan 121.60 3 Kalis Kalis Mandai Kapuas Hulu West Kalimantan 1,428.20 4 Tapin Rarahim Piani Tapin South Kalimantan 324.00 5 Barabai Hinas Kanan Batu Benawa H1. Sungai Teng. South Kalimantan 249.20 6 Pisap Kaitan Awayan H1. Sungai Teng. South Kalimantan 1,950.70 7 Purui Purui Jaro Tabalong South Kalimantan 220.00 8 Waruk Menarung Br. Tongkok Kutai East Kalimantan 240.00 9 Bawan Long Bawan 1 Kerayan Bulungan East Kalimantan 200.00

10 Mating Long Bawan 2 Kerayan Bulungan East Kalimantan 36.00 11 Remayo Pa'Betung Kerayan Bulungan East Kalimantan 504.00 12 Karau Rudok Dusun Tengah Buntok Central Kalimantan 2,112.00 13 Sampulan Muara Tuhup Muara Laung Barito Utara Central Kalimantan 80.00 14 Raung Kuala Kurun 1 Kuala Kurun Kapuas/Gng. Mas Central Kalimantan 24.00 15 Sholuhan Kuala Kurun 2 Kuala Kurun Kapuas Central Kalimantan 48.00 16 Suko Puruh Cahu 1 Puruk Cahu North Barito Central Kalimantan 346.00 17 Bumban Puruh Cahu 2 Saripoi North Barito Central Kalimantan 228.00 18 Munthe Tincep 1 Sonder Minahasa North Sulawesi 605.00 19 Munthe Tincep 2 Sonder Minahasa North Sulawesi 1,100.00 20 Munthe Tincep 3 Sonder Minahasa North Sulawesi 2,200.00 21 Susua Rate Limbong 2 Lasusua Kolaka North Sulawesi 712.80 22 Lakambula Olondoro Teomokale Buton North Sulawesi 441.60 23 Tindaki Tindaki Parigi Donggala Central Sulawesi 515.20 24 Dolago Dolago Parigi Donggala Central Sulawesi 768.00 25 ~ Banggai Walatang Donggala Central Sulawesi 816.00 26 ~ Salumpaka Banawa Donggala Central Sulawesi 231.60 27 Tamunggu Nupabomba Tawaeli Donggala Central Sulawesi 319.20 28 Pondo Boboya Palu Timur Donggala Central Sulawesi 399.40 29 Pameki Mantilayo Sigi Biromaku Donggala Central Sulawesi 1,500.00 30 Ampana Sansarino Ampana Kota Poso Central Sulawesi 554.40 31 Kanori Malewa Tojo Poso Central Sulawesi 404.90 32 Tomasa Pandiri Lage Poso Central Sulawesi 2,756.00 33 Wimbi Sawidago 2 Pamona Utara Poso Central Sulawesi 436.80 34 Mongono Solan Klintom Banggai Central Sulawesi 1,523.50 35 Tanggar Tombolo Malino Tanjung Moncong South Sulawesi 1,230.00 36 Mamuju Mamuju Mamuju Mamuju South Sulawesi 648.00 37 Tangkok Manipi Sinjai Barat Sinjai South Sulawesi 5,616.00 38 Urupai Labole Lamuru Bone South Sulawesi 1,090.00 39 Mayamba Paumah Sendana mejene South Sulawesi 106.60 40 Maiting Kabiraan Malunda Mejene South Sulawesi 157.00 41 Lengkeme Langkeme Mario Riwawu Soppeng South Sulawesi 145.60 42 Biyalo Biyalo Bulukumba Donggala South Sulawesi 360.00 43 Sallu Kendenan Makale Tator South Sulawesi 194.90 44 Kokkang Tombang Salluputti Tator South Sulawesi 432.00 45 Dolok Suddu Alla Enrekang South Sulawesi 224.60 46 Mata Allo Bilajen Alla Enrekang South Sulawesi 2,820.80 47 Matama Talogo Tutallu Polmas South Sulawesi 562.80 48 Mumbi Kalimamang Tutallu Polmas South Sulawesi 547.00 49 Susua Rate Limbong 2 Lasusua Kolaka South East Sulawesi 712.80 50 Lakambula Olondoro Teomokale Buton South East Sulawesi 441.60

Total Potential 39,215.80 Source : Rencana Induk Pengembangan Energi Baru dan Terbarukan 1997, Directorate General of Electricity and Energy Development, Ministry of Energy and Mineral Resources


96

Table 4.9 Potential of Microhydro Energy > 20 kVA (15 kW) (measured by non PLN) in East Region of Indonesia

(kW)


1 Ira Ira Galela North Maluku Maluku 370.60 2 Akelamo Goal Sahu North Maluku Maluku 800.00 3 Memekan Memekan Kao North Maluku Maluku 52.80 4 Ngaoli Ngaoli Kao North Maluku Maluku 345.60 5 Wae Toni Saunullu Tehoru Central Maluku Maluku 240.00 6 ~ Teminabuan Teminabuan Sorong Papua 400.00 7 ~ Sorpehee Sorpehee Fak Fak Papua 340.00 8 ~ Hamerhu Hamerhu Fak Fak Papua 640.00 9 Iborengeh Masi 1 Warware Monokwari Papua 668.80

10 Masi Masi 2 Warware Monokwari Papua 436.80 11 Ransiki Ransiki Ransiki Monokwari Papua 1,364.40 12 Wambiadi Wambiadi Wambiadi Manokwari Papua 450.00 13 Mariarotu Mariarotu Yapen Selatan Yapen Waropen Papua 1,443.20 14 Waelega Bonar Rutteng Manggarai East Nusa Tenggara 2,600.00 15 Bijeli Bijeli Molo Selatan Central Timor East Nusa Tenggara 4,532.60 16 ~ Oe Hala Molo Selatan Central Timor East Nusa Tenggara 92.50 17 ~ Fulur Tasifato Belu East Nusa Tenggara 200.00 18 Lowo Mego Wolodesa Perw. Paga Sika East Nusa Tenggara 288.00 19 Wae Musur Sita 1 Mborong Manggarai East Nusa Tenggara 2,400.00 20 Wae Laku Sita 2 Satar Mese Manggarai East Nusa Tenggara 608.00 21 ~ Tjuruk Ruteng Manggarai East Nusa Tenggara 760.00 22 Wae Naong Barang Cibal Manggarai East Nusa Tenggara 680.00 23 Wae Purang Purang Lembor Manggarai East Nusa Tenggara 714.00 24 Kali Putih Mbulilo Wolowaru Ende East Nusa Tenggara 130.00 25 Wai Wutu Piga Pwk. Bajawa Ngada East Nusa Tenggara 321.60 26 Utan Utan Utan Sumbawa East Nusa Tenggara 330.00 27 Lowo Roga Masabewa Paga Sikka East Nusa Tenggara 306.00 28 Wai Buntal Taen Terong Riung Ngada East Nusa Tenggara 416.00 29 Wai Pua Were 2 Golewa Ngada East Nusa Tenggara 98.00 30 Wai Boa Aimere Aimere Ngada East Nusa Tenggara 193.10 31 Amor-amor Sami Jengkel Bayan West Lombok East Nusa Tenggara 180.00 32 Nae Dompu Dompu Bima West Nusa Tenggara 680.00 33 Babak Babak Narmada Central Lombok West Nusa Tenggara 1,050.20 34 Brang Marenteh Marenteh Alas Sumba Besar West Nusa Tenggara 215.00 35 Mamak Mamak Lape Lapok Sumbawa West Nusa Tenggara 560.00 36 ~ Batujai Batujai Central Lombok West Nusa Tenggara 168.00 37 Pengga Pengga Pengga Central Lombok West Nusa Tenggara 448.00 38 Segare Pekatan Tanjung West Lombok West Nusa Tenggara 468.00 39 Delo Paradowane Monta Bima West Nusa Tenggara 216.70 40 Brang Jereweh Jereweh Delo Sumbawa Besar West Nusa Tenggara 121.00 41 Lampe Lampe Rasanae Bima West Nusa Tenggara 216.70

Total Potential 26,545.60 Source : Rencana Induk Pengembangan Energi Baru dan Terbarukan 1997, Directorate General of Electricity and Energy Development, Ministry of Energy and Mineral Resources

97

Table 4.10 Potential of Solar Energy

No Regency Province Year of Measurement

Average Radiation (kWh/m2)

Measured by

1 Banda Aceh Aceh 1980 4.10 LSDE

2 Palembang South Sumatera 1979-1981 4.95 BMG

3 Menggala Lampung 1972-1979 5.23 DGEED/BMG

4 Rawasragi Lampung 1965-1979 4.13 DGEED/BMG

5 Jakarta Jakarta 1965-1981 4.19 DGEED/BMG

6 Bandung West Java 1980 4.15 LSDE

7 Lembang West Java 1980 5.15 LSDE

8 Citius, Tangerang West Java 1980 4.32 LSDE

9 Darmaga, Bogor West Java 1980 2.56 LSDE

10 Serpong, Tangerang West Java 1991-1995 4.45 LSDE

11 Semarang Central Java 1979-1981 5.49 BMG

12 Surabaya East Java 1980 4.30 LSDE

13 Kenteng, Yogyakarta Yogyakarta 1980 4.50 LSDE

14 Denpasar Bali 1977-1979 5.26 DGEED/BMG

15 Pontianak West Kalimantan 1991-1993 4.55 LSDE

16 Banjarbaru South Kalimantan 1979-1981 4.80 BMG

17 Banjarmasin South Kalimantan 1991-1995 4.57 LSDE

18 Samarinda East Kalimantan 1991-1995 4.17 LSDE

19 Menado North Sumatera 1991-1995 4.91 LSDE

20 Palu South East Sulawesi 1991-1994 5.51 LSDE

21 Kupang West Nusa Tenggara 1975-1978 5.12 DGEED/BMG

22 Waingapu, Sumba Timur

East Nusa Tenggara 1991-1995 5.75 LSDE

23 Maumere East Nusa Tenggara 1992-1994 5.72 LSDE


98

Table 4.11 Potential of Wind Energy in West Region of Indonesia measured by BMG)

(m/sec)

No Village/Sub District/Regency Province Year of Measurement Average Velocity

at Elevation of 24 m

1 Sabang Aceh 1994 2.73 2 Meulaboh Aceh 1994 3.33 3 Polonia Medan North Sumatera 1994 3.68 4 Sei Dadap Kisaran North Sumatera 1994 3.06 5 Binaka North Sumatera 1994 3.06 6 Sicincin West Sumatera 1994 3.86 7 KP. Laing West Sumatera 1992 3.72 8 Depati Darbo Jambi 1994 4.01 9 Simpang Tiga Pakanbaru Riau 1994 3.97 10 Kijang Riau 1994 4.22 11 Japura Rengat Riau 1994 2.83 12 Ranai Riau 1994 2.45 13 Pangkal Pinang South Sumatera 1992 3.68 14 Buluh Tumbang Tanjung Pandan South Sumatera 1995 5.56 15 Serang Banten West Java 1992 3.01 16 Curug Tangerang West Java 1994 2.70 17 Tanjung Priok Jakarta 1993 4.45 18 Cengkareng Jakarta 1994 3.55 19 Semarang Maritim Central Java 1992 2.94 20 Kledung Central Java 1994 4.08 21 Adi Sumarmo Surakarta Central Java 1995 2.39 22 Iswahyudi Madiun East Java 1994 5.57 23 Suranaya AURI East Java 1994 4.65 24 Surabaya Perak East Java 1994 2.61 25 Kalianget East Java 1994 5.40 26 Sangkapura Bawean East Java 1994 2.96 27 Surabaya Maritim East Java 1994 3.37 28 Ploso East Java 1991 2.39 29 Kp. Tiekung East Java 1994 2.55 30 Denpasar Bali 1992 2.39 • Small Scale : 2 – 3 (m/sec) • Medium Scale : 3 – 4 (m/sec) • Large Scale : > 4 (m/sec) Source : Rencana Induk Pengembangan Energi Baru dan Terbarukan 1997, Directorate General of Electricity and Energy Development, Ministry of Energy and Mineral Resources

99

Table 4.12 Potential of Wind Energy in East Region of Indonesia (measured by BMG)

(m/sec)

No. Village/Sub District/Regency Province Year of measurement Average Velocity

at Elevation of 24 m

1 Banjar Baru South Kalimantan 1994 2.55 2 Balik Papan East Kalimantan 1994 3.49 3 Tarakan East Kalimantan 1994 3.06 4 Tanjung Redep East Kalimantan 1994 2.58 5 Palangkaraya Panarung Central Kalimantan 1994 2.96 6 Muara Teweh Central Kalimantan 1994 2.95 7 Pangkalan Bun Central Kalimantan 1994 3.01 8 Pangkalan Bun Central Kalimantan 1994 3.01 9 Bubung Luwuk South East Sulawesi 1994 3.01

10 Samratulangi Menado North Sulawesi 1994 3.21 11 Meteo Bitung North Sulawesi 1994 2.80 12 Rembiga Ampenen West Nusa Tenggara 1994 3.14 13 Sengkol West Nusa Tenggara 1991 2.45 14 Sumbawa Besar West Nusa Tenggara 1994 3.92 15 Bima West Nusa Tenggara 1994 2.83 16 Kupang East Nusa Tenggara 1994 5.51 17 Maumere East Nusa Tenggara 1994 3.46 18 Lasiana East Nusa Tenggara 1994 3.62 19 Lekunik East Nusa Tenggara 1994 3.93 20 Tardamu East Nusa Tenggara 1994 5.11 21 Satar Tacik Ruteng East Nusa Tenggara 1994 3.88 22 Ternate Maluku 1994 2.90 23 Tual Maluku 1994 2.70 24 Saumlaki Maluku 1994 4.72 25 Geser Maluku 1994 3.37 26 Sanana Maluku 1994 3.01 27 Nalea Maluku 1994 3.86 28 Labuha Maluku 1994 2.62 29 Genyem Papua 1992 2.89 30 Biak Papua 1994 3.81 31 Kaimana Papua 1994 3.80 32 Manokwari Papua 1994 4.21 33 Sentani Papua 1994 3.18 34 Serui Papua 1990 3.42 35 Wamena Papua 1990 2.96 36 Timika Papua 1994 3.06 • Small Scale : 2 – 3 (m/sec) • Medium Scale : 3 – 4 (m/sec) • Large Scale : > 4 (m/sec)


100

Table 4.13 Potential of Biomass Energy

No Province Energy

from rice waste (kWh)

Energy from corn

waste (kWh)

Energy From

cassava waste (kWh)

Energy from wood

waste (kWh)

Energy from

bagasse waste (kWh)

Energy from

coconut waste (kWh)

Energy from palm waste (kWh)

Total potential (kWh)l

Total potential

(kW)

1 Aceh 4,389,706 431,095 258,504 6,049,213 n.a 219,280 205,280 11,553,080 1,318.84

2 North Sumatera 10,195,593 2,314,892 871,309 5,355,260 64,490 235,701 1,683,820 20,721,068 2,365.42

3 West Sumatera 5,098,375 246,795 199,979 3,948,58 0.0 161,697 137,843 9,793,277 1,117.95

4 Riau 1,983,752 257,553 169,647 9,615,760 0.0 796,550 928,015 13,751,279 1,569.78

5 Jambi 2,367,450 128,522 616,022 5,425,444 0.0 298,997 214,169 9,050,605 1,033.17

6 Bengkulu 1,347,523 295,034 159,077 1,053,227 0.0 29,925 52,813 2,937,601 335.34

7 South Sumatera 5,430,242 328,720 755,798 9,138,553 57,921 63,780 259,221 16,034,238 1,830.39

8 Lampung 5,479,526 4,099,255 4,031,337 1,200,435 260,241 436,210 37,483 15,544,489 1,774.49

9 Jakarta 62,007 722 1,470 2,698 0.0 0.0 0.0 66,899 7.64

10 West Java 25,217,219 1,884,996 3,632,919 1,374,134 113,359 476,541 22,076 32,721,246 3,735.30

11 Central Java 19,274,685 8,091,226 5,868,925 1,517,684 293,198 422,761 0.0 35,468,481 4,048.91

12 Yogyakarta 7,577 180 22 33,155 28,236 113,149 0.0 182,322 20.81

13 East Java 21,090,156 16,558,311 6,713,419 2,124,634 856,306 519,077 0.0 47,861,905 5,463.69

14 West Kalimantan 4,225,297 245,497 391,479 14,598,861 0.0 119,163 135,369 19,715,669 2,250.65

15 Central Kalimantan 2,327,557 41,242 122,772 23,747,448 0.0 73,314 8,194 26,320,528 3,004.63

16 South Kalimantan 5,021,574 245,908 199,243 4,370,927 45,814 122,838 16,445 10,022,752 1,144.15

17 East Kalimantan 1,723,811 182,263 294,074 25,932,474 0.0 66,050 45,775 28,244,449 3,224.25

18 North Sulawesi 1,250,948 1,117,723 138,926 3,173,349 16,505 755,977 0.0 6,453,431 736.69

19 Central Sulawesi 1,979,301 282,321 352,967 7,040,892 0.0 408,941 8,814 10,073,238 1,149.91

20 South Sulawesi 11,037,629 5,659,932 1,236,409 3,555,232 71,889 349,818 44,929 21,955,841 2,506.37

21 South East Sulawesi 1,036,020 644,745 358,275 5,506,430 0.0 97,876 0.0 7,643,349 872.53

22 Bali 1,965,806 661,104 206,987 34,745 0.0 174,551 0.0 3,043,195 347.40

23 West Nusa Tenggara 3,487,425 457,785 227,621 1,120,737 0.0 97,299 0.0 5,390,869 615.40

24 East Nusa Tenggara 2,033,010 3,974,166 1,876,283 2,153,199 0.0 127,297 0.0 10,163,957 1,160.27

25 Maluku 322,707 473,766 433,506 7,789,331 0.0 558,270 0.0 9,577,581 1,093.33

26 Papua 213,204 58,504 78,470 59,271,453 0.0 31,545 40,354 59,693,532 6,814.33

27 East Timor 279,675 1,018,650 438,906 566,083 0.0 24,896 0.0 2,328,212 265.78

Total Potential 138,847,782 49,700,918 29,634,361 205,699,957 1,807,964 6,781,514 3,840,607 436,313,106 49,807.43


101

Table 4.14 Potential of Biogas Energy

No Province Energy from cow waste

(kWh)

Energy from buffalo waste

(kWh)

Energy from pig waste (kWh)

Total potential (kWh)

Total potential

(kW)

1 Aceh 176,518,754 196,136,857 181,220 372,836,831.00 42,561.28

2 North Sumatera 74,363,081 132,422,738 203,169,016 409,954,835.00 46,798.50

3 West Sumatera 126,698,243 98,229,921 3,407,275 228,335,439.00 26,065.69

4 Riau 36,120,418 21,630,728 22,834,799 80,585,945.00 9,199.31

5 Jambi 38,478,295 38,231,613 1,238,582 77,948,490.00 8,898.23

6 Bengkulu 30,164,863 48,092,009 113,785 78,370,657.00 8,946.42

7 South Sumatera 144,011,035 69,914,662 21,079,697 235,005,394.00 26,827.10

8 Lampung 108,170,057 22,692,458 7,308,835 138,171,350.00 15,772.99

9 Jakarta 1,671,636 296,479 4,436,556 6,404,671.00 731.13

10 West Java 93,668,568 252,258,353 5,272,717 351,199,638.00 40,091.28

11 Central Java 405,853,632 131,878,374 13,902,080 551,634,086.00 62,971.93

12 Yogyakarta 61,485,351 5,222,260 1,091,497 67,799,108.00 7,739.62

13 East Java 1,018,223,467 78,446,300 6,142,490 1,102,812,257.00 125,891.81

14 West Kalimantan 47,469,518 2,977,066 102,917,667 153,364,251.00 17,507.33

15 Central Kalimantan 14,886,698 4,426,575 13,901,453 33,214,726.00 3,791.64

16 South Kalimantan 47,219,493 26,031,288 1,251,422 74,502,203.00 8,504.82

17 East Kalimantan 22,933,519 11,013,426 9,209,247 43,156,192.00 4,926.51

18 North Sulawesi 83,926,641 2,414,049 54,189,247 140,529,937.00 16,042.23

19 Central Sulawesi 121,577,567 21,287,126 23,807,187 166,671,880.00 19,026.47

20 South Sulawesi 201,287,881 119,742,352 42,624,867 363,655,100.00 41,513.14

21 South East Sulawesi 80,296,106 6,233,922 1,388,381 87,918,409.00 10,036.35

22 Bali 153,772,988 5,378,353 120,413,566 279,564,907.00 31,913.80

23 West Nusa Tenggara 138,391,872 106,098,407 2,640,116 247,130,395.00 28,211.23

24 East Nusa Tenggara 245,128,428 90,774,249 160,980,602 496,883,279.00 56,721.84

25 Maluku 30,020,918 10,427,830 9,620,437 50,069,185.00 5,715.66

26 Papua 17,244,574 372,072 64,499,908 82,116,554.00 9,374.04

27 East Timor 10,374,345 25,986,128 42,923,212 79,283,685.00 9,050.65

Total Potential 3,529,957,948 1,528,615,595 940,545,861 5,999,119,404 684,830.98


102

Table 4.15 Potential of Peat Energy

Quality

No Location Province Ash (%)

S (%)

Average Thickness

(m) Area (ha)

Dry Weight (million tons)

Average Calorific

Value (MJ/kg

dry weight)

Total Calorific

Value (109 MJ)

1 Alue Bilie Aceh 21.00 0.20 1.50 20,000.00 91.05 11.99 1,091.69

2 Tanjung Medan North Sumatera 2.50 0.30 2.50 26,000.00 73.10 20.91 1,528.52

3 Siak Kiri Riau 1.50 0.15 1.50 206,000.00 396.00 20.51 8,121.96

4 Siak Kanan Riau 1.50 0.17 4.80 110,000.00 423.20 21.65 9,162.28

5 P. Bengkalis Riau 3.50 0.42 3.00 66,410.00 360.00 24.00 8,640.00

6 P. Rangsang Riau 3.50 0.42 3.00 76,000.00 200.00 19.70 3,940.00

7 Tembilahan Riau 4.00 0.90 2.40 112,000.00 330.00 19.31 6,372.30

8 P. Rupat Riau 2.80 0.37 3.10 38,100.00 143.28 19.71 2,824.05

9 Kumpeh Jambi 5.10 0.70 3.00 17,700.00 31.86 18.12 577.30

10 Air Hitam Jambi 3.10 0.19 6.00 157,50.00 977.60 18.96 18,535.30

11 Dendang Jambi 4.00 0.50 4.00 25,000.00 70.00 20.71 1,449.70

12 Air Sugihan South Sumatera 23.10 0.0 1.50 7,200.00 9.72 15.29 148.61

13 Bayung Lincir South Sumatera 5.60 0.25 3.50 45,000.00 59.33 20.91 1,240.59

14 Tulung Selapan South Sumatera 0.0 0.0 3.50 12,000.00 292.80 18.00 5,270.40

15 Paloh West Kalimantan 2.40 0.70 2.00 11,500.00 27.60 19.08 526.61

16 Sakura West Kalimantan 1.70 0.60 3.00 17,500.00 99.97 18.19 1,818.45

17 Rasau Jaya/Pinang West Kalimantan 2.10 0.30 3.40 44,000.00 165.00 20.89 3,446.85

18 Ketapang West Kalimantan 3.20 0.80 2.10 75,000.00 240.00 20.88 5,011.20

19 Sungairaya West Kalimantan 3.00 0.48 5.00 64,635.00 262.00 19.58 5,129.96

20 Kendawangan West Kalimantan 5.60 0.90 1.50 77,000.00 14.25 19.86 283.01

21 Maraban South Kalimantan 0.30 0.17 3.00 12,600.00 12.30 24.00 295.20

22 Kanamit Central Kalimantan 4.50 0.80 2.50 57,000.00 92.50 19.24 1,779.70

23 Sampit Central Kalimantan 2.20 0.10 3.50 1,071.00 3.94 15.89 62.61

24 Sekajang Central Kalimantan 3.80 0.51 3.00 36,895.00 139.40 18.48 2,576.11

25 Kelampangan Central Kalimantan 1.60 0.12 3.00 4,280.00 15.36 20.82 319.80

26 Baung Central Kalimantan 4.10 0.45 4.70 78,750.00 377.30 19.17 7,232.84

27 Kota Besi Central Kalimantan 2.50 0.37 2.00 3,600.00 5.40 20.47 110.54

28 Berengbengkel Central Kalimantan 1.70 0.15 2.00 4,000.00 7.20 20.82 149.90

29 Muarakaman East Kalimantan 10.50 0.90 2.00 5,579.00 16.85 15.06 253.76

30 Malangke Sulawesi 3.10 0.31 0.50 1,250.00 1.25 20.71 25.89

Total Potential Indonesia 133.5 12.23 86.5 1,256,070.06 4,938.26 582.91 97,925.13

Note : Values of MJ/kg dry weight and MJ are those of thermal energy Sources : Rencana Induk Pengembangan Energi Baru dan Terbarukan 1997, Directorate General of Electricity and Energy Development, Ministry of Energy and Mineral Resources

103

V. ENERGY PRODUCTION AND CONSUMPTION IN INDONESIA


ENERGY PRODUCTION AND CONSUMPTION

105

Table 5.1 Production of Energy, 1997-2005

Type of Production Unit 1997 1998 1999 2000 2001 2002 2003 2004 2005

Crude Oil & Condensate

Thousand barrel 576,962.57 568,782.26 545,579.06 517,488.69 489,306.41 456,944.00 418,593.46 347,356.42 341,904.43

Gas MMSCF 3,166,034.90 2,978,851.90 3,068,349.06 2,901,378.73 2,807,149.95 3,041,872.71 3,155,243.12 3,030,132.06 2,985,340.96

LNG tons 27,136,671.20 27,179,907.30 29,812,374.60 27,321,019.90 24,343,678.00 26,184,740.50 26,077,444.47 25,237,867.67 23,676,764.80

LPG tons 2,786,651.80 2,343,944.20 2,263,518.10 2,087,669.10 2,187,676.70 2,113,881.00 1,927,318.28 2,016,001.24 1,818,899.82

Coal tons 54,822,000.00 61,931,000.00 73,777,000.00 77,040,000.00 92,540,000.00 103,372,000.00 114,278,000.00 132,352,000.00 149,665,233.34

Sources:

- Directorate General of Oil & Gas, Oil & Gas Data Information, 6th Ed.,2002 - Embassy of the United States of America Jakarta, Petroleum Report Indonesia : 2002-2003, March 2004 - Indonesia Oil & Gas Statistics, 1995-2005 Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources - Indonesia Mineral & Coal Statistics, 2000-2004, Directorate of Mineral and Coal Enterprises, Ministry of Energy and Mineral Resources - Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources - http:// dpmb.esdm.go.id

106

Table 5.2 Energy Supply by Type of Primary Energy, 1990-2004

(Thousand BOE) Year Crude Oil % Gas % Coal % Hydro % Geo % Biomass % Total 1990 297,434.57 44.63 127,603.63 19.15 24,390.00 3.66 21,678.30 3.25 2,185.30 0.33 193,190.59 28.99 666,482.39 1991 307,149.74 43.63 152,419.78 21.65 24,683.23 3.51 21,222.30 3.01 2,231.20 0.32 196,353.58 27.89 704,059.83 1992 339,310.51 44.52 163,685.27 21.48 30,129.50 3.95 27,465.90 3.60 2,045.70 0.27 199,486.74 26.18 762,123.63 1993 339,952.70 43.62 173,142.36 22.22 35,122.90 4.51 26,301.80 3.37 2,169.40 0.28 202,654.63 26.00 779,343.79 1994 348,163.40 42.23 207,075.78 25.12 35,135.21 4.26 25,737.50 3.12 3,000.00 0.36 205,264.26 24.90 824,376.15 1995 367,779.07 42.06 230,037.44 26.31 38,666.49 4.42 26,349.50 3.01 4,200.00 0.48 207,404.32 23.72 874,436.82 1996 401,355.42 43.26 239,484.78 25.81 46,090.80 4.97 27,120.60 2.92 4,545.30 0.49 209,219.61 22.55 927,816.51 1997 423,921.16 44.44 233,232.25 24.45 56,842.80 5.96 20,691.60 2.17 5,424.10 0.57 213,843.95 22.42 953,955.86 1998 393,762.49 43.11 207,184.27 22.68 61,000.80 6.68 26,912.80 2.95 7,435.20 0.81 217,168.62 23.77 913,464.19 1999 409,777.72 43.18 202,201.78 21.31 83,958.93 8.85 25,972.90 2.74 7,501.70 0.79 219,564.74 23.14 948,977.77 2000 451,235.18 44.78 204,633.82 20.31 93,831.55 9.31 25,111.40 2.49 9,179.10 0.91 223,613.99 22.19 1,007,605.03 2001 450,538.77 42.26 232,584.73 21.82 115,029.25 10.79 29,380.30 2.76 11,795.10 1.11 226,840.46 21.28 1,066,168.60 2002 464,507.34 41.79 251,431.61 22.62 122,879.41 11.06 29,843.80 2.68 12,199.99 1.10 230,641.23 20.75 1,111,503.38 2003 465,802.09 41.25 246,132.55 21.80 128,763.35 11.40 30,696.00 2.72 23,372.00 2.07 234,423.57 20.76 1,129,189.56 2004 510,349.41 44.87 181,277.82 15.94 151,524.50 13.32 32,401.20 2.85 24,856.40 2.19 237,065.44 20.84 1,137,474.77

Source: Handbook of Indonesia’s Energy Economy Statistics, 2005, Center for Energy Information, Department of Energy and Mineral Resources (Processed by PE UI using INOSYD)

107

Table 5.3 Energy Consumption by Type of Final Energy, 1990 – 2004

(Thousand BOE) Year Petroleum Fuels % Gas % Coal % LPG % Electricity % Biomassa % Total 1990 173,135.83 39.24 43,936.37 9.96 9,411.70 2.13 2,705.85 0.61 18,788.30 4.26 193,190.59 43.79 441,168.63 1991 184,874.13 40.19 43,491.56 9.45 11,058.08 2.40 3,082.43 0.67 21,167.64 4.60 196,353.58 42.68 460,027.42 1992 201,743.83 41.39 46,190.88 9.48 12,266.40 2.52 3,527.92 0.72 24,260.64 4.98 199,486.74 40.92 487,476.42 1993 218,904.86 42.59 48,164.84 9.37 13,940.96 2.71 4,133.57 0.80 26,132.07 5.08 202,654.63 39.43 513,930.92 1994 227,550.18 43.04 49,468.86 9.36 14,419.88 2.73 4,984.42 0.94 27,054.70 5.12 205,264.26 38.82 528,742.29 1995 245,233.21 43.92 52,562.90 9.41 16,924.33 3.03 5,862.35 1.05 30,366.46 5.44 207,404.32 37.15 558,353.58 1996 261,441.21 44.83 55,157.60 9.46 15,785.89 2.71 6,774.11 1.16 34,825.51 5.97 209,219.61 35.87 583,203.92 1997 275,272.59 44.94 61,007.99 9.96 16,395.21 2.68 6,977.41 1.14 39,022.44 6.37 213,843.95 34.91 612,519.58 1998 271,925.68 44.58 55,217.13 9.05 18,215.03 2.99 6,966.04 1.14 40,539.55 6.65 217,168.62 35.60 610,032.05 1999 290,414.95 43.73 75,420.40 11.36 27,425.06 4.13 7,517.14 1.13 43,764.31 6.59 219,564.74 33.06 664,106.60 2000 307,580.86 43.33 84,004.53 11.83 36,950.29 5.21 8,127.72 1.14 49,569.53 6.98 223,613.99 31.50 709,846.91 2001 319,170.37 43.48 89,628.48 12.21 38,269.63 5.21 8,280.44 1.13 51,840.99 7.06 226,840.46 30.90 734,030.36 2002 328,089.76 43.49 93,986.35 12.46 39,589.17 5.25 8,745.06 1.16 53,417.90 7.08 230,641.23 30.57 754,469.47 2003 330,623.73 43.44 90,734.74 11.92 40,954.11 5.38 8,910.36 1.17 55,472.80 7.29 234,423.57 30.80 761,119.31 2004 354,274.20 42.53 114,651.10 13.76 56,437.25 6.78 9,159.10 1.10 61,352.90 7.37 237,065.44 28.46 832,939.98 Source: Handbook of Indonesia’s Energy Economy Statistics, 2005, Center for Energy Information, Department of Energy and Mineral Resources (Processed by PE UI using INOSYD)

108

Table 5.4 Final Energy Consumption by Sector, 1990 – 2004

(Thousand BOE) Year Industry % Commercial % Residential % Transportation % Others % total 1990 72,563.39 33.25 6,218.00 2.85 45,997.00 21.08 76,183.17 34.91 17,242.12 7.90 218,203.67 1991 75,464.00 32.56 7,224.00 3.12 47,568.00 20.53 82,585.86 35.64 18,907.61 8.16 231,749.46 1992 85,822.25 33.75 8,317.00 3.27 49,221.00 19.36 91,208.57 35.87 19,695.17 7.75 254,264.00 1993 93,897.11 34.11 9,911.00 3.60 51,159.00 18.58 96,713.16 35.13 23,616.71 8.58 275,296.97 1994 104,488.85 35.67 10,834.00 3.70 53,443.00 18.24 98,186.85 33.52 25,992.16 8.87 292,944.86 1995 114,698.42 36.03 12,063.00 3.79 56,395.00 17.72 105,866.94 33.26 29,309.74 9.21 318,333.10 1996 115,294.09 34.16 13,538.00 4.01 59,451.00 17.62 116,188.58 34.43 33,018.47 9.78 337,490.14 1997 125,067.83 34.59 14,847.00 4.11 64,368.00 17.80 122,833.39 33.98 34,405.54 9.52 361,521.76 1998 123,833.29 34.78 14,961.00 4.20 68,154.00 19.14 123,558.40 34.71 25,493.37 7.16 356,000.05 1999 160,372.39 39.93 15,955.00 3.97 71,142.00 17.71 128,833.84 32.07 25,363.12 6.31 401,666.35 2000 184,118.43 41.81 17,176.00 3.90 75,542.00 17.15 137,440.30 31.21 26,138.12 5.93 440,414.85 2001 197,893.44 42.48 17,755.00 3.81 79,739.00 17.12 143,624.41 30.83 26,859.70 5.77 465,871.55 2002 197,932.16 41.57 18,394.00 3.86 83,160.00 17.47 149,107.28 31.32 27,525.35 5.78 476,118.79 2003 189,526.41 39.44 19,725.00 4.10 86,582.00 18.02 156,827.33 32.63 27,939.83 5.81 480,600.57 2004 241,152.26 43.82 21,698.00 3.94 89,087.00 16.19 169,788.99 30.85 28,597.21 5.20 550,323.47

Source: Handbook of Indonesia’s Energy Economy Statistics, 2005, Center for Energy Information, Department of Energy and Mineral Resources (Processed by PE UI using INOSYD)

109

Table 5.5 Petroleum Fuel Consumption by Sector, 1990 – 2004

(Thousand BOE) Year Industry Commercial Residential Transportation Others Electricity Total 1990 37,840.00 2,394.00 39,490.00 76,170.00 17,242.00 30,095.99 203,231.99 1991 40,384.00 3,028.00 39,997.00 82,557.00 18,908.00 34,104.65 218,978.65 1992 46,488.00 3,880.00 40,503.00 91,178.00 19,695.00 38,507.81 240,251.81 1993 52,551.00 4,970.00 41,104.00 96,663.00 23,617.00 41,905.06 260,810.06 1994 56,093.00 5,491.00 41,860.00 98,114.00 25,992.00 25,066.95 252,616.95 1995 61,525.00 5,962.00 42,655.00 105,781.00 29,310.00 19,713.88 264,946.88 1996 62,349.00 6,499.00 43,491.00 116,084.00 33,018.00 22,118.26 283,559.26 1997 64,836.00 6,854.00 46,469.00 122,711.00 34,406.00 30,436.03 305,712.03 1998 68,312.00 5,749.00 48,976.00 123,396.00 25,493.00 27,329.84 299,255.84 1999 79,719.00 5,824.00 50,847.00 128,662.00 25,363.00 31,077.57 321,492.57 2000 85,239.00 6,134.00 52,794.00 137,275.00 26,138.00 33,195.15 340,775.15 2001 87,507.00 6,226.00 55,094.00 143,484.00 26,860.00 35,676.09 354,847.09 2002 87,363.00 6,320.00 57,906.00 148,976.00 27,525.00 46,035.27 374,125.27 2003 79,434.00 6,414.00 60,137.00 156,698.00 27,940.00 50,308.36 380,931.36 2004 88,651.00 6,511.00 60,856.00 169,659.00 28,597.00 56,208.71 410,482.71

Source: Handbook of Indonesia’s Energy Economy Statistics, 2005, Center for Energy Information, Department of Energy and Mineral Resources (Processed by PE UI using INOSYD )

110

Table 5.6 Gas Consumption by Sector, 1990 – 2004

(Thousand BOE)

Year Industry Commercial Residential Transportation Electricity Total 1990 14,027.00 92.00 39.00 3.00 2,388.86 16,549.86 1991 11,407.00 103.00 40.00 18.00 2,296.72 13,864.72 1992 12,287.00 117.00 40.00 20.00 2,296.72 14,760.72 1993 11,975.00 131.00 41.00 40.00 10,465.47 22,652.47 1994 18,670.00 152.00 49.00 63.00 28,862.62 47,796.62 1995 19,639.00 172.00 58.00 74.00 39,517.75 59,460.75 1996 18,308.00 194.00 68.00 89.00 52,830.78 71,489.78 1997 23,462.00 208.00 74.00 103.00 40,996.93 64,843.93 1998 17,940.00 186.00 76.00 140.00 39,881.08 58,223.08 1999 32,117.00 194.00 74.00 147.00 42,495.52 75,027.52 2000 37,752.00 203.00 82.00 138.00 41,099.30 79,274.30 2001 47,891.00 206.00 89.00 111.00 39,946.81 88,243.81 2002 45,859.00 209.00 96.00 99.00 34,649.69 80,912.69 2003 44,211.00 212.00 104.00 97.00 33,101.00 77,725.00 2004 68,661.00 215.00 111.00 97.00 31,687.91 100,771.91


111

Table 5.7 Coal Consumption by Sector, 1990-2004

(Thousand BOE) Year Industry Commercial Residential Transportation Others Electricity Total 1990 9,243.00 0.00 0.00 0.00 0.00 14,013.66 23,256.66 1991 10,860.00 0.00 0.00 0.00 0.00 15,763.70 26,623.70 1992 12,047.00 0.00 0.00 0.00 0.00 15,763.70 27,810.70 1993 13,690.00 0.00 2.00 0.00 0.00 14,505.16 28,197.16 1994 14,151.00 0.00 13.00 0.00 0.00 16,949.10 31,113.10 1995 16,601.00 0.00 24.00 0.00 0.00 17,143.22 33,768.22 1996 15,473.00 0.00 36.00 0.00 0.00 24,417.00 39,926.00 1997 16,056.00 0.00 55.00 0.00 0.00 30,532.41 46,643.41 1998 17,829.00 0.00 72.00 0.00 0.00 32,593.65 50,494.65 1999 26,862.00 0.00 86.00 0.00 0.00 34,983.07 61,931.07 2000 36,215.00 0.00 88.00 0.00 0.00 40,259.25 76,562.25 2001 37,508.00 0.00 91.00 0.00 0.00 42,993.54 80,592.54 2002 38,802.00 0.00 94.00 0.00 0.00 43,075.26 81,971.26 2003 40,140.00 0.00 97.00 0.00 0.00 46,771.31 87,008.31 2004 55,344.00 0.00 99.00 0.00 0.00 47,238.50 102,681.50


112

Table 5.8a Petroleum Fuel Sales in Residential Sector, 2000-2005

2000 2001 2002 2003 2004 2005 Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Premium 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00

Kerosene 12,409,142 100.00 8,172,429 100.00 11,622,937 100.00 11,704,403 100.00 11,787,354 100.00 11,294,676 100.00

Automotive Diesel Oil 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00

Intermediate Diesel Oil 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00

Fuel Oil 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00

TOTAL 12,409,142 100 8,172,429 100 11,622,937 100 11,704,403 100 11,787,354 100 11,294,676 100 Source: Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources (Processed)

Table 5.8b Petroleum Fuel Sales in Transportation Sector, 2000-2005

2000 2001 2002 2003 2004 2005 Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Premium & Special Premium 12,874,043 50.71 11,490,034 49.06 14,096,529 51.76 14,647,489 54.77 17,027,444 56.51 17,828,528 58.81

Kerosene 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00 Automotive Diesel Oil 12,152,821 47.87 9,774,706 41.73 12,675,523 46.54 12,108,939 43.95 12,816,785 42.54 12,132,616 40.02 Intermediate Diesel Oil 139,530 0.55 1,960,756 8.37 122,517 0.45 85,878 0.31 51,995 0.17 71,814 0.24 Fuel Oil 221,365 0.87 196,933 0.84 339,230 1.25 267,803 0.97 233,982 0.78 281,316 0.93


113

Table 5.8c Petroleum Fuel Sales in Industry Sector, 2000-2005

2000 2001 2002 2003 2004 2005

Volume (kl)

Percent (%)

Volume (kl)

Percent (%)

Volume (kl)

Percent (%)

Volume (kl)

Percent (%)

Volume (kl)

Percent (%)

Volume (kl)

Percent (%)

Premium 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00 Kerosene 48,634 0.40 2,339,809 21.10 52,953 0.43 48,440 0.48 58,765 0.44 90,906 0.77 Automotive Diesel Oil 6,674,515 54.95 5,104,186 46.02 7,010,072 57.18 5,682,776 56.57 8,956,069 66.37 8,505,760 72.11 Intermediate Diesel Oil 1,308,278 10.77 1,566,295 14.12 1,198,555 9.78 1,063,634 10.59 1,007,715 7.47 807,141 6.84 Fuel Oil 4,115,835 33.88 2,081,063 18.76 3,997,918 32.61 3,251,247 32.36 3,472,210 25.73 2,391,854 20.28


Table 5.8d Petroleum Fuel Sales in Electricity Sector, 2000-2005

2000 2001 2002 2003 2004 2005

Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Volume

(kl) Percent

(%) Premium 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00 Kerosene 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00 0 0.00 Automotive Diesel Oil 3,244,920 64.79 9,836,012 89.42 4,589,987 70.09 5,122,023 65.23 4,589,987 70.09 6,832,053 75.89 Intermediate Diesel Oil 24,360 0.49 26,394 0.24 38,474 0.59 33,720 0.43 38,474 0.59 16,255 0.18 Fuel Oil 1,739,012 34.72 1,137,735 10.34 1,920,478 29.33 2,696,366 34.34 1,920,478 29.33 2,154,715 23.93


114

Table 5.9a Petroleum Fuel Sales per Region, 2003

KiloLiter

No UPMS I UPMS II UPMS III UPMS IV UPMS V UPMS VI UPMS VII UPMS VIII TOTAL Premium 1,791,598 996,157 5,047,512 1,889,029 2,897,290 863,052 944,000 218,851 14,647,489

1 a. Transportation 1,791,598 996,157 5,047,512 1,889,029 2,897,290 863,052 944,000 218,851 14,647,489

Kerosene 1,485,584 773,161 3,881,577 1,503,017 2,376,466 803,523 673,729 256,052 11,753,109

a. Residential 1,484,357 771,619 3,855,972 1,493,208 2,369,530 803,142 671,411 255,164 11,704,4032

b. Industry 1,227 1,542 25,605 9,809 6,936 115 2,318 888 48,440

Automotive Diesel Oil 4,440,567 2,178,744 5,368,028 2,498,723 4,316,072 3,254,999 1,227,407 779,918 24,064,458

a. Residential 2,091,808 1,146,818 3,125,551 1,395,132 2,398,340 1,042,750 712,853 195,687 12,108,939

b. Industry 1,317,189 5,143 1,809,604 336,657 72,295 1,542,526 213,561 385,801 5,682,7763

c. Electricity 1,031,570 405,352 432,873 766,934 1,316,148 669,723 300,993 198,430 5,122,023

Intermediate Diesel Oil 46,828 51,017 721,889 62,197 224,236 8,501 68,810 1,183,478

a. Residential 11,562 6,315 24,438 4,790 32,480 782 5,511 85,878

b. Industry 35,266 22,235 690,336 53,269 191,756 7,473 63,299 1,063,6344

c. Electricity - 22,467 7,115 4,138 - 33,720

Fuel Oil 1,018,800 233,714 2,523,460 799,454 1,487,101 41,105 111,782 150 6,215,566

a. Residential 19,561 1,967 117,341 14,644 96,700 7,331 10,259 267,803

b. Industry 568,185 158,212 1,663,441 284,483 515,940 33,774 27,212 3,251,2475

c. Electricity 431,054 73,535 742,678 500,327 874,461 74,311 2,696,366

TOTAL 8,783,377 4,232,793 17,542,466 6,752,420 11,301,165 4,971,180 3,025,728 1,254,971 57,864,100 Source: Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

115

Table 5.9b Petroleum Fuel Sales per Region, 2004

KiloLiter

No UPMS I UPMS II UPMS III UPMS IV UPMS V UPMS VI UPMS VII UPMS VIII TOTAL

Premium 2,086,945 1,172,962 5,490,179 2,197,943 3,163,435 992,303 1,056,125 258,124 16,418,0161

a. Transportation 1,791,598 996,157 5,047,512 1,889,029 2,897,290 863,052 944,000 218,851 14,647,489

Kerosene 1,472,827 764,692 3,885,584 1,534,633 2,451,421 807,805 674,425 254,732 11,846,119

a. Residential 1,471,105 759,889 3,857,708 1,526,907 2,440,564 806,489 671,929 252,763 11,787,3542

b. Industry 1,722 4,803 27,876 7,726 10,857 1,316 2,496 1,969 58,765


a. Residential 2,216,996 1,331,509 3,147,180 1,533,987 2,262,171 1,190,294 747,565 387,083 12,816,785

b. Industry 1,441,144 778,411 2,524,151 1,251,695 663,174 1,793,934 261,373 242,187 8,956,0693

c. Electricity 1,207,818 412,321 315,855 19,534 1,527,543 681,932 332,562 217,332 4,714,897

Intermediate Diesel Oil 41,188 56,879 675,162 58,527 192,451 10,882 58,325 0 1,093,414

a. Residential 8,914 5,851 140 7,228 23,802 167 5,893 0 51,995

b. Industry 32,274 23,852 668,494 51,299 168,649 10,715 52,432 0 1,007,7154

c. Electricity 0 27,176 6,528 0 0 0 0 0 33,704

Fuel Oil 936,155 230,115 2,411,564 713,817 1,269,018 77,048 116,790 0 5,754,507

a. Residential 19,698 3,824 76,126 14,543 104,777 5,410 9,604 0 233,982

b. Industry 534,879 215,042 1,491,160 699,274 422,019 71,638 38,198 0 3,472,2105

c. Electricity 381,578 11,249 844,278 0 742,222 0 68,988 0 2,048,315


116

Table 5.9c Petroleum Fuel Sales per Region, 2005

KiloLiter

No UPMS I UPMS II UPMS III UPMS IV UPMS V UPMS VI UPMS VII UPMS VIII TOTAL

Premium 2,258,790 1,266,535 5,940,065 2,289,072 3,334,077 1,042,826 1,078,367 270,595 17,480,3271

a. Transportation 1,791,598 996,157 5,047,512 1,889,029 2,897,290 863,052 944,000 218,851 14,647,489

Kerosene 1,375,586 768,711 3,765,451 1,450,594 2,382,302 778,884 625,702 238,353 11,385,582

a. Residential 1,372,295 761,068 3,738,166 1,444,133 2,363,974 777,191 607,057 230,793 11,294,6762

b. Industry 3,291 7,643 27,285 6,461 18,328 1,693 18,646 7,560 90,906


a. Residential 2,240,741 1,121,411 3,061,296 1,503,323 2,330,795 1,061,353 676,341 137,356 12,132,616

b. Industry 1,308,615 1,114,924 1,924,863 388,844 760,654 2,084,373 505,371 418,116 8,505,7603

c. Electricity 1,331,615 141,428 1,092,711 877,210 2,143,687 715,164 304,660 225,578 6,832,053

Intermediate Diesel Oil 36,659 34,796 590,118 53,598 150,425 10,692 18,923 0 895,210

a. Residential 10,245 3,259 16,455 5,330 30,610 993 4,922 0 71,814

b. Industry 26,414 20,324 572,913 43,976 119,815 9,699 14,001 0 807,1414

c. Electricity 0 11,213 750 4,292 0 0 0 0 16,255

Fuel Oil 824,692 204,491 1,787,696 628,083 1,205,791 32,352 144,780 0 4,827,884

a. Residential 25,979 15,240 99,444 11,357 90,751 10,603 27,942 0 281,316

b. Industry 311,725 188,701 1,276,568 189,760 337,329 21,748 66,022 0 2,391,8545

c. Electricity 486,988 550 411,683 426,966 777,712 0 50,816 0 2,154,715


117

Table 5.10 Crude Oil Production by Production Schemes, 1995 – 2005

(Barrel)

Year Pertamina Production

Sharing Contractors

Total

Annually 20,656,779.00 464,193,521.00 484,850,300.00 1995

Daily Average 56,594.00 1,271,763.00 1,328,357.00

Annually 37,577, 840.00 447,995,960.00 485,573,800.00 1996

Daily Average 102,670.00 1,224,030.00 1,326,700.00

Annually 38,942,558.00 445,398,042.00 484,340,600.00 1997

Daily Average 106,692.00 1,220,269.00 1,326,961.00

Annually 43,570,517.00 436,539,183.00 480,109,700.00 1998

Daily Average 119,371.00 1,195,998.00 1,315,369.00

Annually 40,984,592.00 399,476,972.00 440,461,564.00 1999

Daily Average 112,287.00 1,094,457.00 1,206,744.00

Annually 45,726,352.00 419,699,983.00 465,426,335.00 2000

Daily Average 124,935.00 1,146,721.00 1,271,657.00

Annually 46,101,364.00 395,072,849.00 441,174,213.00 2001

Daily Average 129,882.00 1,082,391.00 1,212,273.00

Annually 42,569,440.00 364,952,958.00 407,522,398.00 2002

Daily Average 118,904.00 999,871.00 1,118,775.00

Annually 41,512,127.00 328,053,059.00 369,565,186.00 2003

Daily Average 113,731.85 898,775.50 1,012,507.36

Annually 41,010,652.00 306,148,281.00 347,158,933.00 2004

Daily Average 112,358.00 838,762.00 951,120.00

Annually 41,877,493.00 299,325,102.00 341,202,595.00 2005

Daily Average 114,733.00 820,069.00 934,802.00

Sources :

- Indonesia Oil and Gas Statistics, 1995-2005 Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

- Oil & Gas Statistics of Indonesia 2000-2004, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

118

Table 5.11 Condensate Production by Production Scheme, 1995 – 2005

(Barrel)

Year Pertamina Production

Sharing Contractors

Total

Annually 349,597.00 61,776,824.00 62,126,421.00 1995

Daily Average 958 169,252.00 170,210.00

Annually 59,560.00 63,014,920.00 63,074,480.00 1996

Daily Average 160 172,640.00 172,800.00

Annually 46,465.00 59,365,544.00 59,412,009.00 1997

Daily Average 127 162,645.00 162,772.00

Annually 137,596.00 54,644,672.00 54,782,268.00 1998

Daily Average 377 149,711.00 150,048.00

Annually 209,168.00 53,972,181.00 54,181,349.00 1999

Daily Average 573 147,869.00 148,442.00

Annually 720,149.00 51,400,608.00 52,120,757.00 2000

Daily Average 1,968.00 140,439.00 142,407.00

Annually 214,828.00 47,917,367.00 48,132,195.00 2001

Daily Average 589 131,280.00 131,869.00

Annually 99,525.00 48,002,723.00 48,102,248.00 2002

Daily Average 273 131,514.00 131,787.00

Annually 103,200.00 48,742,844.00 48,846,044.00 2003

Daily Average 282.74 133,542.04 133,824.78

Annually 197,489.00 46,975,415.00 47,172,904.00 2004

Daily Average 539.59 128,348.13 128,887.72

Annually 701,838.00 45,749,079.00 46,450,917.00 2005

Daily Average 1,923.00 125,340.00 127,263.00 Sources :



119

Table 5.12 Production of Naphtha and LSWR by Refinery, 1996 – 2005

(Barrel) Refinery

Year Products P.Brandan Dumai S.Pakning Musi Cilacap Balikpapan Balongan Cepu Kasim

Total

Naphtha 259,462 291,271 0 23,339 9,586,766 4,453,184 0 0 0 14,614,022 1996

LSWR 0 3,689,236 5,066,437 16,340,893 1,055,438 23,255,328 0 0 0 49,407,332 Naphtha 242,164 396,644 0 36,733 3,035,678 4,475,643 0 0 0 8,186,862

1997 LSWR 0 9,826,160 4,805,368 16,106,174 914,340 21,504,036 0 0 0 53,156,078 Naphtha 70,761 227,506 0 87,336 2,305,760 3,359,049 0 0 0 6,050,412

1998 LSWR 0 4,767,558 3,483,279 9,673,835 657,337 22,275,944 2,234,290 0 239,751 43,331,994 Naphtha 614,776 399,559 0 95,346 4,998,137 3,058,849 0 0 40,752 9,207,419

1999 LSWR 0 5,509,723 2,581,395 7,650,353 1,056,766 21,912,179 0 0 0 38,710,416 Naphtha 667,074 620,226 0 135,714 9,023,638 6,172,462 0 0 28,240 16,647,354

2000 LSWR 0 5,693,507 3,333,620 3,827,181 1,177,562 24,585,961 0 0 0 38,617,831 Naphtha 73,338 213,870 0 2,634,839 10,332,709 6,925,713 0 0 0 20,180,469

2001 LSWR 0 4,855,527 2,860,161 6,957 2,716,652 22,919,190 0 0 866,586 34,225,073 Naphtha 0 0 0 0 0 31,033 0 0 0 31,033

2002 LSWR 0 2,560,153 3,051,234 488,043 439,179 21,106,172 0 0 717,730 28,362,511 Naphtha 20,295 0 0 4,299,733 9,668,298 4,165,440 0 0 0 18,153,766

2003 LSWR 0 2,618,638 3,885,279 2,302,857 1,624,280 20,737,635 0 0 1,016,373 32,185,062 Naphtha 0 0 3,601,827 8,204,852 6,671,033 0 0 0 18,477,712

2004 LSWR 1,935,875 4,385,352 802,850 2,081,510 18,921,161 0 0 1,061,869 29,188,617 Naphtha 314,654 0 965,725 4,511,650 10,185,687 5,238,579 0 0 0 21,216,295

2005 LSWR 0 0 7,829,198 276,891 1,378,815 18,539,881 0 0 939,856 28,964,641

Sub Total Naphtha 2,262,524 2,149,076 965,725 15,426,517 67,341,525 44,550,985 0 0 68,992 132,765,344 Sub Total LSWR 0 41,456,377 41,281,323 57,476,034 13,101,879 215,757,487 2,234,290 0 4,842,165 376,149,555 Total Non-Fuels Products 2,262,524 43,605,453 42,247,048 72,902,551 80,443,404 260,308,472 2,234,290 0 4,911,157 508,914,899 Sources :

- Indonesia Oil & Gas Statistics 1996-2002, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources - Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources, 2006

120

Table 5.13a Production of various Fuels by Refinery, 2003

(Barrel)

Refineries Fuels Products

P.Brandan Dumai S.Pakning Musi Cilacap Balikpapan Balongan Cepu Kasim Total

1. JP-5 0 0 0 0 0 0 0 0 0 0

2. Avgas 0 0 0 72,351 0 0 0 0 0 72,351

3. Avtur 0 2,528,517 0 687,185 3,363,683 4,124,217 0 0 0 10,703,602

4. Premium 0 8,670,509 0 6,984,283 23,220,352 13,660,366 16,510,633 0 526,987 69,573,130

5. Kerosene 336,449 6,160,934 2,274,871 5,815,385 23,124,978 16,202,299 3,911,199 174,348 555,627 58,556,090

6. Gas Oil/ ADO/ HSD 174,503 24,559,224 2,834,910 8,341,619 23,201,178 25,777,277 8,654,278 220,764 744,983 94,508,736

7. Diesel Oil/ IDO/ MDF 0 1048 0 443,232 5,426,958 611,918 1,311,961 0 0 7,795,117

8. Fuel Oil/ DCO/ IFO/ MFO 52,046 54,167 0 8,431,800 23,179,382 340 2,159,718 0 0 33,877,453

9. Pertamax plus 0 0 0 0 0 0 495,861 0 0 495,861

10.Pertamax 0 0 0 232,200 0 30,640 2,357,879 0 0 2,620,719

Sub Total 562,998 41,974,399 5,109,781 31,008,055 101,516,531 60,407,057 35,401,529 395,112 1,827,597 278,203,059Converted from kiloLiter Source : Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

121

Table 5.13b Production of various Fuels by Refinery, 2004

(Barrel)



1. JP-5 0 0 0 0 0 0 0 0 0 0

2. Avgas 0 0 0 32,248 0 0 0 0 0 32,248

3. Avtur 0 2,625,419 0 621,005 3,185,872 4,783,701 0 0 0 11,215,997

4. Premium 0 8,791,612 0 7,775,338 22,747,609 15,151,474 16,952,659 0 523,462 71,942,154

5. Kerosene 281,846 5,739,851 2,653,849 5,818,757 19,617,295 17,018,205 4,963,520 168,623 562,465 56,824,412

6. Gas Oil/ ADO/ HSD 159,088 24,362,779 2,943,891 7,730,101 23,993,524 28,123,212 10,372,352 221,854 745,681 98,652,481

7. Diesel Oil/ IDO/ MDF 16,058 82 0 445,878 8,112,892 496,058 1,132,151 0 0 10,203,119

8. Fuel Oil/ DCO/ IFO/ MFO 0 648 0 8,143,901 20,961,727 4,164 1,854,101 0 0 30,964,541

9. Pertamax plus 0 0 0 0 0 0 303,162 0 0 303,162

10. Pertamax 0 0 0 351,895 0 151,502 2,534,047 0 0 3,037,445

Sub Total 456,992 41,520,391 5,597,740 30,919,122 98,618,919 65,728,316 38,111,993 390,477 1,831,609 283,175,558Converted from kiloLiter Source : Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

122

Table 5.13c Production of various Fuels by Refinery, 2005

(Barrel)



1. JP-5 0 0 0 0 0 0 0 0 0 0

2. Avgas 0 0 0 33,814 0 0 0 0 0 33,814

3. Avtur 0 2,583,548 0 691,664 2,802,628 4,609,052 0 0 0 10,686,892

4. Premium 0 7,861,068 0 8,033,855 20,166,508 16,831,920 17,660,576 0 464,634 71,018,560

5. Kerosene 340,523 5,920,639 2,629,382 6,062,436 17,075,738 16,461,482 4,552,991 187,078 494,517 53,724,786

6. Gas Oil/ ADO/ HSD 163,497 23,158,704 2,835,008 6,410,558 22,761,491 28,180,373 10,186,847 221,024 722,767 94,640,268

7. Diesel Oil/ IDO/ MDF 16,058 138 0 255,234 7,088,768 246,585 968,711 0 0 8,575,494

8. Fuel Oil/ DCO/ IFO/ MFO 0 296 0 6,036,214 20,143,040 4,220 1,570,494 0 0 27,754,265

9. Pertamax plus 0 0 0 0 0 0 431,870 0 0 431,870

10. Pertamax 0 0 0 110,342 0 87,523 1,502,023 0 0 1,699,888

Sub Total 520,078 39,524,392 5,464,390 27,634,117 90,038,173 66,421,156 36,873,512 408,101 1,681,918 268,565,837 Converted from kiloLiter Source : Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

123

Table 5.14a Production of Oil and Gas by Refinery, 2003

Crude Oil Condensate Imported Crude Oil LNG LPG

Thousand

Barrel Thousand

Barrel Thousand

Barrel Billion BTU

Thousand Barrel

Thousand ton

Thousand Barrel

A. OIL REFINERY

P. Brandan 961.64 0 0.00 0 0

Dumai 45,945.78 0 0.00 0 0 51.50 553.625

Sei Pakning 17,140.15 0 0.00 0 0

Musi 41,102.46 0 0.00 0 0 102.97 1106.8738

Cilacap 37,213.18 0 88,080.88 0 0 162.72 1749.2508

Balikpapan 42,213.44 0 46,035.71 0 0 128.42 1380.472

Balongan 36,259.88 0 462.68 0 0 333.34 3583.3728

Cepu 822.13 0 0.00 0 0

Kasim 3,091.30 0 0.00 0 0

SUB TOTAL 224,749.94 0.00 134,579.28 0 0 778.94 8373.5943

B. GAS REFINERY

Arun 0 0 0 328,312.49 87,878.08 0.00

Badak 0 0 0 1,019,036.44 273,346.69 843.39

Mundu 0 0 0 0 0 12.55

Tanjung Santan 0 0 0 0 0 155.38

Jabung 0 0 0 0 0 67.26

Arjuna 0 0 0 0 0 25.80

Arar 0 0 0 0 0 0.77

Sumbagut 0 0 0 0 0 38.90

SUB TOTAL 0 0 0 1,347,348.93 361,224.76 1,148.38

TOTAL 0 0 0 1,347,348.93 361,224.76 1,927.32

Sources :

- Indonesia Oil and Gas Statistics, 2003, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

- Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

124

Table 5.14b Production of Oil and Gas by Refinery, 2004


Thousand Barrel

Thousand Barrel

Thousand Barrel

Billion BTU

Thousand Barrel

Thousand ton

Thousand Barrel

A. OIL REFINERY

P. Brandan 961.64 0 0.00 0 0

Dumai 45,945.78 0 0.00 0 0 63.25 679.937

Sei Pakning 17,140.15 0 0.00 0 0

Musi 41,102.46 0 0.00 0 0 134.28 1,443.47

Cilacap 37,213.18 0 88,080.88 0 0 148.11 1,592.21

Balikpapan 42,213.44 0 46,035.71 0 0 120.32 1,293.39

Balongan 36,259.88 0 462.68 0 0 430.44 4,627.24

Cepu 822.13 0 0.00 0 0

Kasim 3,091.30 0 0.00 0 0

SUB TOTAL 224,749.94 0.00 134,579.28 0 0 896.40 9,636.25

B. GAS REFINERY

Arun 0 0 0 292,928.27 78,406.92 0.00 0.00

Badak 0 0 0 1,010,988.93 271,188.02 854.14 9,886.19

Mundu 0 0 0 0 0 9.46 101.66

Tanjung Santan 0 0 0 0 0 0.00 0.00

Jabung 0 0 0 0 0 68.98 859.52

Arjuna 0 0 0 0 0 147.22 1,736.01

Arar 0 0 0 0 0 1.47 18.36

Sumbagut 0 0 0 0 0 38.34 412.12

SUB TOTAL 0 0 0 1,303,917.20 349,594.94 1,119.61 13,013.40

TOTAL 0 0 0 1,303,917.20 349,594.94 2,016.00 22,649.64

Sources :

- Indonesia Oil and Gas Statistics, 2004, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources


125

Table 5.14c Production of Oil and Gas by Refinery, 2005


Thousand

Barrel Thousand

Barrel Thousand

Barrel Billion BTU

Thousand Barrel

Thousand ton

Thousand Barrel

A. OIL REFINERY

P. Brandan 896.97 0 0 0 0

Dumai 42,087.33 0 0 0 0 71.37 767.23

Sei Pakning 17,888.34 0 0 0 0

Musi 36,399.54 0 0 0 0 139.68 1,501.56

Cilacap 24,095.05 1,090.38 85,372.98 0 0 118.39 1,272.68

Balikpapan 45,785.15 2,406.96 42,030.25 0 0 99.14 1,065.74

Balongan 41,795.67 0 193.84 0 0 404.14 4,344.49

Cepu 903.96 0 0.00 0 0

Kasim 2,843.29 0 0.00 0 0

SUB TOTAL 212,695.29 3,497.34 127,597.07 0 0 832.72 8,951.71

B. GAS REFINERY

Arun 0 0 0 217,529.28 58,225.18 0.00 0.00

Badak 0 0 0 1,005,610.72 269,745.36 770.20 8,961.84

Mundu 0 0 0 0 0 5.96 64.06

Tanjung Santan 0 0 0 0 0 127.36 1,503.66

Jabung 0 0 0 0 0 56.24 700.41

Arjuna 0 0 0 0 0 0.00 0.00

Arar 0 0 0 0 0 0.00 0.00

Sumbagut 0 0 0 0 0 26.43 284.10

SUB TOTAL 0 0 0 1,223,140.00 327,970.55 995.10 11,514.07

TOTAL 0 0 0 1,223,140.00 327,970.55 1,827.81 20,465.78

Source: Indonesia Oil and Gas Statistics, 2005, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

126

Table 5.15 Natural Gas Production by Production Scheme, 1995 – 2005

(Barrel) Year Pertamina Pertamina-JOB Pertamina-TAC PSC Total

Annually 279,163,623 35,114,369 28,303,436 2,821,434,761 3,164,016,189 1996

Daily Average 764,832 96,204 77,544 7,729,958 8,668,538

Annually 279,511,569 34,783,553 26,154,729 2,825,585,041 3,166,034,892 1997

Daily Average 765,785 95,297 71,657 7,741,329 8,674,068

Annually 270,329,833 37,613,772 29,460,354 2,641,447,914 2,978,851,873 1998

Daily Average 740,630 103,051 80,713 7,236,844 8,161,238

Annually 259,131,635 34,239,136 34,213,979 2,740,764,314 3,068,349,064 1999

Daily Average 709,950 93,806 93,737 7,508,943 8,406,436

Annually 285,691,770 33,186,444 27,604,880 2,554,895,640 2,901,378,734 2000

Daily Average 782,717 90,922 75,630 6,999,714 7,948,983

Annually 276,790,580 32,675,517 37,243,630 2,460,440,226 2,807,149,953 2001

Daily Average 758,330 89,522 102,037 6,740,932 7,690,822

Annually 258,012,265 36,999,407 39,733,464 2,707,127,571 3,041,872,707 2002

Daily Average 706,883 101,368 108,859 165,915,572 166,832,682

Annually 264,658,030 32,376,560 203,016,436 2,819,735,938 3,319,786,964 2003

Daily Average 725,090 88,703 556,209 7,725,304 9,095,307

Annually 301,856,580 27,544,471 54,470,370 2,655,764,844 3,039,636,265 2004

Daily Average 827,004 75,464 149,234 7,276,068 8,327,771

Annually 308,000,980 23,962,781 37,293,334 2,605,729,121 2,974,986,216 2005

Daily Average 843,838 65,652 130,542 7,138,984 8,179,016

Source :

- Indonesia Oil and Gas Statistics, 1995-2002, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

- Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources, 2006

127

Table 5.16 Production and Utilization of Natural Gas, 1999-2005

(MMSCF)

1999 2000 2001 2002 2003 2004 2005

Gas Production 3,066,349.00 2,901,302.00 2,807,150.00 3,041,852.00 3,073,482.00 3,030,132.06 2,985,340.96

Utilization (incl. Export) 2,575,131.00 2,728,172.00 2,623,725.00 2,856,637.00 2,900,581.00 2,678,791.43 2,592,511.71

( % Utilization ) 0.84 0.94 0.93 0.94 0.94

- Own use 385,887 397,163 382,583 372,446 353,612 311,869.35 315,067.71

- LPG/ Lex Plant 8,253 14,936 10,397 26,901 28,141 34,098.78 24,578.61

- Refinery 41,911 32,227 29,437 30,879 22,995 20,496.73 16,154.70

- Fertilizer/ Petrochemical 238,797 255,178 230,140 268,129 254,222 196,150.83 196,775.08

- Cement Industry 2,048 2,822 3,411 2,737 2,884

- Electricity 175,334 223,564 254,237 199,765 182,573

- PT PGN (Persero) 46,944 62,560 86,295 148,957 158,921 283,381.65

- Others Industry 131,990 155,357 102,915 64,824 125,815

Exports 1,543,967 1,584,365 1,524,310 1,741,999 1,771,418

( % Exports ) 60% 58% 58% 61% 61%

Domestic Utilization 1,031,164 1,143,807 1,099,415 1,114,638 1,129,163 594,666.90

(% Domestic Utilization) 40% 42% 42% 39% 39%

Losses/ Flared 458,184 137,671 179,371 154,943 172,901 131,786 157,532

( % Losses ) 15% 5% 6% 5% 6% Source: Oil & Gas Statistics of Indonesia 1999 – 2005, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

128

Table 5.17 Production of LNG, 1999 – 2005

Year Refinery Unit

1999 2000 2001 2002 2003 2004 2005

Barrel 158,142,836.48 92,892,616.35 41,553,057.00 86,427,144.65 87,878,075.48 78,406,924.51 58,225,181.06

MMSCF 529,462.22 311,004.48 139,120.00 289,508.74 294,215.80 262,506.38 194,937.91

m3 25,144,711.00 14,769,926.00 6,606,936.00 13,749,071.00 13,972,614.00 12,466,701.00 9,257,803.79

MMBtu 590,821,637.09 347,046,814.69 155,242,219.00 323,059,932.43 328312490 292,928,270.02 217,529,276.44

ARUN

ton 11,416,606.73 6,706,079.73 2,999,788.00 6,242,574.69 6,344,071.29 5,660,332.39 4,203,377.21

Barrel 254,818,169.81 285,558.150.94 295,655,566.00 276,238,880.50 273,346,685.54 271,188,018.87 269,745,364.93

MMSCF 249,028.60 951,451.20 985,095.00 920,400.33 910,763.82 903,571.36 898,764.58

m3 40,516,089.00 45,403,746.00 47,009,235.00 43,921,982.00 43,462,123.00 43,118,895.00 42,889,513.02

MMBtu 949,962,137.05 1,064,560,786.72 1,102,203,950.00 1,029,818,546.52 1,019,036,443.67 1,010,988,934.34 1,005,610,720.45

BADAK

Ton 18,395,767.38 20,614,940.15 21,343,890.00 19,942,165.79 19733373.2 19,577,535.28 19,473,387.59

Barrel 412,961,006.29 378,450,767.29 337,208,623.00 362,666,025.15 361,224,761.02 349,594,943.38 327,970,545.99

MMSCF 1,378,490.88 1,262,455.68 1,124,215.00 1,209,909.07 1204979.618 1,166,077.74 1,093,702.49

m3 65,660,800.00 60,173,672.00 53,616,171.00 57,671,053.00 57,434,737.00 55,585,596.00 52,147,316.81

MMBtu 1,540,783,774.14 1,411,607,601.41 1,257,446,169.00 1,352,878,478.95 1347348934 1,303,917,204.36 1,223,139,996.89

Total

Ton 29,812,374.12 27,321,019.88 24,343,678.00 26,184,740.48 26,077,444.47 25,237,867.67 23,676,764.80 Source :

- Indonesia Oil and Gas Statistics, 1999-2002, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources - Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

129

Table 5.18 Production of LPG, 2001 – 2005

(tons)

Type of Refinery Products 2001 2002 2003 2004 2005

A. Gas Refinery

Butane 0.00 0.00 0.00 0.00 0.00 Arun

Propane 0.00 0.00 0.00 0.00 0.00

Butane 510,553.00 381,872.12 409,490.13 440,857.69 369,832.86 Badak

Propane 552,469.00 441,561.02 433,902.17 413,278.35 400,364.56

Butane 0.00 0.00 0.00 57,227.53 0.00 Arjuna

Propane 114,101.00 162,171.99 25,797.00 89,996.65 0.00

Butane 67,792.00 67,262.40 61,652.80 57,227.53 48,394.41 Santan

Propane 105,703.00 105,262.80 93,722.50 89,996.65 78,963.98

Butane 0.00 68,929.68 67,261.95 68,978.02 56,240.01 Jabung

Propane 0.00 0.00 0.00 0.00 0.00

Butane 9,314.00 9,533.00 12,548.00 9,457.00 5,959.00 Mundu

Propane 0.00 0.00 0.00 0.00 0.00

Butane 0.00 0.00 0.00 0.00 0.00 Arar

Propane 4,072.00 677.53 772.00 1,474.00 0.00

Butane 51,531.00 48,308.00 38,900.00 38,337.00 26,428.00 Sumbagut

Propane 0.00 0.00 0.00 0.00 0.00

Butane 639,190.00 506,975.52 594,185.61 625,791.06 515,768.97 Sub Total

Propane 776,345.00 709,673.34 554,193.67 504,749.00 479,328.54

B. Oil Refinery

Dumai Butane 60,810.00 43,416.00 51,500.00 63,250.00 71,370.00

Musi Butane 101,963.00 121,070.00 102,965.00 134,276.00 139,680.00

Cilacap Butane 146,347.00 144,768.00 162,721.00 148,113.00 118,389.00

Balikpapan Butane 94,513.00 104,437.00 128,416.00 120,315.00 99,139.00

Exor-1 Balongan Butane 368,510.00 400,486.00 333,337.00 430,441.00 404,139.00

Sub Total Butane 772,143.00 814,177.00 778,939.00 896,395.00 832,717.00

Butane 1,411,333.00 1,321,152.52 1,373,124.61 1,522,186.06 1,348,485.97 Total

Propane 776,345.00 709,673.34 554,193.67 504,749.00 479,328.54 Sources :



130

Table 5.19 Gas Sales of PT. PGN (Persero) by Sector, 1995 – 2005

Years Production Households Industry & Commercial Total

LPG (ton) 28,876 1,224,621 1,249,497 Natural Gas (103 m3) 3,015 5,316 8,331 1995 Number of Consumers 38,554 1,715 40,269 Natural Gas (103 m3) 8,884 1,505,961 1,514,844 LPG (ton) 2,900 4,337 7,237 1996 Number of Consumers 41,651 1,861 43,512 Natural Gas (103 m3) 9,548 1,835,355 1,844,904 LPG (ton) 2,634 3,459 6,093 1997 Number of Consumers 45,640 1,882 47,522 Natural Gas (103 m3) 10,659 1,561,107 1,571,766 LPG (ton) 2,417 2,303 4,720 1998 Number of Consumers 49,361 1,945 51,306 Natural Gas (103 m3) 11,729 1,612,104 1,623,834,588 LPG (ton) 2,398 2,276 4,674 1999 Number of Consumers 52,290 2,113 54,403 Natural Gas (103 m3) 12,742 1,907,882 1,920,625 LPG (ton) 2,847 1,997 4,484 2000 Number of Consumers 56,704 2,217 58,928 Natural Gas (103 m3) 13,510 2,116,602 2,130,113 LPG (ton) 1,955 1,766 3,721 2001 Number of Consumers 692,757 27,813 64,463 Natural Gas (103 m3) n.a n.a 2,131,137 LPG (ton) n.a n.a 3,796 2002 Number of Consumers n.a n.a 64,463 Natural Gas (103 m3) n.a n.a 2,684,224 LPG (ton) n.a n.a 3,364 2003 Number of Consumers n.a n.a 77,075 Natural Gas (103 m3) n.a n.a 2,937,681 LPG (ton) n.a n.a 0 2004 Number of Consumers n.a n.a 894,856

Source : Indonesia Oil and Gas Statistics,1995-2004 ,Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources.

131

Table 5.20 Coal Production by Company, 1999-June 2006

(Thousand ton) No. Company 1999 2000 2001 2002 2003 2004 2005 2006*

Government Company (PT Tambang Batubara Bukit Asam)

1 - Bukit Asam - - 8,559 3,742

2 - Ombilin 1,091 737 559 362 10 69 48 0

3 - Tanjung Enim : Steam Coal 10,043 9,984 9,612 9,077 10,013 - - -

4 - Tanjung Enim : Antrachite 73 25 41 43 4 8,638 - -

Sub Total 11,207 10,746 10,21 2 9,482 10,027 8,707 8,607 3,743

Coal Contractor

5 PT Adaro Indonesia 13,601 15,481 17,708 20,819 22,523 24,331 26,686 16,746

6 PT Allied Indo Coal 426 132 121 164 52 185 - -

7 PT Antang Gunung Meratus 150 257 447 465 507 1,130 1,029 -

8 PT Arutmin Indonesia 8,653 7,708 9,532 10,557 13,615 15,019 16,757 7,919

9 PT Bahari Cakrawala Sebuku 1,548 1,521 1,968 2,065 1,964 2,531 3,000 850

10 PD Baramarta 0 246 177 637 719 1,049 - 23

11 PT Baramulti Suksessarana 0 0 0 14 39 73 1,286 -

12 PT Bentala Coal Mining 188 166 83 0 0 0 27 -

13 PT Berau Coal 3,261 4,877 6,750 7,123 7,360 9,103 9,197 4,472

14 PT BHP Kendilo Coal Indonesia 1,027 1,038 933 769 0 0 - -

15 Borneo Indobara - - - - - - - 232

16 PT Gunung Bayan Pratama Coal 1,048 1,345 1,970 2,602 3,326 3,360 4,330 1,333

17 PT Indominco Mandiri 3,058 3,705 4,435 5,335 6,327 7,103 7,449 1,617

18 PT Jorong Barutama Greston 714 1,128 2,599 2,293 2,891 2,801 3,029 1,014

19 PT Kadya Caraka Mulia 0 101 40 0 0 0 167 -

20 PT Kalimantan Energi Lestari 601 -

21 PT Kaltim Prima Coal 13,974 13,099 15,528 17,577 16,203 21,280 27,641 14,550

22 PT Kartika Selabumi Mining 0 0 0 0 302 736 1,035 342

23 PT Kideco Jaya Agung 7,302 8,037 10,381 11,500 14,056 16,927 18,125 7,717

24 PT Lanna Harita Indonesia 0 0 99 945 1,235 1,700 1,887 704

25 Mahakam Sumber Jaya 1,694 -

26 PT Mandiri Inti Perkasa 0 602 1,082 279

27 PT Marunda Graha Mineral 0 458 824 250

28 PT Multi Harapan Utama 1,644 1,221 1,301 973 1,620 1,521 897 509

29 PT Riau Bara Harum 167 -

30 PT Sumber Kurnia Buana 0 609 406 847 932 757 870 -

31 PT Tanito Harum 1,011 1,036 1,571 1,807 2,179 2,256 2,403 217

32 PT Tanjung Alam Jaya 0 0 483 586 450 250 751 286

33 PT Trubaindo Coal Mining 1,610 -

Sub Total 57,605 61,707 76,532 87,078 96,301 113,171 132,544 59,062

Cooperative Unit

34 KOP Karya Merdeka 25 52 0 0 0 0

35 KOP Teratai Putih 26 53 0 0 0 0

36 KUD Bina Bersama 12 0 0 0 0 0

37 KUD Karya Maju 7 20 0 0 0 0

38 KUD Karya Murni 2 0 5 17 0 0 13 11

39 KUD Karya Nata 0 0 10 0 0 0

40 KUD Maduratna 121 29 0 0 0 0

41 KUD Makmur 30 0 0 0 0 0

42 KUD Penerus Baru 17 0 0 0 0 0

43 KUD Toddopuli 0 0 0 0 0 0

132

Table 5.20 Coal Production by Company, 1999-June 2006 (Continued)

(Thousand ton) No. Company 1999 2000 2001 2002 2003 2004 2005 2006*

44 KUD Usaha Karya Cempaka 17 45 0 0 0 0

45 KUD Markulin 0 686

46 KUD Nusantara 182

47 KUD Tani Jaya Murni 99

Sub Total 257 199 15 17 0 967 13 11

Mining Authorization Holder

48 PT Alhasanie 117 -

49 PT Amanah Anugerah Adimulya 0 0 0 113 0 0

50 PT Anugerah Bara Kaltim 0 0 47 1,580 2,475 3,413 3,395 -

51 CV Balangan Putera 69

52 CV Bara Pinang Corporation 0 222

53 PT Baradinamika Muda Sukses 159 113 300 455 328 - 64 -

54 PT Berkelindo Jaya Pratama 36 0 0 0 0 0

55 PT Bina Mitra Sumberarta 169

56 PT Bukit Baiduri Enterprise 1,689 1,994 2,013 1,980 2,417 1,430 1,690 1,179

57 PT Bukit Bara Utama 140 83 103 76 102 96 88 27

58 PT Bukit Sunur 640 498 342 245 114 155 91 23

59 PT Bumi Dharma Kencana 271

60 PT Cenco International 180

61 PT Danau Mas Hitam 273 64 0 33 88 178 54 11

62 PT Fajar Bumi Sakti 187 155 297 100 50 153 328 - 63 PT Kalimantan Energi Utama 681

64 PT Karbindo Abesyapradi 491 121 306 268 55 34 -

65 PT Kimco Armindo 963

66 PT Kitadin Corporation 865 1,259 2,359 1,922 2,291 1,768 1,604 -

67 PT Kusuma Raya Utama 31

68 PT Mahakarya Ekaguna 186 -

69 PT Manunggal Inti Arthamas 308 -

70 PT Multi Prima Energi 259 -

71 PT Nusa Riau Kencana Coal 94 338 -

72 PT Restu Kumala Jaya 148 44 0 13 0 0

73 PT Sari Andara Persada 80 57 14 0 0 0

74 PT Satui Bara Tama 441

75 PT Surya Kencana Jorong Mandiri 27

76 PT Surya Sakti Darma Kencana 328

77 PT Tri Bhakti Sarimas 24

Sub Total 4,708 4,388 5,781 6,795 7,951 9,507 9,762 1,239

Grand Total 73,777 77,040 92,540 103,372 114,278 132,352 150,925 64,054 *until June 2006 Sources :

- Indonesia Mineral & Coal Statistics 2004, Directorate of Mineral and Coal Enterprises, Ministry of Energy and Mineral Resources

- Directorate of Mineral and Coal Enterprises, http://portal.dpmb.esdm.go.id

133

Table 5.21 Domestic Coal Sales by Company , 1998 -2004

(Thousand ton) No Company 1999 2000 2001 2002 2003 2004 2005 2006*

State Owned (Bukit Asam, PT) Bukit Asam - - - - - 2 7,151.01 3,370.17 1 Ombilin Mine 620 591 430 303 26 93 41.76 1.62

2 Tanjung Enim Mine (Steam) 8,920 8,442 7,825 7,290 7,631 7,117 - -

3 Tanjung Enim Mine (Anthracite) 67 32 21 28 4 - - -

Sub Total 9,607 9,065 8,276 7,621 7,661 7,210 7,192.77 3,371.79 Contractor 4 PT Adaro Indonesia 4,720 6,608 8,356 9,306 9,314 7,858 8,776.61 4,588.54 5 PT Allied Indo Coal - 156 121 200 118 193 - -

6 PT Antang Gunung Meratus 110 224 463 479 498 613 416.86 -

7 PT Arutmin Indonesia 108 16 257 495 245 920 4,576.81 138.46

8 PT Bahari Cakrawaia Sebuku 211 230 291 289 106 110 - -

9 PD Baramarta - - 177 - 695 1,047 398.14 - 10 PT Baramulti Suksessarana - - - 49 57 24.87 - 11 PT BerauCoal 1,197 1,429 1,798 1,813 2,324 2,971 3,752.96 1,379.25 Borneo Indobara - - - - - - - 213.62

12 PT Gunung Bayan Pratama Coal, - 54 97 - 3,343 2,594.06 1,053.51

13 PT lndominco Mandirt 54 38 149 38 - 95 46.79 -

14 PT Jorong Barutama Greston - 268 1,142 1,255 706 1,040 840.53 216.47

PT Kadya Caraka Mulia - - - - - - 167.42 - 15 PT Kaltim Prima Coal 625 512 647 558 572 551 - -

16 PT Kartika Selabumi Mining, - - 284 837 905.07 679.12

17 PT Kideco Jaya Agung 828 1,662 2,864 4,499 5,251 5,743 1,007.31 342.40 18 PT Lanna Harita Indonesia - - - - 79 57 6,353.88 2,584.59 19 PT Mandiri Intiperkasa - - - - - 16 - - 21 PT Multi Harapan Utama 848 901 936 688 423 299 242.32 187.59 Riau Bara Harum - - - - - - 68.40 -

22 PT Sumber Kurnia Buana - 423 406 847 932 587 497.65 - 23 PT Tanito Harum 38 130 115 82 - - 9.13 - 24 PT Tanjung Alam Jaya - 28 483 - 451 282 - - PT Trubaindo Coal Mining - - - - - - 1,171.44 544.51 Sub Total 8,739 12,679 18,302 20,549 22,047 26,620 32,856.35 11,928.06

Mining Authorization

25 PT Anugerah Bara Kaltim/Shawindo, - - - 174 158 3 - -

26 C V Balangan Putra, - - - - - 69 - -

27 C V Bara Pinang Corporation - - - - - 222 - -

28 PT Baradinamika Muda Sukses - - 232 455 369 - - -

29 PT Bukit Baiduri Enterprise 22 - 122 75 44 - - - 30 PT Bukit Bara Utama 2 - 5 - - - - - 31 PT Bukit Sunur 6 - 4 8 - 1 - - 32 PT Bumi Dharma Kencana - - - - - 271 - - 33 PT Cenco International - - - - - 180 - - 34 PT Danau Mashitam 9 32 - - - - 101.30 -

134

Table 5.21 Domestic Coal Sales by Company , 1998 -2004 (Continued)

(Thousand ton) No Company 1999 2000 2001 2002 2003 2004 2005 2006*

35 PT Fajar Bumi Sakti 137 86 95 62 36 - 188.17 -

36 PT Kalimantan Energi Utama - - - - 681 - -

37 PT Karbindo Abesyapradhi 253 115 206 107 77 - 56.43 - 38 PT Kilisuci Paramita - - - 10 - - - - 39 PT Kitadin Corporation 68 103 63 76 266 78 - - PT Maharya Eka Guna - - - - - 185.56 -

40 Nusa Riau Kencana Coal - - - - - 18 150.85 - 41 PT Kusuma Raya Utama - - - - - - - - 42 PT Restu Kumala Jaya 148 44 13 - - - - 43 PT Satui Bara Tama - - - - - 441 - -

44 PT Suiya Kencana Jorong Mandiri - - - - - 27 - -

45 PT Surya Sakti Darma Kemcana - - - - - 328 - -

Sub Total 645 380 727 980 950 2,319 1,309.66 10.50 Cooperative Unit 46 KOP Kary a Merdeka - - - - - - - - 47 KUD Karya Mumi 2 - 5 17 - - - 10.50 48 KUD KaryaNata - - 10 - - - - - 49 KUD Makmur 30 - - - - - - - 50 KUD Markufin - - - - - 686 - - 51 KUD Nusantara - - - - - 182 - - 52 KUD Tani Jaya Mumi - - - - - 107 - - Sub Total 32 - 15 17 - 975 - - Total 19,023 22,124 27,320 29,167 30,658 37,125 41,358.78 15,310.35 *until June 2006 Sources :

- Indonesia Mineral & Coal Statistics 2004, Directorate of Mineral and Coal Enterprises, Ministry of Energy and Mineral Resources


135

Table 5.22 Domestic Coal Sales by Industry, 1998-2004

(Thousand ton) 1998 1999 2001 2002 2003 2004

1. Coal-Fired Power Plant 10,622.94 13,576.45 17,977.00 18,414.47 22,995.61 22,882.19

CFPP Asam-Asam n.a n.a 488.15 568.44 568.00 554.31

CFPP Bukit Asam 1,200.03 1,213.17 1,153.97 1,057.56 1,142.65 1,090.77

CFPP Freeport n.a n.a 646.09 557.95 669.33 593.65

CFPP Newmont Minahasa n.a n.a 38.97 28.08 24.00 3.65

CFPP Newmont Nusa Tenggara n.a n.a 406.13 477.61 480.00 482.58

CFPP Ombilin (Sijantang) 137.43 125.1 374.89 105.36 229.58 182.64

CFPP Paiton 2,151.93 3,368.92 6,276.10 8,300.75 9,060.89 9,310.01

CFPP Suralaya 7,133.54 8,869.25 10,172.03 8,950.79 10,821.16 10,664.59

2. Cement Industry 1265.12 2032.34 5143.27 5911.06 4,773.62 5,549.31

PT Basowa Cement n.a 30.27 247.51 152.98 251.01 169.85

PT Indocement Cibinong 42.91 88.35 1352.14 1019.87 0.00 0.00

PT Indocement Cirebon 7.68 80.78 380.4 294.22 313.50 385.95

PT Indocement Citeureup n.a n.a 0 1019.87 800.92 1,184.56

PT Indocement Tarjun n.a n.a 341.51 370.12 269.56 368.41

PT Kodeco Cement 67.19 456.42 0 0 0.00 0.00

PT Semen Andalas 59.21 19.52 35.64 47.05 168.00 185.34

PT Semen Baturaja 68.7 62.37 71.34 103.36 94.01 129.08

PT Semen Cibinong 577.61 452.15 602.77 897.67 885.64 811.58

PT Semen Gresik 75.83 99.98 912.03 862.61 715.17 1,063.64

PT Semen Kupang 0 0 0 0 5.64 12.82

PT Semen Nusantara 14.85 177.26 0 0 0.00 0.00

PT Semen Padang 262.72 469.75 474.96 680.64 692.39 454.21

PT Semen Tonasa 88.43 95.5 724.96 462.7 577.78 783.87

3. Metallurgy 144.91 194.21 181.7 208.72 201.91 119.18

PT Antam Tbk. 32.77 20.78 13.6 120 62.27 46.27

PT Inco Tbk. 74.17 75.51 123.5 77.87 109.51 51.16

PT Kobatin 0 1.2 30.23 2.19 10.00 7.32

PT Newmont Sumbawa 0 70.97 0 0 0.00 0.00

PT Kobatin 24.52 16.94 0 0 0.00 0.00

PT Timah Tbk. 13.46 8.82 14.37 8.66 20.12 14.43

4. Pulp Industry 702.88 829.09 822.82 499.59 1,704.50 1,160.91

PT Indah Kiat 167.63 198.23 163.28 7.51 1,198.00 369.42

PT Indorayon Utama 21.35 2.27 0 8.36 8.36

PT Jaya Kertas 10.32 23.7 20.88 27.83 32.55 54.50

PT Tjiwi Kimia 503.57 604.9 638.65 455.88 473.95 728.63

5. Small Industry 0 0 0 0 0.00 0.00

6. Briquette 29.96 38.3 31.27 24.71 24.98 17.96

7. Others* 2,600.55 2,573.35 1,593.06 3,792.48 957.32 6,347.71

Total 15,366.36 19,243.75 25,749.12 28,851.02 30,657.94 36,077.26

Source : Indonesia Mineral & Coal Statistics 2004, Directorate of Mineral and Coal Enterprises, Ministry of Energy and Mineral Resources

136

Table 5.23 Coal Quality by Company

Parameter Calorific Value

Suphur Ash Total Moisture

Company

(Kcal/Kg) (%-adb) (%-adb) (%-ar)

Reference

STATE OWNED COMPANY

Tambang Batubara Bukit Asam Tbk. PT

Suralaya Coal (SRC) 5500-6500 0.15-1.47 3-15 18.28 PTBA.2005

Lumut Coal (LMC) 6500-7500 0.24-155 4-10 8-17 PTBA,2005

Antracite Coal (ANC) 7500-8000 0.57-179 6-20 2-8 PTBA.2005

Ombilin (OMB) 6800-7000 0.5 8 14 Max PTBA, 2005

CONTRACTOR

1. Adaro Indonesia, PT

Paringin 5900 0.1 1 23.5 OR IV, 2002

Tutupan 5850 0.1 0.8 24.5 QR IV, 2002

Wara 4395 0.15 1.4 34.1 QR IV, 2002

2. Allied Indo Coal, PT 6900-7200 0.8 10 4 WP&B 2003

3. Antang Gunung Meratut, PT

F.Tanjung 6500-6800 0.5-1 10-15 9-15 WP&B 2003

F.Warukin 5000-5500 0.1-0.5 10-15 9-15 WP&B 2003

4. Arutmin Indonesia, PT

Asam-asam 5000 0.15 3.9 23 Arutmin, 2002

Sarongga 6720 0.8 10 4.95 Arutmin, 2002

Satui 6800 0.8 8 7 Arutmin, 2002

Senakin Barat 6700 0.8-1.4 12 4.5 Arutmin, 2002

Senakin Timur 6700 0.8-1.4 12 4.5 Arutmin, 2002

5. Bahari Cakrawala Sebuku, PT 6260 0.83 8.97 7-12 WP&B 2003

6. Baramarta, PD 6400-7200 0.3-1.2 1-4 2-7 WP&B 2003

7. Baramulti Suksessarana, PT 5900-6500 0.4-1.3 1-4 3-8 WP&B 2003

8. Berau Coal, PT

Lati 5400 1 5 26 WP&B 2003

Binuang Blok 5 & 6 5900 0.6 5 18 WP&B 2003

Binuang Blok 7 5559 0.7 4,3 22.5 WP&B 2003

SambarataBlokA 6000 0.7 5 15 WP&B 2003

Birang 5550 0.99 4.43 18 Berau, 2002

9. Gunung Bayan Pratama, PT

Tlaga & Rusuh 5373-7870 0.25-2.70 1.8-18.22 4.20-9.90 QR I, 2002

10.lndominco Mandiri, PT

Seam O 6475 0.22 2.1 10.9 QR III, 2002

Seam l 5982 0.26 9.3 11.1 QR III, 2002

Seam 2 Selatan Barat 6250 0.19 1.9 11.7 QR III, 2002

Seam 4 Selatan Timur 6144 0.27 3 13.5 QR III, 2002

Seam 6 Selatan Timur 5993 0.28 2.4 15.9 QR III, 2002

Seam 11 Selatan Timur 6144 2.11 3 8 QR III, 2002

11. Jorong Barutama Greston, PT 5617 0.25 4.5 30.5 QR III, 2002

12. Kaltim Prima Coal,PT

Melawan West 5610 0.22 2.1 21.2 QR III, 2002

Melawan East 5610 0.22 2.1 21.2 QR III, 2002

Bendili 5940 0.21 3.2 7.2 QR III, 2002

Surya Pit 5940 0.21 3.2 7.2 QR III, 2002 Source: Indonesia Mineral & Coal Statistics 2004, Directorate of Mineral and Coal Enterprises, Ministry of Energy and Mineral Resources

137

Table 5.24 Electricity Production by Type of Power Plant of PLN, 1992 – 2005

(GWh)

Own Generated

Year Hydro Steam

Gas Turbine

Combined Cycle

Geothermal Diesel* Rented Sub

Total

Purchased Total

1992 8,787.64 22,565.72 2,688.91 1,775.27 1,083.74 3,977.55 - 40,878.83 837.42 41,716.25

1993 7,858.66 21,784.23 2,609.44 7,794.75 1,090.00 4,331.51 - 45,468.59 1,057.62 46,526.21

1994 7,042.75 21,581.41 1,013.13 14,228.37 1,601.76 4,599.00 - 50,066.42 1,411.94 51,478.36

1995 7,528.72 22,775.27 1,470.46 19,304.37 2,210.03 4,921.96 - 58,210.81 1,193.42 59,404.23

1996 8,118.17 25,506.45 1,299.06 23,043.91 2,352.35 5,410.31 - 65,730.25 1,656.29 67,386.54

1997 5,148.72 31,472.63 1,731.49 27,320.82 2,605.28 5,774.73 745.98 74,799.65 1,819.92 76,619.57

1998 9,649.00 30,512.37 1,395.50 24,940.78 2,616.80 5,306.55 543.61 74,964.61 2,938.76 77,903.37

1999 9,370.08 33,999.53 1,555.04 27,045.52 2,727.73 5,325.86 472.96 80,496.72 4,279.08 84,775.80

2000 9,109.94 38,428.70 1,251.63 26,396.74 2,648.54 5,667.97 686.63 84,190.15 9,135.14 93,325.29

2001 10,651.02 39,376.31 1,459.39 27,366.18 2,982.12 5,752.43 767.27 88,354.72 13,299.21 101,653.93

2002 8,833.57 39,031.98 2,228.75 28,802.77 3,186.98 5,984.59 1,224.60 89,293.24 19,066.61 108,359.85

2003 8,472.16 42,178.01 2,486.25 28,409.31 2,958.63 5,541.39 2,435.17 92,480.92 20,538.76 113,019.68

2004 8,942.79 41,645.42 3,179.33 30,700.30 3,146.54 5,498.34 3,078.45 96,191.17 24,053.14 120,244.31

2005 9,830.96 42,268.13 6,039.08 31,271.97 3,005.51 5,761.20*) 3,105.25 101,282.09 26,087.70 127,369.82 *) Include Gas Micro scale Power Plant, from 2004 Source: PLN Statistics, 2004, PT. PLN (Persero)

138

Table 5.25 Fuel Consumption for PLN Power Plant, 1989-2005

Natural Gas HSD IDO MFO Coal Year

(MMSCF) (Thousand liter) (Thousand liter) (Thousand liter) (ton)

1989/90 11,815 1,233,814 40,758 1,890,516 3,970,559

1990/91 13,301 1,666,565 70,776 2,817,275 4,572,306

1991/92 12,788 1,897,178 57,165 3,206,929 5,143,300

1992/93 12,788 2,478,317 82,245 3,267,068 5,143,300

1993/94 58,271 3,251,686 68,526 3,021,545 4,732,669

1994 160,705 1,882,862 45,041 1,865,637 5,530,066

1995 220,032 1,817,598 8,238 1,157,591 5,593,402

1996 433,003 2,220,784 15,505 1,111,006 7,966,656

1997 228,268 2,982,319 33,635 1,590,122 9,961,959

1998 78,547 2,856,272 26,440 1,253,285 10,634,490

1999 236,612 3,253,219 20,941 1,429,003 11,414,098

2000 228,883 3,141,917 23,145 1,858,568 13,135,583

2001 222,421 3,575,348 30,457 1,793,283 14,027,713

2002 192,927 4,625,521 40,682 2,300,603 14,054,377

2003 184,304 5,024,362 31,573 2,557,546 15,260,305

2004*) 176,436 6,299,706 36,935 2,502,598 15,412,738

2005*) 143,050 7,626,201 27,581 2,258,776 16,900,972 *) Include Gas Micro scale Power Plant, from 2004 Source: PLN Statistics 2004-2005, PLN (Persero)

Table 5.26 Own-Uses, Losses, and Factors in PLN Electricity, 1993-2005

Year Own Uses

(GWh)

Transmission Losses (GWh)

Distribution Losses (GWh)

Load Factor (%)

Capacity Factor (%)

Demand Factor (%)

1993/94 1,901.22 1,188.96 4,667.05 74.88 38.17 33.54

1994 1,990.87 1,416.93 4,957.59 68.01 39.89 38.06

1995 2,260.91 1,698.58 5,626.12 66.82 44.34 29.28

1996 2,588.33 1,825.40 5,882.49 68.59 47.75 29.46

1997 3,230.30 1,818.68 7,069.91 70.08 46.15 46.79

1998 3,218.68 1,755.24 7,462.54 68.90 43.21 46.63

1999 3,224.35 2,116.56 7,862.40 67.60 44.63 49.41

2000 3,416.13 2,307.77 8,175.10 69.54 46.29 49.31

2001 3,709.87 2,336.56 10,924.80 71.13 47.90 49.04

2002 3,767.51 2,706.61 14,521.74 72.10 48.28 49.11

2003 4,039.82 2,686.10 15,715.54 71.88 49.78 49.21

2004 5,824.43 2,711.49 10,420.45 72.64 51.14 49.36

2005 5,302.43 2,794.43 11,442.77 74.26 52.15 48.26

Source: PLN Statistics, 2004-2005, PT. PLN (Persero)

139

Table 5.27 Electricity Sold by PLN by Sector, 1996-2005

Year Industrial Sector

Residential Sector

Commercial Sector

Social Buildings

Government Buildings

Public Lighting Total

Number of customers 47,847 20,696,261 770,920 442,302 76,196 16,799 21,980,325

Energy Sales(MVA) 27,948.89 19,550.83 6,225.67 1,203.99 1,314.79 687.84 56,932.01 1996

Income (million Rp) 4,085,015.00 3,106,917.00 1,656,290.00 157,244.00 296,656.00 116,275.00 9,418,397.00


Energy Sales(MVA) 30,768.81 22,698.27 7,249.62 1,403.41 1,355.93 835.48 64,311.52 1997



Energy Sales(MVA) 27,995.54 24,865.45 8,655.96 1,417.41 1,383.28 943.77 65,261.41 1998



Energy Sales(MVA) 31,337,57 26,874,78 9,330.31 1,468.82 1,343.54 977.05 71,332.07 1999

Income (million Rp) 6,535,846 5,208,334 2,924,805 316,216 425,382 259,968 15,670,552

Number of customers 44,337 26,769,675 1,062,955 582,811 79,453 29,174 28,595,405

Energy Sales(MVA) 34,013.22 30,563.42 10,575.97 1,643.52 1,297.83 1,070.85 79,164.81 2000

Income (million Rp) 10,289,533 6,337,009 4,024,216 380,484 638,447 470,194 22,139.88

Number of customers 46,014.00 27,885,612 1,172,247 608,713 79,746 35,396 29,827,728

Energy Sales(MVA) 35,593.25 33,339.78 11,395.35 1,781.55 1,281.63 1,128.82 84,520.38 2001

Income (million Rp) 12,872,975 8,456,684 5,149,643 485,425 764,718 546,538 28,275,983


Energy Sales(MVA) 36,831.30 33,993.56 11,845.04 1,842.89 1,281.49 1,294.47 87,088.75 2002

Income (million Rp) 16,313,885 13,352,473 702,137 776,371 887,275 667,088 32,699,229

Number of customers 46.818 29.997.554 1.310.686 659.034 83.81 53.514 32.151.416

Energy Sales(MVA) 36.497 35.753 13.224 2.022 1.433 1.512 90.441 2003

Income (million Rp) 19.355.351 18.680.109 8.746.392 1.087.806 1.040.349 899.629 49.809.637

Number of customers 46.52 31.095.970 1.382.416 686.851 87.187 67.502 33.366.446

Energy Sales(MVA) 40.324 38.588 15.258 2.238 1.645 2.045 100.097 2004

Income (million Rp) 22.547.351 21.523.164 10.410.620 1.272.560 1.171.832 1.306.466 58.232.002


Energy Sales(MVA) 42,448 41,184 17,023 2,430 1,726 2,221 107,032 2005

Income (million Rp) 24,189,890 23,188,785 11,825,952 1,384,770 1,260,284 1,396,542 63,246,221

Source: PLN Statistics, 2004-2005, PT. PLN (Persero)

140

Tabel 5.28a Load Balance of PLN Electricity, 2003

(MW) PLN Unit/Province Installed

Capacity Load

Capacity Peak Load

Region of Naggroe Aceh. D 137.30 88.50 60.50 Regionof North Sumatera 0.40 0.40 0.30 Region of West Sumatera 41.60 33.10 30.10 Region of Riau 188.80 173.80 117.50 Region of South Sumatera, Jambi & Bengkulu North Sumatera 79.70 50.10 30.90 - South Sumatera 35.60 19.30 11.80 - Jambi 22.50 22.50 12.40 - Bengkulu 21.70 8.30 6.80 Region of Bangka Belitung 76.20 34.60 49.80 Regionof Lampung 12.50 5.10 10.70 Region of West Kalimantan 232.20 162.40 176.60 Region of South & Central Kalimantan 381.50 290.90 286.30 - Central Kalimantan 310.20 237.50 232.80 - South Kalimantan 71.30 53.40 53.50 Region of East Kalimantan 310.70 192.10 213.60 Region North, Central Sulawesi & Gorontalo 321.50 262.90 232.00 - North Sulawesi 155.80 148.00 134.50 - Gorontalo 39.50 34.80 26.10 - Central Sulawesi 126.20 80.20 71.30 Region of South & Southeast Sulawesi 461.50 384.70 472.10 - South Sulawesi 435.80 361.80 452.90 - South East Sulawesi 25.70 22.80 19.20 Region of Maluku 145.60 64.00 52.10 - Maluku 102.10 41.50 34.50 - North Maluku 43.50 22.50 17.60 Region of Papua 136.50 100.20 84.30 Distribution of Bali 4.10 2.20 1.30 Region of West Nusa Tenggara 146.00 99.10 101.10 Region of East Nusa Tenggara 125.40 69.20 57.40 PT PLN Batam 115.80 96.40 116.10 G & T Nothern Part of Sumatera 1,470.00 1,161.60 1,180.10 G & T Southern Part of Sumatera 1,328.70 1,201.40 990.40 Total Non Java 5,715.90 4,403.30 4,263.20 Distribution East Java 10.50 8.70 3.00 Distribution Central Java 0.60 0.50 0.20 - Central Java 0.40 0.30 0.20 - Yogyakarta 0.30 0.20 - Distribution West Java 0.80 0.70 0.60 - West Java 0.60 0.60 - - Banten 0.20 0.20 - Distribution Jaya & Tangerang - - - PT Indonesia Power 8,980.00 8,327.00 - PT PJB 6,495.50 6,039.00 - P3B - - 13,682.00 Total Java 15,490.40 14,375.90 13,685.80 Total Indonesia 21,206.30 18,779.20 17,949.10 Source : PLN Statistics, 2003 PT.PLN (Persero)

141

Tabel 5.28b Load Balance of PLN Electricity, 2004

(MW)

PLN Unit/Province Installed Capacity

Load Capacity

Peak Load

Region of Naggroe Aceh. D 142.30 73.08 48.37 Regionof North Sumatera 0.44 0.40 0.28 Region of West Sumatera 43.42 33.40 30.09 Region of Riau 187.52 176.70 171.32 Region of South Sumatera, Jambi & Bengkulu North Sumatera 78.25 53.84 34.51 - South Sumatera 34.08 24.99 12.48 - Jambi 22.52 16.25 13.46 - Bengkulu 21.65 12.60 8.57 Region of Bangka Belitung 85.24 63.21 56.57 Regionof Lampung 7.68 3.67 9.60 Region of West Kalimantan 239.51 239.67 230.50 Region of South & Central Kalimantan 396.28 280.27 235.05 - Central Kalimantan 312.50 220.42 191.62 - South Kalimantan 83.78 59.85 43.42 Region of East Kalimantan 336.34 223.28 213.62 Region North, Central Sulawesi & Gorontalo 343.81 271.83 242.02 - North Sulawesi 178.08 156.58 136.79 - Gorontalo 39.49 31.56 26.84 - Central Sulawesi 126.24 83.69 78.39 Region of South & Southeast Sulawesi 463.64 364.72 530.76 - South Sulawesi 384.69 308.32 482.84 - South East Sulawesi 78.95 56.40 47.92 Region of Maluku 169.82 82.15 52.12 - Maluku 116.44 55.39 34.51 - North Maluku 53.38 26.76 17.61 Region of Papua 139.23 98.71 90.16 Distribution of Bali 4.08 3.71 1.52 Region of West Nusa Tenggara 147.70 103.06 101.10 Region of East Nusa Tenggara 127.96 68.86 63.57 PT PLN Batam 137.50 78.80 130.50 PT PLN Tarakan 31.22 28.00 20.44 G & T Nothern Part of Sumatera 1,520.87 1,212.24 1,203.70 G & T Southern Part of Sumatera 1,370.04 1,180.04 1,028.39 Total Non Java 5,972.85 4,570.78 4,494.17 Distribution East Java 13.66 11.12 2.99 Distribution Central Java 0.64 0.21 - Central Java 0.38 0.20 - Yogyakarta 0.26 0.01 Distribution West Java 0.93 0.89 0.64 - West Java 0.71 0.71 - Banten 0.22 0.18 Distribution Jakarta Raya & Tangerang PT Indonesia Power 9,005.19 7,643.87 PT PJB 6,477.14 5,817.21 P3B 14,398.00 Total Java 15,497.56 13,473.09 14,401.84 Total Indonesia 21,470.41 18,043.87 18,896.01 Source : PLN Statistics, 2004 PT.PLN (Persero)

142

Table 5.28c Load Balance of PLN Electricity, 2005 (MW)

PLN Unit/Province Installed Capacity

Load Capacity

Peak Load

Region of Naggroe Aceh. D 143.92 78.23 39.77 Regionof North Sumatera 0.44 0.37 0.28 Region of West Sumatera 43.06 28.84 25.18 Region of Riau 161.27 121.88 99.96 Region of South Sumatera, Jambi & Bengkulu 79.13 48.28 33.02 - South Sumatera 36.38 24.77 8.50 - Jambi 16.65 13.42 14.88 - Bengkulu 26.11 10.09 9.64 Region of Bangka Belitung 94.59 55.66 57.25 Regionof Lampung 7.25 4.30 9.96 Region of West Kalimantan 283.69 166.63 191.40 Region of South & Central Kalimantan 398.72 334.18 323.40 - Central Kalimantan 313.57 262.29 218.97 - South Kalimantan 85.15 71.89 45.23 Region of East Kalimantan 297.61 205.76 250.71 Region North, Central Sulawesi & Gorontalo 353.78 258.56 249.42 - North Sulawesi 181.94 147.68 140.49 - Gorontalo 41.00 26.49 27.73 - Central Sulawesi 130.84 84.39 81.20 Region of South & Southeast Sulawesi 496.08 364.18 313.78 - South Sulawesi 416.99 306.83 276.89 - South East Sulawesi 79.08 57.35 36.89 Region of Maluku 207.34 114.18 77.60 Region of Papua 184.67 93.10 79.05 Distribution of Bali 5.58 3.60 1.99 Region of West Nusa Tenggara 147.46 105.13 117.98 Region of East Nusa Tenggara 151.71 77.31 66.59 PT PLN Batam 137.50 83.30 150.60 PT PLN Tarakan 31.64 24.80 25.50 G & T Nothern Part of Sumatera 1,524.05 1,215.24 1,203.70 G & T Southern Part of Sumatera 1,410.05 1,147.31 1,121.43 P3B Sumatra 0.00 0.00 0.00 Total Non Java 6,159.54 5,311.52 4,438.57 Distribution East Java 13.65 13.12 2.99 Distribution Central Java 0.64 0.00 0.21 - Central Java 0.38 0.00 0.20 - Yogyakarta 0.26 0.00 0.01 Distribution West Java 0.93 0.93 0.64 - West Java 0.71 0.71 0.00 - Banten 0.22 0.22 0.00 Distribution Jakarta Raya & Tangerang 0.00 0.00 0.00 PT Indonesia Power 9,005.19 7,574.53 0.00 PT PJB 6,477.14 5,778.28 0.00 P3B Java-Bali 0.00 0.00 0.00 Muara Tawar 858.00 858.00 14,821.00 Total Java 16,355.55 14,224.86 14,824.84 Total Indonesia 22,515.09 19,536.38 19,263.40 Source : PLN Statistics, 2005 PT.PLN (Persero)

143

VI. EXPORTS AND IMPORTS OF ENERGY IN INDONESIA


EXPORTS AND IMPORTS OF ENERGY

145

Table 6.1 Export of Energy, 1997 – 2005 Type of Export Unit 1997 1998 1999 2000 2001 2002 2003* 2004* 2005

Thousand Barrel 289,093.20 280,364.60 285,399.70 223,500.00 240,170.30 217,274.00 189,094.82 178,869.41 159,702.82 Crude Oil

and Condensate Million

US$ 5,479.90 3,444.90 4,949.50 6,282.50 5,619.20 4,929.00 5,401.60 6,472.98 8,194.66

Thousand Barrel 71,785.40 58,897.00 56,496.20 67,084.50 56,686.10 55,490.00 63,502.59 52,390.00 40,861.25

Refined Product Million

US$ 1,291.10 695.4 912.2 1,675.90 1,241.90 1,060.00 1,606.82 1,751.41 2,050.40

MMBTU 1,387,548,990 1,387,548,990 1,501,935,830 1,400,024,020.00 1,238,784,870.00 1,035,543,000.00 1,369,603,250.00 1,369,603,250.00 1,369,603,250.00 LNG

Million US$ 4,735.00 3,389.80 4,489.10 6,802.10 5,375.30 5,595.00 6,586.42 7,721.97 9,132.23

Piping Gas MMBTU - - - - 122,183,750.00 216,171,250.00 216,171,250.00 216,171,250.00 216,171,250.00

ton 2,132,917 1,761,304 1,745,383 1,306,318.00 1,484,484.00 1,268,000.00 1,106,424.23 1,034,270.06 1,066,391.80 LPG

Million US$ 516.2 257.1 339.2 393.70 388.60 412.00 329.48 356.81 475.11

Coal Thousand ton 41,726.00 47,626.00 55,301.00 58,460.00 65,281.00 74,177.93 85,681.00 93,758.81 106,206.74

- Unaudited: export 2005 (except coal) - Unaudited: export refined product 2003 - Export LNG value in Million US$ from 2001 not included exporting by pipeline

Sources:

- Embassy of the United States of America Jakarta, Petroleum Report Indonesia : 2002-2003, March 2004 - Indonesia Oil & Gas Statistics, 1995-2005 Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources - Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources - Directorate of Mineral and Coal Enterprises, http://www.dpmb.esdm.go.id - Energy News, http://www.usembassyjakarta.org

146

Table 6.2 Import of Energy, 1995 – 2005 Type of Import Unit 1995 1996 1997 1998 1999 2000 2001 2002 2003* 2004* 2005*

Thousand Barrels 68,326.90 71,791.00 62,881.90 72,475.90 84,692.00 79,978.10 112,878.10 124,147.70 137,126.65 148,489.59 118,302.86

Crude Oil Million

US$ 1,229.10 1,506.70 1,291.90 985.7 1,501.20 2,303.50 2,852.30 n.a 4,118.21 5,802.40 6,503.76

Thousand Barrels 45,019.20 60,905.80 94,994.20 54,053.80 79,902.00 87,001.60 89,622.10 106,927.60 101,598.51 122,598.45 158,625.33

Petroleum Fuels Million

US$ 978.8 1,576.90 2,296.80 803.4 1,656.30 2,889.90 2,577.40 n.a 3,317.94 5,750.80 10,353.91

n.a : not available * unaudited Sources:

- Directorate General of Oil & Gas, Oil & Gas Data Information, 6th Ed.,2002 - Embassy of the United States of America Jakarta, Petroleum Report Indonesia : 2002-2003, March 2004 - Indonesia Oil & Gas Statistics, 1995-2002, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources - Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

147

Table 6.3 Import of Crude Oil by Type, 2000 – 2005

(Barrel)

No. Products 2000 2001 2002 2003 2004 2005

1 ALC 36,182,304 40,005,584 34,472,549 41,339,170 37,879,588 39,370,973

2 Azeri 4,986,874

3 Bach Ho 3,025,964 6,518,473 3,548,095 3,384,571 7,510,042 3,631,646

4 Badin 2,406,380 385,893 1,505,789

5 Basrah 2,004,092

6 BBT 0 1,310,526 0

7 Bebatik 0 0 649,803

8 Bintulu 467,938 2,532,932 0

9 BIS 0 183,453 0

10 Ben Chamas 4,929,038 8,021,350 5,476,107

11 BLC 1,971,959 0 3,889,780

12 Bonny Light 0 10,443,068 7,786,978 3,840,495 5,681,711 7,699,300

13 Borrow Island 0 0 0

14 Brass River 0 925,751 6,568,639 2,775,547 1,017,610

15 Brunei LC/ Manis 599,590 0 0

16 Buanga Kekwa 346,330 588,013

17 Cham 0 601,527 0

18 Champion 2,088,406 6,948,114

19 Cooper Basin 0 0 0

20 Cossack 1,273,288 1,304,837 3,745,959

21 Daihung 1,170,657 0 0

22 Dulang 0 0 0

23 Escravos/ Forcados 12,784,351 1,797,312 3,827,392 947,148 9,554,088 947,142

24 Gippsland 0 0 0 1,354,504 1,309,311

25 Harriet/Varanus 0 0 0

26 ILC 3,667,594 5,538,619 0 1,888,712 0

27 Jabiru 0 0 0

28 Kitina 0 0 1,887,294

29 Kutubu 0 0 1,878,834 3,134,773 1,245,513 601,649

30 Labuan 2,222,325 0 5,203,485 6,345,155 2,903,545 1,745,498

31 LBN 1,754,336 0 0

32 Legendre 0 548,884 661,934 3,660,083 1,927,817

33 Marib Light 0 0 1,979,636 1,939,917 0

34 Masa 470,683 0 0

35 Miri 4,618,839 3,168,133 1,746,697 630,523

36 MLC 0 0 0

37 Mutineer Exeter 1,284,970

38 Nanhai 5,983,017 6,573,363 6,682,148 3,644,653 0 579,618

39 Nemba 2,943,342 7,720,215

40 Nice Blend 2,380,711

41 Nile Blend 0 0 810,351

42 North W.S. Cond 0 0 0 622,146

43 Odudu 0 7,625,225 9,446,665 10,486,526 0

44 Oman 0 0 2,096,636

148

Table 6.3 Import of Crude Oil by Type, 2000 – 2005 (Continued)

(Barrel) No. Products 2000 2001 2002 2003* 2004 2005 45 Palanca 995,309

46 Palm 0 989,121 0

47 PPT 0 479,466 0

48 QIB 0 4,740,697 0

49 Quaiboe/ Nile Blend 919,072 1,405,184 15,307,383 11,344,121 10,444,373 7,595,669

50 Rang dong 472,428 0 0 3,954,424 962,668 2,422,147

51 Ruby 470,849 0 674,655 1,026,698 1,102,195

52 Saharan 0 7,857,493 5,492,300 8,068,368 4,500,062 993,838

53 Sarir 0 0 989,185 3,646,681 0 1,037,908

54 Seria 0 0 659,917 3,674,660 5,229,287 13,459,632

55 Skua/ Griffin 0 0 0

56 Tantawan/Benchmas 2,544,149 4,474,390 4,182,342

57 Tapis 627,904 0 9,393,365

58 Thevarnard 0 0 0

59 Var 0 362,023 0

60 Wenchang 0 0 1,657,497 2,250,787 4,208,933 4,033,511

61 Xijiang 0 1,813,251 1,169,666 4,699,339 6,586,741 4,502,359

62 Zafiro 0 0 1,939,918 1,938,925 6,821,381

Total 81,732,435 110,908,272 125,905,217 137,126,653 147,299,540 118,302,860 Sources:

- Indonesia Oil and Gas Statistics, 1997-August 2003, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources


149

Table 6.4 Import of Refinery Products, 2000 – 2005

(Barrel) Products 2000 2001 2002 2003 2004 2005

Gas Oil 45,079,337 1,346,006 60,609,566 77,604,755 90,817,486

DPK 16,732,380 0 0

IDO 1,794,410.00 - - - - -

HSFO 12,477,236 58,649 0

Inco Fuel 0 0 0

IFO 12,712,611 189,615 0

Kerosene 19,624,012 17,219,590 17,100,258 14,284,537 13,594,785 16,378,352

Pygas 755,002.99 479,263.19 387,730.24 80,825.97 307,702 -

Fuel Oil 12,712,613 7,556,859 8,863,108 7,892,099 9,370,389 8,380,045

Avtur - 199,422 1,234,605 1,582,777 3,622,078 4,112,632

Avgas - 0 6,478 0 0 0

Premium 11,464,533 4,121,905 15,790,121 22,253,020 31,136,209 38,936,818

ADO 58,904,934.93 46,589,870.52 60,609,566.03 55,586,079.83 64,874,990.44 90,817,486.43

HOMC 90 - 2,579,433.50 574,303.96 200,000.00 - -

HOMC 92 - 4,397,958.96 2,028,530.00 4,111,473.44 678,070.20 3,036,698.31

HOMC 93 - - 8,472.00 - - -

HOMC 95 - 3,545,501.37 1,437,503.00 1,874,430.00 712,426.00 -

HOMC 97 - 105,000.00 - - 95,133.00 -

LPG - - - 1,881,808.94 369,011.08 250,509.08

Sources:



150

Table 6.5 Export of Crude Oil by Destination Country, 1997 – 2005

(Barrel) Country 1997 1998 1999 2000 2001 2002 2003 2004 2005

Arab Saudi 0 210,011 0 532,649 0 0 0 Australia 33,724,756 51,689,282 42,740,670 20,539,899 32,147,225 33,274,233 20,034,470 17,927,840 18,034,151

China 44,433,187 28,321,078 30,842,831 33,781,103 18,850,028 21,408,856 28,867,632 25,426,105 28,467,433

India 0 0 0 0 3,907,416 682,616 0 Japan 94,966,831 80,229,153 88,180,203 74,807,184 70,231,383 51,077,628 44,479,013 44,120,310 37,186,844

Korea 32,637,329 32,076,840 38,629,225 37,407,522 46,623,836 38,185,209 30,273,558 30,232,519 27,842,982

Malaysia 0 0 0 0 1,301,167 3,967,194 0 2,439,322 1,507,387

New Zealand 550,109 778,169 670,336 164,992 760,003 1,063,899 0 285,010 2,020,667

Philippines 2,937,395 1,013,748 420,006 1,110,426 1,145,719 410,338 0 278,005 0

Singapore 12,212,537 15,249,484 8,237,064 15,655,585 14,933,556 7,859,108 5,973,731 3,838,302 4,589,206

Taiwan 11,354,434 10,150,280 9,056,796 9,156,889 7,663,153 6,042,385 5,527,515 6,029,097 2,639,440

Thailand 8,470,324 2,684,514 5,549,786 9,932,728 3,876,493 6,089,605 5,858,688 6,293,551 5,721,285

USA 20,705,014 24,843,784 26,576,697 14,152,826 15,034,016 15,863,909 13,100,997 11,929,831 5,988,356

TOTAL 261,991,916 247,246,343 250,903,614 217,241,803 216,473,995 185,924,980 154,115,604 148,799,892 133,997,751

Sources:

- Indonesia Oil and Gas Statistics, 1997- 2004, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources - Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

151

Table 6.6 Export of Condensate by Destination Country, 1997 – 2005

(Barrel)

Country 1997 1998 1999 2000 2001 2002 2003 2004 2005

China 0 659,764 725,303 n.a 180,044 656,060 1,950,705 842,186

Japan 3,856,579 5,745,706 6,540,241 n.a 7,634,672 10,673,893 8,463,790 7,919,959 6,441,355

USA 0 0 262,462 n.a 314,997 0 0 267,503

Australia 3,076,121 283,498 662,672 n.a 3,416,633 1,194,532 2,160,068 2,502,397 1,760,278

Singapore 9,977,857 6,334,122 3,868,560 n.a 5,583,269 6,789,116 5,178,246 4,922,662 3,023,117

Korea 8,423,329 4,814,470 7,243,867 n.a 5,341,220 5,791,506 9,832,321 11,877,862 12,265,505

Thailand 454,490 355,003 1,052,351 n.a 1,619,498 4,468,747 5,036,350 2,847,039

Philippines 151,483 0 0 n.a 0 0 144,073

Taiwan 0 0 1,378,306 n.a 504,003 980,670 0

Arab Saudi 0 0 237,891 n.a 0 0 0

Malaysia 0 0 n.a 543,625 0 0 199,981

Vietnam 0 0 0 n.a 0 545,762 0

TOTAL 25,939,859 18,192,563 21,971,653 n.a 25,137,961 30,554,524 32,765,553 30,069,919 24,799,925 n.a. : not available Sources: - Indonesia Oil and Gas Statistics, 1997-2004, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources - Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources

152

Table 6.7 Export of Refinery Product, 1999– 2005

Products Unit 1999 2000 2001 2002 2003 2004 2005*

Thousand Barrel 0.00 n.a 0.00 0.00 n.a Avtur

Million US$ 0.00 n.a 0.00 0.00 n.a

Thousand Barrel 207.61 n.a 783.91 714.20 787.29 277.90 121.12 Benzene

Million US$ 1.32 n.a 25.86 23.69 54.71 20.22 12.80

Thousand Barrel 3,782.41 n.a 3,104.69 0.00 3,253.54 Decant Oil

Million US$ 48.49 n.a 49.32 0.00 136.89

Thousand Barrel 0.00 n.a 0.00 0.00 n.a Gas Oil

Million US$ 0.00 n.a 0.00 0.00 n.a

Thousand Barrel 1,135.06 n.a 2,622.42 1,654.38 2,638.35 2,589.62 2,014.20 Green Coke

Million US$ 5.70 n.a 16.75 13.89 22.19 22.76 26.59

Thousand Barrel 0.00 n.a 0.00 0.00 n.a IFO

Million US$ 0.00 n.a 0.00 0.00 n.a

Thousand Barrel 246.89 n.a 0.00 0.00 n.a JP-5

Million US$ 5.11 n.a 0.00 0.00 n.a

Thousand Barrel 0.00 n.a 0.00 3,253.18 2,813.23 4,939.94 n.a Light Fuel Oil

Million US$ 0.00 n.a 0.00 56.78 77.98 103.32 n.a

Thousand Barrel 517.34 n.a 611.50 0.00 n.a LOMC

Million US$ 10.61 n.a 14.41 0.00 n.a

Thousand Barrel 17,420.82 n.a 32,831.22 35,938.03 34,651.74 42,287.22 31,320.52 LSWR

Million US$ 267.24 n.a 707.99 640.62 928.71 1,091.84 1,389.59

Thousand Barrel 461.40 n.a 147.47 417.33 673.89 512.50 306.65 Lube Oil

Million US$ 14.77 n.a 6.34 10.32 31.24 23.10 21.66

Thousand Barrel 0.00 n.a 0.00 0.00 n.a Mixed Oil

Thousand US$ 0.00 n.a 0.00 0.00 n.a

Thousand Barrel 0.00 n.a 0.00 0.00 n.a Mogas

Million US$ 0.00 n.a 0.00 0.00 n.a

Thousand Barrel 8,772.29 n.a 13,448.37 10,993.31 18,715.00 11,763.13 6,531.06 Naphtha

Million US$ 145.33 n.a 330.76 235.42 528.08 361.22 305.47

Thousand Barrel 522.36 n.a 759.74 120.15 571.61 282.60 Paraxylene

Million US$ 18.28 n.a 40.59 5.40 41.66 30.15

Thousand Barrel 0.00 n.a 0.00 0.00 n.a Propylene

Million US$ 0.00 n.a 0.00 0.00 n.a

Thousand Barrel 69.34 n.a 738.56 689.69 552.78 367.98 620.99 PTA Slack

Million US$ 3.66 n.a 45.48 0.00 45.61 38.10 49.05

Thousand Barrel 146.57 n.a 10.26 0.00 Wax

Million US$ 0.28 n.a 10.57 0.00

Thousand Barrel 33,282.09 n.a 55,058.14 53,780.28 60,832.28 63,309.90 44,450.68 Total

Million US$ 520.79 n.a 1,248.06 986.11 1,688.52 1,702.21 1,972.19 Sources :

- Indonesia Oil and Gas Statistics, 1999 – 2004 Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources


153

Table 6.8 Export of Refinery Product by Destination Country, 1999 –2005

Country Unit 2000 2001 2002 2003* 2004* 2005

Thousand Barrel 16,153.07 13,838.41 9,918.86 11,184.91 21,305.87 25,244.87 Japan

Thousand US$ 419,959.44 n.a n.a 420,016.92 743,660.00 1,101,949.00 Thousand Barrel 2,315.99 1,452.22 386.93 3,012.90 2,198.40 405.91

USA Thousand US$ 56,191.33 n.a n.a 63,535.11 64,642.80 21,656.00 Thousand Barrel 17,807.07 15,903.10 10,140.84 6,870.05 6,390.16 3,938.87

Korea Thousand US$ 441,836.05 n.a n.a 210,131.36 204,859.29 156,020.00 Thousand Barrel 14,485.86 10,936.61 9,308.49 12,957.83 10,544.23 9,593.35

Singapore Thousand US$ 310,946.70 n.a n.a 311,725.76 358,890.66 403,858.00 Thousand Barrel 2,785.83 2,828.62 1,620.77 820.02 1,743.80 997.99

Taiwan Thousand US$ 83,640.60 n.a n.a 33,100.35 62,538.52 44,791.00 Thousand Barrel 1,251.40 1,843.90 1,892.46 3,019.26 418.90 426.36

Australia Thousand US$ 34,433.79 n.a n.a 14,641.31 17,144.12 12,959.00 Thousand Barrel 3,722.94 - 2,813.54 4,047.29 2,432.60

Italy Thousand US$ 89,388.22 n.a 108,329.93 79.94 Thousand Barrel 2,267.70 910.93 52.75 168.14 741.01

Thailand Thousand US$ 72,923.06 n.a n.a 11,659.29 48.59 Thousand Barrel 1,268.40 1,401.61 380.51 3,113.91 667.80 668.90

Malaysia Thousand US$ 43,733.65 n.a n.a 13,016.63 23,126.49 17,761.00 Thousand Barrel 5,026.20 3,260.54 3,657.31 4,290.52 1,880.55

India Thousand US$ 122,909.79 n.a n.a 120,635.01 47.80 Thousand Barrel 0.00 170.87 124.86 20.58

Pakistan Thousand US$ 0.00 n.a n.a 0.66 Thousand Barrel 0.00 2,641.23 1,542.14 5,625.52 3,927.78 1,867.05

China Thousand US$ 0.00 n.a n.a 156,214.73 126,749.11 78,720.00 Thousand Barrel 0.00 14.02 21.25

Bangladesh Thousand US$ 0.00 n.a 0.99 Thousand Barrel 0.00 16.48 667.68

Vietnam Thousand US$ 0.00 n.a 15,523.15 Thousand Barrel 0.00 124.86

France Thousand US$ 0.00 n.a Thousand Barrel 0.00 63.25

New Zealand Thousand US$ 0.00 n.a Thousand Barrel 0.00 252.12

Netherland Thousand US$ 0.00 2.55 Thousand Barrel 67,084.46 81,945.40 42,058.53 58,356.63 52,390.83

Total Thousand US$ 1,675,962.63 n.a n.a 1,615,592.03 1,771,849.99

n.a : Not Available * unaudited Source :



154

Table 6.9 Export of LNG by Destination Country, 1995 –2005

Year Unit Japan Taiwan Korea Total

MMBTU 833,187,850 103,696,260 350,051,820 1,286,935,930 1995

Thousand US$ 2,416,501.20 338,865.10 1,100,894.80 3,856,261.10

MMBTU 955,771,780 78,551,700 335,741,450 1,370,064,930 1996

Thousand US$ 3,245,789,90 296,632,80 1,187,732.60 1,187,732.60

MMBTU 936,317,800 78,987,070 372,244,120 1,387,548,990 1997

Thousand US$ 3,155,947.60 289,587,50 1,289,390.60 4,445,338.20

MMBTU 927,140,940 97,152,800 371,646,440 1,395,940,180 1998

Thousand US$ 2,228,695.70 262,750.90 898,348.90 3,389,795.50

MMBTU 958,654,880 110,519,060 423,761,890 1,492,935,830 1999

Thousand US$ 2,850,981.50 395,085.90 1,243,022.90 4,489,090.30

MMBTU 933,859,920 145,398,470 320,765,630 1,400,024,020 2000

Thousand US$ 4,532,123.50 781,701.25 1,488,294.53 6,802,119.28

MMBTU 870,978,110 212,323,430 155,483,330 1,238,784,870 2001

Thousand US$ n.a n.a n.a n.a

MMBTU 929,302,080 260,145,510 170,845,150 1,360,292,740 2002

Thousand US$ n.a n.a n.a n.a

MMBTU 923,706,740 182,881,450 263,015,060 1,369,603,250 2003*

Thousand US$ 4,330,218.65 964,364.13 1,291,839.80 6,586,422.58

MMBTU 841,968,900 205,826,130 274,620,250 1,322,415,280 2004*

Thousand US$ 4,623,436.50 1,388,643.68 1,709,887.43 7,721,967.60

MMBTU 738,644,920 186,263,540 292,920,730 1,217,829,190 2005*

Thousand US$ 4,945,590.08 1,682,790.65 250,384.90 9,132,229.78

* unaudited Sources :



155

Table 6.10 Export of LPG by Destination Country, 2000 – 2005 Country Unit 2000 2001 2002 2003 2004 2005

Thousand ton 944.00 1,169.10 880.30 882.31 891.59 865.65

Japan Million US$ 290.33 n.a n.a 266.27 308.29 392.69

Thousand ton 1.75 93.53 10.65 3.65 0.00 8.81

Taiwan Million US$ 0.48 n.a n.a 0.83 0.00 3.12

Thousand ton 151.76 21.76 243.35 81.97 45.76 85.58

China Million US$ 41.88 n.a n.a 23.80 15.06 34.39

Thousand ton 90.47 35.75 0.00 0.00 0.00 0.00

Hong Kong Million US$ 25.11 n.a n.a 0.00 0.00 0.00

Thousand ton 30.45 51.79 8.45 6.98 9.18 4.65

Australia Million US$ 8.47 n.a n.a 1.91 2.91 2.09

Thousand ton 0.00 18.19 16.52 21.71a) 0.00a) 0.00a)

Malaysia Million US$ 0.00 n.a n.a 5.482a) 0.00a) 0.00a)

Thousand ton 3.48 13.30 1.62 - - -

Singapore Million US$ 1.06 n.a n.a - - -

Thousand ton 31.47 17.12 57.26

Philippines Million US$ 10.33 n.a n.a

Thousand ton 0.00 0.00 0.00 0.00 0.00 0.00 Papua New Guinea Million US$ 0.00 n.a n.a 0.00 0.00 0.00

Thousand ton 0.00 3.31 1.75

Vietnam Million US$ 0.00 n.a n.a

Thousand ton 0.05 60.56 50.70 72.75 52.49 0.00

Domestic Million US$ 16.04 n.a n.a 20.24 17.77 0.00

Thousand ton 1,253.25 1,484.50 1,269.71 1,106.42 1,034.27 1,066.39

TOTAL Million US$ 393.71 n.a n.a 329.48 356.81 475.11 n.a : not available * unaudited a) Malaysia and Singapore Sources:

- Indonesia Oil and Gas Statistics, 1998 – August 2003, Directorate General of Oil and Gas, Ministry of Energy and Mineral Resources


156

Table 6.11 Coal Export by Company, 1999 – 2005 No. Company 1999 2000 2001 2002 2003 2004 2005 2006*

Government Company 1 PT Tambang Batubara Bukit Asam

- Bukit Asam 2,492 1,409

- Ombilin 502 172 34 0 - - - -

- Tanjung Enim 1,738 1,971 1,861 1,855 2,239 2,712 - -

Coal Contractors 2 PT Allied Indo Coal 432 38 0 0 0 0 0 0

3 PD Baramarta 0 0 27 460 - 1,049

4 PT Adaro 10,048 9,671 11,446 12,688 15,187 15,099 17,317 11,919

5 PT Arutmin Indonesia 7,089 9,303 9,247 9,858 13,772 13,796 12,517 7,125

6 PT Bahari Cakrawala Sebuku 1,379 1,328 1,584 1,715 1,885 2,696 2,823 971

7 PD Baramarta 719 1,049 95 -

8 PT Bentala Coal Mining 77 0 7 0

9 PT Berau Coal 2,091 3,344 4,835 5,072 5,349 6,160 5,763 2,645

10 PT BHP Kendilo Coal Indonesia 1,118 1,032 883 817 374 -

11 PT Gunung Bayan Pratama Coal 450 1,447 1,810 2,609 3,539 2 1,324 197

12 PT Indominco Mandiri 3,212 3,863 4,371 5,334 4,887 6,584 8,902 1,807

13 PT Jorong Barutama Greston 836 897 1,330 1,060 1,961 1,826 2,139 711

14 PT Kaltim Prima Coal 13,390 12,743 15,079 16,629 16,034 22,404 26,622 14,504

15 PT Kideco Jaya Agung 6,433 6,525 7,321 6,750 8,942 10,966 11,831 5

16 PT Lanna Harita Indonesia 0 0 99 831 1,194 1,480 1,733 696

17 PT Mandiri Intiperkasa - 352 1,021 204

18 PT Marunda Graha Minera - 295 788 295

19 PT Multi Harapan Utama 875 621 580 448 1,159 1,002 648 419

20 PT Tanito Harum 1,005 934 1,053 1,629 2,104 3,217 4,984 600

21 PT Tanjung Alam Jaya 0 0 0 636 0 34 - -

22 PT Trubaindo Coal Mining - - 389 1,034

Mining Authorisation Holder 23 PT Anugerah Bara Kaltim 0 0 0 1449 2,317 1,479 1,502 -

24 PT Anugerah Buana Bahari Abadi 0 0 48 0

25 PT Berkelindo Jaya Pratama 27 0 0 0

26 PT Berkelindo Jaya Pratama 308 249 0 0

27 PT Bukit Baiduri Enterprise 1663 1888 1998 1963 2,459 1,255 1,626 1,230

28 PT Bukit Bara Utama 126 89 71 47 108 83 74 24

29 PT Bukit Sunur 642 460 245 268 155 130 85 22

30 PT Danau Mas Hitam 272 154 0 27 49 197 84 7

31 PT Fajar Bumi Sakti 35 81 16 0 4 - 200 -

32 PT Karbindo Abesyapradi 232 73 128 155 - - - -

33 PT Kitadin - Tandung Mayang 0 339 0 0 1,934 864 1,047 -

34 PT Kitadin Corporation 785 815 1515 1859 28 - - -

35 PT Nusa Riau Kencana Coal 76 241 -

36 PT Restu Kumala Jaya 113 100 0 15

Cooperative Unit 37 KOP Teratai Putih 3 27 0 0

38 KOP Karya Merdeka 3 27 0 0

Total 54,884 58,191 65,628 74,174 85,681 93,759 106,767 51,231 Sources :

- Indonesia Mineral & Coal Statistics, 1997-2005 Directorate of Mineral and Coal Enterprises, Ministry of Energy and Mineral Resources


157

Table 6.12 Coal Export by Destination Country, 1999 – 2005

(Thousand ton)

Country 1999 2001 2002 2003 2004 2005 2006*

ASIA 43,678 47,164 60,236 66,158 Arab Saudi 0 0 38 68 - - - China 15 629 2,858 520 1,219 1,227 766 Hong Kong 2,510 4,662 5,564 9,178 8,230 8,970 4,605 India 2,345 3,130 4,586 6,700 5,465 8,740 5,207 Japan 13,170 15,216 16,530 17,992 19,013 24,237 9,543 Korea 9,964 4,254 Malaysia 1,960 2,098 6,239 3,823 4,315 3,977 1,842 Pakistan 41 251 280 Philippines 2,800 1,980 2,018 2,118 2,352 2,655 1,090 Singapore 101 71 489 488 684 1,280 373 South Korea 5,308 5,552 5,633 6,966 9,690 Srilangka 0 0 27 40 8 Taiwan 13,554 11,507 13,100 14,144 16,678 14,524 8,474 Thailand 1,916 2,318 3,155 4,075 2,217 4,256 1,884 Turkey 0 0 0 46 - EUROPE 6,882 10,227 9,936 12,787 Bulgaria 29 0 0 0 0 Croatia 0 0 642 420 199 65 - Denmark 0 0 297 0 0 Finland 0 132 130 120 - France 0 0 248 0 254 350 63 Germany 101 502 557 661 62 Greece 216 0 213 220 - Israel 466 Ireland 18 455 295 0 0 484 307 Italy 370 1,584 2,096 4,669 2,704 2,780 1,570 Netherlands 2,041 2,410 1,515 284 350 1,076 1,773 New Zealand 709 963 544 Portugal 0 948 444 231 - Scotland 0 0 0 0 0 Slovenia 550 563 71 0 230 405 287 Spain 2,872 3,203 3,001 2,926 3,007 3,653 1,921 Switzerland 562 379 357 2,266 4,039 4,287 1,356 United Kingdom 125 50 70 990 1,141 1,772 1,037 Australia-America 2,596 2,161 2,555 3,118 Australia 0 160 0 386 - Brazilian 398 284 356 344 439 146 - Canada 0 36 0 0 0 Chile 1,099 642 554 271 326 887 772 Peru 0 0 535 72 - USA 1,098 1,039 1,110 2,045 2,110 1,931 1,406 Others 2,161 5,730 1,451 3,618 7,809 8,425 2,143 Total 55,318 65,281 74,178 85,681 93,759 107,306 51,496 Sources :

- Indonesia Mineral & Coal Statistics, 1997-2004, Directorate of Mineral and Coal Enterprises, Ministry of Energy and Mineral Resources


159

VII. INFRASTRUCTURE OF ENERGY IN INDONESIA


INFRASTRUCTURE OF ENERGY

161

Table 7.1 Installed Capacities of Oil Refinery Plants, 1999 – 2005

(Barrel/Day)

Refinery Plant 1999 2000 2001 2002 2003 2004 2005

Pangkalan Brandan 5,000 5,000 5,000 5,000 5,000 5,000 5,000

Dumai 120,000 120,000 170,000 120,000 120,000 120,000 120,000

Sungai Pakning 50,000 50,000 50,000 50,000 50,000 50,000 50,000

Musi 135,200 135,200 133,700 135,200 135,200 135,200 135,200

Cilacap 348,000 348,000 348,000 348,000 348,000 348,000 348,000

Balikpapan 260,000 260,000 260,000 260,000 260,000 260,000 260,000

Cepu 3,800 3,800 3,800 3,800 3,800 3,800 3,800

Exor-1 Balongan 125,000 125,000 125,000 125,000 125,000 125,000 125,000

Kasim 10,000 10,000 10,000 10,000 10,000 10,000 10,000

Total 1,057,000 1,057,000 1,105,500 1,105,500 1,105,500 1,105,500 1,105,500 Sources:

- Oil & Gas Data & Information 2001, Directorate General of Oil & Gas, Department of Energy and Mineral Resources

- Pertamina Annual Report 1996/1997 - CIC Magazine No. 218,26 January 1999 - Directorate General of Oil & Gas, Department of Energy and Mineral Resources

Table 7.2a Fuel Oil Sales & Distribution Channels of Pertamina and Partner

No. Distribution Channel Unit

1 SPBU - Public Gas Station 2659

2 SPBI - Gas Fuel Distribution for Industry 8

3 SPBA - Fuel Distributor for Armed Forces 189

4 Kerosene Distributor 2728

5 SPBB - Fuel Distributor for Bunkers 58

6 PSPD - Premium Solar Packed Dealer 130

7 APMS - Automotive Diesel Oil Distributor 286

8 SPDN - Diesel Oil Dealer for Fisheries 30 Source: PERTAMINA Annual Report, 2003

162

Table 7.2b Non-Fuel Oil Sales & Distribution Channels of Pertamina and Partners

No. Distribution Channel Unit

1 Lubricans Distributors 224

2 Private lubricant Packages Factories 6

3 LPG Distributor 457

4 Asphalt Distributor 22

5 Tank Asphalt Distributor 50

6 Wax Distributor 32

7 Industrial Chemical Products Distributor 136

8 SPBG - LNG Filling Pump 28

9 LPG Station 18

10 SPBE - Bulk Elpiji Station & Transporter 44 Source: PERTAMINA Annual Report, 2003 Table 7.3 Oil Fuel Pipeline Location Distance (km) Diameter

Balongan - Jakarta 210 16” & 16” & 16”

Cilacap - Tasikmalaya 127 10” & 16”

Tasikmalaya - Padalarang 131 10” & 16”

Tasikmalaya – Ujung Berung 91 10” & 10”

Cilacap - Maos 20 10” & 12”

Maos - Rewulu 161 8” & 12” Source: PT Pertamina (Persero)

163

Table 7.4 Number of Oil Fuels Public Station and Kerosene Agents

OIL FUEL PUBLIC STATION KEROSENE AGENT

LOCATION PRIVATE PERTAMINA TOTAL AGENT TNI /

POLRI TOTAL (Unit) (Unit) (Unit) (Unit) (Unit) (Unit)

Aceh 49 0 49 29 0 29 North Sumatra 154 0 154 329 0 329 Riau 64 1 65 70 0 70 West Sumatra 54 0 54 112 0 112 Sub Total UPPDN I 321 1 322 540 0 540 South Sumatra 66 0 67 69 0 69 Jambi 30 0 30 19 0 19 Bengkulu 14 0 14 3 0 3 Lampung 66 0 66 49 0 49 Bangka Belitung 15 0 15 13 0 13 Sub Total UPPDN II 191 0 192 153 0 153 DKI.Jakarta 165 19 184 136 34 170 Banten 98 1 99 57 0 57 West Java 404 6 410 325 20 345 Sub Total UPPDN III 667 26 693 518 54 572 Central Java 225 0 225 196 0 196 Yogyakarta 97 0 97 77 0 77 Sub Total UPPDN IV 322 0 322 273 0 273 East Java 384 1 385 0 0 0 Bali 79 0 79 0 0 0 West Nusa Tenggara 18 1 19 0 0 0 East Nusa Tenggara 21 0 21 0 0 0 Sub Total UPPDN V 502 2 504 0 0 0 East Kalimantan 35 0 35 0 0 0 South Kalimantan 33 0 33 0 0 0 Central Kalimantan 18 0 18 0 0 0 West Kalimantan 31 0 31 0 0 0 Sub Total UPPDN VI 117 0 117 0 0 0 South Sulawesi 95 2 97 91 0 91 South East Sulawesi 10 0 10 17 0 17 Central Sulawesi 26 0 26 31 0 31 North Sulawesi 31 0 31 36 0 36 Sub Total UPPDN VII 162 2 164 175 0 175 Maluku 8 0 8 25 0 25 North Maluku 4 1 5 8 0 8 Papua 15 2 17 46 0 46 Sub Total UPPDN VIII 27 3 30 79 0 79 Grand Total 2,309 34 2,344 1,738 54 1,792 Source : PT Pertamina (Persero)

164

Table 7.5 Oil Fuel Storage Tanks of PT PERTAMINA (Persero) in Sumatera and Java

T O T A L Number of Tank Total Capacity Location

(Unit) (Kilo Liter) UPPDN I Medan - Transit Terminal 53 447,520 - Instalasi 30 145,700 - Seafed Depot 92 188,391 - Inland Depot 29 24,322 - DPPU 52 17,730 - Third Party 19 78809 Sub Total UPPDN I 275 902,472

UPPDN II Palembang - Seafed Depot 40 85,224 - Inland Depot 38 77,759 - DPPU 19 1,529 - Third Party 11 4,171 Sub Total UPPDN II 108 168,683

UPPDN III Jakarta - Transit Terminal 21 338,638 - Instalasi 13 126,417 - Seafed Depot 33 412,884 - Inland Depot 35 191,781 - DPPU 23 81,917 - Third Party 12 232,200 Sub Total UPPDN III 137 1,383,837

UPPDN IV Semarang - Transit Terminal 13 231,811 - Instalasi 22 94,580 - Inland Depot 63 196,794 - DPPU 18 1,423 - Third Party 8 126,000 Sub Total UPPDN IV 124 650,608

UPPDN V Surabaya - Transit Terminal 17 147,278 - Instalasi 74 466,196 - Seafed Depot 123 221,045 - Inland Depot 35 23,400 - DPPU 41 1,102 - Third Party 37 325,573 Sub Total UPPDN V 327 1,184,594 Source : PT Pertamina (Persero)

165

Table 7.6 Oil Fuel Storage Tanks of PT PERTAMINA (Persero) in Kalimantan, Sulawesi, and Papua

T O T A L Number of Tank Total Capacity Location

(Unit) (Kilo Liters) UPPDN VI Balikpapan - Seafed Depot 90 176,981 - Inland Depot 10 11,177 - DPPU 33 4,475 - Third Party 2 4,600 Sub Total UPPDN VI 135 197,233

UPPDN VII Makassar - Instalasi 20 55,409 - Seafed Depot 123 130,378 - DPPU 25 2,705 - Third Party 7 71,308 Sub Total UPPDN VII 175 259,800

UPPDN VIII Jayapura - Transit Terminal 12 137,217 - Seafed Depot 142 131,913 - DPPU 31 200 - Third Party 691 Sub Total UPPDN VIII 185 270,021 Sub Total Directorate PPDN 1,466 5,017,248 Sub Total Third Party 96 843,352 Grand Total 1,562 5,860,600 Source : PT Pertamina (Persero)

Table 7.7 Distribution Gas Pipeline of PT PGN (Persero) No. Location Length (km) Capacity (MMSCFD)

1 Medan 418 195

2 Palembang 72 0.8

3 Cirebon 331 6

4 Surabaya 509 212

5 Bogor 408 36

6 Jakarta 810 467 Source : PT Perusahaan Gas Negara (Persero), www.pgn.co.id

166

Table 7.8 Gas Pipeline No. Pipe Name Diameter

(inch) Length

(km) Capacity

(MMSCFD) Location Remark

Gathering Line

1. Offshore-Lhok Seumawe 30 109 1,000 Aceh LNG Plant

2. Onshore-Lhok Seumawe/Arun 16-42 30-34 200-2,000 Aceh LNG Plant/Industries

3. Badak-Bontang 42 57 2,000 East Kalimantan LNG Plant

4. Field-Badak-Bontang 20-36 10-70 300-1,500 East Kalimantan Gas Processing

5. Offshore-West Java 16-26 20-70 200-600 West Java Proc. Platform

6. Grissik Fields 16-26 13-50 200-600 South Sumatra To Sales Line

Sales Line

7. Offshore-T. Priok/Muara Karang 16-26 10-55 200-600 North of Java Power Plant

8. Cilamaya-Cilegon 24 220 500 West Java Industries

9. Pagerungan-Gresik 24-28 3-370 500-700 East Java Power Plant/Industries

10. Prabumulih-Palembang 20-28 15-50 300-500 South Sumatra Power Plant/Industries

11. Grissik-Duri 28 550 700 Sumatra Duri Steam Flood

12. Natuna-Singapore 16-28 10-470 200-700 South China Sea Export/Power Plant

13. Grissik-Sakeman 28 135 700 Riau Transmission

14. Sakeman-Batam-Singapore 28 335 700 Sumatra Export/Power Plant Source : Directorate General of Oil & Gas, Ministry of Oil and Gas

Table 7.9 Transacted Gas Pipeline Project in 2005 & 2006 No Projects Length Status

1 East kalimantan to Java gas transmision pipeline 1220 km Tendered on 29-12-2005

2 Semarang to Cirebon gas Transmission pipeline 230 km Tendered on 2-7-2005

3 Semarang to Gresik gas transmission pipeline 250 km Tendered on 2-7-2005

4 Duri-Dumai to Medan gas Transmission pipeline 529 km To be tendered in mid 2006

5 Cirebon to Muara Bekasi gas tranmission pipeline 220 km To be tendered in mid 2007

6 Sengkang to Mkassar gas transmision pipeline 274 km To be tendered at the end of 2006 Source: Petrominer, March 15 2006

167

Table 7.10 Design and Production Capacities of LNG Plant

(Million ton/year) Arun LNG Refinery Plant Badak LNG Refinery Plant

Capacity Capacity Train Design Production

Train Design Production

1 1,552 2,142 A 1,842 2,622 2 1,552 2,142 B 1,842 2,622 3 1,552 2,142 C 1,842 2,622 4 1,552 2,142 D 1,842 2,622 5 1,552 2,142 E 1,842 2,731 6 1,552 2,142 F 1,842 2,731

G 1,842 2,742 H 1,842 2,950

Total 9,312 12,852 18,088 21,642 Total Design Capacity 27,400

Total Production Capacity 34,294

Source : Directorate General of Oil and Gas, 2003, Ministry of Energy and Mineral Resources

Table 7.11 Main Coal Harbor

Terminal Location Operator Maximum

Vessel (DWT)

Stockyard (Thousand M. ton)

Sumatera Kertapati South Sumatera PT TB Bukit Asam 7,000 50,000 Pulau Bai South Sumatera Government of Indonesia 40,000 n.a Tarahan South Sumatera PT TB Bukit Asam 40,000 310,000 Teluk Bayur West Sumatera PT TB Bukit Asam 35,000 90,000 Kalimantan Tanjung Bara East Kalimantan PT Kaltim Prima Coal 180,000 500,000 Tanah Merah East Kalimantan PT Kideco 60,000 260,000 North Pulau Laut South Kalimantan PT Arutmin 150,000 500,000 Balikpapan East Kalimantan PT Dermaga Perkasa Pratama 80,000 800,000 Tanjung Redeb East Kalimantan PT Berau Coal 5,000 50,000 Beloro East Kalimantan PT Multi Harapan Utama 8,000 75,000 Loa Tebu East Kalimantan PT Tanito Harum 8,000 50,000 Tanjung Pemancingan South Kalimantan PT Arutmin 60,000 1,500,000 Sembilang South Kalimantan PT Arutmin 7,500 200,000 Air Tawar South Kalimantan PT Arutmin 7,500 200,000 Satui South Kalimantan PT Arutmin 5,000 150,000 Banjarmasin South Kalimantan Government of Indonesia 5,000 n.a Kelanis South Kalimantan PT Adaro 8,000 150,000 Indonesian Bulk Terminal South Kalimantan PT IBT 200,000 1,600,000 Java Terminal Batubara Indah West Java n.a 6,000 50,000 n.a : not available Source : Directorate General Mineral and Coal Enterprise, Ministry of Energy and Mineral Resources

168

Table 7.12 Number of PLN Power Plants, 1992 – 2005

(Unit)

Year Hydro Steam Gas Turbine

Combined Cycle Geothermal Diesel*) Total

1992 142 34 44 0 0 2,976 3,196

1993 149 34 45 12 3 3,126 3,369

1994 146 35 49 30 6 3,400 3,666

1995 154 36 41 33 6 3,646 3,916

1996 143 38 45 40 23 3,479 3,768

1997 154 38 50 40 6 3,683 3,971

1998 170 39 49 33 7 3,664 3,962

1999 177 39 49 50 7 3,731 4,053

2000 182 39 47 54 7 3,685 4,014

2001 186 41 47 54 8 3,837 4,173

2002 184 41 47 55 8 4,431 4,766

2003 185 40 47 56 8 4,543 4,879

2004 190 41 55 51 8 4,778 5,123

2005 191 41 60 51 8 4,859 5,210 *) Include Gas Micro scale Power Plant, from 2004 Source: PLN Statistics, 2004-2005, PT PLN (Persero)

169

Table 7.13 Installed and Rated Capacities of PLN Power Plants, 1992 – 2005

(MW)

Hydro Steam Gas Turbine Combined Cycle Geothermal Diesel*) Total % Year

Installed Rated Installed Rated Installed Rated Installed Rated Installed Rated Installed Rated Installed Rated Rated

1992 2,178.71 2,158.34 3,940.60 3,718.00 1,222.76 774.70 1,392.33 1,265.28 140.00 140.00 2,062.17 1,448.25 10,936.57 9,504.57 87%

1993 2,178.76 2,129.30 4,690.60 4,535.20 995.92 662.60 3,411.31 3,243.35 195.00 195.00 2,128.46 1,464.20 13,600.05 12,229.65 90%

1994 2,178.27 2,054.05 4,755.60 4,580.51 982.37 732.80 3,942.11 3,661.86 305.00 305.00 2,164.12 1,502.44 14,327.47 12,836.66 90%

1995 2,178.27 1,989.50 4,820.60 4,530.95 1,002.47 758.65 4,414.48 4,397.41 305.00 305.00 2,265.36 1,564.08 14,986.18 13,545.59 90%

1996 2,184.03 2,170.78 5,020.60 4,242.50 1,093.31 885.80 5,053.31 4,719.25 308.75 306.37 2,447.84 2,005.18 16,107.84 14,329.88 89%

1997 2,436.34 2,409.01 6,770.60 6,107.00 1,371.12 992.25 5,588.89 5,563.54 362.50 360.00 2,416.39 1,792.09 18,945.84 17,223.89 91%

1998 3,006.76 2,994.64 6,770.60 6,700.40 1,347.41 1,086.86 6,560.97 6,463.09 360.00 360.00 2,535.02 1,649.36 20,580.76 19,254.35 94%

1999 3,013.99 2,985.10 6,770.00 6,671.50 1,516.11 997.81 6,281.70 6,264.09 360.00 360.00 2,649.94 1,890.45 20,591.74 19,168.95 93%

2000 3,015.24 2,747.42 6,770.00 6,508.31 1,203.37 901.90 6,836.22 6,456.13 360.00 360.00 2,549.85 1,692.64 20,734.68 18,666.40 90%

2001 3,105.76 2,952.45 6,900.00 6,502.28 1,224.72 1,054.82 6,863.22 6,306.19 380.00 379.62 2,585.12 1,694.48 21,058.82 18,889.84 90%

2002 3,155.17 2,836.16 6,900.00 6,144.17 1,224.72 861.99 6,863.22 6,074.35 380.00 379.88 2,589.12 1,657.33 21,112.23 17,953.88 85%

2003 3,167.93 3,122.93 6,900.00 6,185.50 1,224.72 1,457.00 6,863.22 5,923.40 380.00 360,00 2,670.42 1,730.41 21,206.29 18,779.25

2004 3,199.44 2,991.63 6,900.00 5,934.52 1,481.57 1,435.89 6,560.97 5,609.65 395.00 359,16 2,933.43 1,713/02 21,470.41 18,043.87

2005 3,220.96 3,079.53 6,900.00 5,657.07 2,723.63 2,829.11 6,280.97 5,854.39 395.00 339.86 2,994.54 1,776.42 22,515.09 19,536.38 *) Include Gas Micro scale Power Plant, from 2004 Source: PLN Statistics, 2004-2005, PT PLN (Persero)

170

Tabel 7.14a Captive Power Plants, 2003

Number of Captive Power Plants/CP (Unit) Installed Capacity (kVA)

PLN Unit/Province Main CP

Reserved CP Total Main CP Reserved

CP Total

kVA from PLN Connected to Reserved CP

Region of Naggroe Aceh. D 95 167 262 515.718,00 54.718,00 569.900,00 26.381,00

Region of North Sumatera 70 76 146 116.575,00 116.575,00 212.073,00 210.265,00

Region of West Sumatera 141 97 238 134.541,40 134.541,40 190.390,50 134.571,00

Region of Riau 404 69 473 106.358,60 106.358,60 869.911,60 69.272,00 Region of South Sumatera, Jambi & Bengkulu

210 296 506 183.768,20 183.768,20 1.074.733,80 183.601,20

- South Sumatera 114 143 257 117.145,00 117.145,00 728.088,00 139.914,50 - Jambi 63 81 144 54.588,00 54.588,00 299.246,00 35.437,70 - Bengkulu 33 72 105 12.035,20 12.035,00 47.399,00 8.249,00 Region of Bangka Belitung 19 35 54 5.853,00 5.853,00 11.956,00 9.571,50

Regionof Lampung 109 113 222 114.179,25 114.179,25 254.559,35 82.315,00 Region of West Kalimantan 93 102 195 64.253,00 64.253,00 211.737,00 41.628,00

Region of South & Central Kalimantan 194 300 494 196.407,00 196.407,00 410.551,00 114.962,00

- South Kalimantan 117 226 343 168.824,00 168.824,00 327.634,00 100.750,00 - Central Kalimantan 77 74 151 27.583,00 27.583,00 82.917,00 14.212,00 Region of East Kalimantan 71 139 210 103.734,00 103.734,00 853.587,50 99.504,70

Region North, Central Sulawesi & Gorontalo 56 246 302 52.397,00 52.397,00 91.762,00 46.093,00

- North Sulawesi 15 123 138 36.120,00 36.120,00 48.590,00 33.933,00 - Gorontalo 7 26 33 5.313,00 5.313,00 23.028,00 4.923,00 - Central Sulawesi 34 97 131 10.964,00 10.964,00 20.144,00 7.237,00 Region of South & Southeast Sulawesi 96 312 408 68.086,00 68.086,00 96.958,00 67.240,00

- South Sulawesi 65 241 306 58.248,00 58.248,00 81.988,00 59.042,00 - South East Sulawesi 31 71 102 9.838,00 9.838,00 14.970,00 8.198,00 Region of Maluku - 99 99 16.711,67 16.711,67 16.711,67 18,96 - Maluku - 51 51 12.015,62 12.015,62 12.015,62 15,38 - North Maluku - 48 48 4.696,05 4.696,05 4.696,05 3,58 Region of Papua 19 146 165 20.402,70 20.402,70 41.443,03 19.140,10 Distribution of Bali 21 330 351 199.873,50 199.873,50 208.138,50 177.649,55 Region of West Nusa Tenggara 110 90 200 15.038,30 15.038,30 26.295,70 12.836,90

Region of East Nusa Tenggara 9 64 73 5.520,00 5.520,00 7.060,00 2.987,45

PT PLN Batam 35 - 35 - - 122.115,00 - Distribution East Java 264 309 573 171.173,05 427.373,68 598.546,73 1.856.417,40 Distribution Central Java 59 940 999 378.618,30 830.856,00 1.209.474,30 746.304,90

- Central Java 46 814 860 374.895,30 747.790,00 1.122.685,30 676.406,60 - Yogyakarta 13 126 139 3.723,00 83.066,00 86.789,00 69.898,30 Distribution West Java 351 1.228 1.579 1.242.306,00 1.359.482,00 2.601.788,00 1.359.482,00 - West Java 260 1.218 1.478 776.424,00 1.353.257,00 2.129.681,00 1.353.257,00 - Banten 91 10 101 465.882,00 6.225,00 472.107,00 6.225,00 Distribution Jaya & Tangerang 51 750 801 111.237,00 1.348.471,00 1.459.708,00 1.711.672,00

Total Indonesia 2.458 5.762 8.22 5.693.761,05 5.404.196,60 11.097.957,65 6.952.773,56 Source: PLN Statistics, 2003, PT PLN (Persero)

171

Tabel 7.14b Captive Power Plants, 2004



Reserved CP Total Main CP Reserved

CP Total


Region of Naggroe Aceh. D 95 167 262 522.78 54,718.00 55,240.78 26,381.00

Region of North Sumatera 65 64 129 67,876.00 144,858.00 212,734.00 210,265.00

Region of West Sumatera 77 222 299 53,094.50 75,244.50 128,339.00 141,414.00

Region of Riau 485 0 485 832,827.90 0.00 832,827.90 0.00 Region of South Sumatera, Jambi & Bengkulu

147 188 335 497,280.10 137,323.00 634,603.10 123,360.08

- South Sumatera 92 108 200 368,541.00 89,513.35 458,054.35 85,626.93 - Jambi 42 59 101 110,410.00 42,335.50 152,745.50 33,309.50 - Bengkulu 13 21 34 18,329.10 5,474.00 23,803.10 4,423.65 Region of Bangka Belitung 19 35 54 6,103.00 5,852.60 11,955.60 9,571.50

Regionof Lampung 126 50 176 118,219.00 47,106.00 165,325.00 103,109.50 Region of West Kalimantan 73 102 175 143,577.00 64,253.00 207,830.00 41,628.00

Region of South & Central Kalimantan 194 300 494 214,144.00 196,407.00 410,551.00 114,962.00

- South Kalimantan 117 226 343 158,810.00 168,824.00 327,634.00 100,750.00 - Central Kalimantan 77 74 151 55,334.00 27,583.00 82,917.00 14,212.00 Region of East Kalimantan 71 139 210 749,853.50 103,734.00 853,587.50 99,504.70

Region North, Central Sulawesi & Gorontalo 78 249 327 40,885.00 50,359.00 91,244.00 46,093.00

- North Sulawesi 43 140 183 12,944.00 37,396.00 50,340.00 33,933.00 - Gorontalo 8 35 43 18,250.00 4,511.50 22,761.50 4,923.00 - Central Sulawesi 27 74 101 9,691.00 8,451.50 18,142.50 7,237.00 Region of South & Southeast Sulawesi 90 330 420 26,507.00 75,444.45 101,951.45 63,926.98

- South Sulawesi 65 251 316 23,940.00 62,211.45 86,151.45 62,828.10 - South East Sulawesi 25 79 104 2,567.00 13,233.00 15,800.00 1,098.88 Region of Maluku 0 99 99 16,711.67 16,711.67 13,085.80 - Maluku 0 51 51 0.00 12,015.62 12,015.62 9,760.60 - North Maluku 0 48 48 0.00 4,696.05 4,696.05 3,325.20 Region of Papua 0 404 404 0.00 191,935.00 191,935.00 19,140.10 Distribution of Bali 21 330 351 8,265.00 199,873.50 208,138.50 177,649.55 Region of West Nusa Tenggara 110 90 200 11,257.40 15,038.30 26,295.70 12,836.90

Region of East Nusa Tenggara 11 117 128 4,740.00 6,798.60 11,538.60 3,574.00

PT PLN Batam 113 0 113 112,511.00 0.00 112,511.00 0.00 PT PLN Tarakan 6 25 31 10,281.60 3,613.40 13,895.00 6,878.51 Distribution East Java 262 332 594 514,024.00 493,499.00 1,007,523.00 232,314.50 Distribution Central Java 59 940 999 378,618.30 830,856.00 1,209,474.30 746,304.90

- Central Java 46 814 860 374,895.30 747,790.00 1,122,685.30 676,406.60 - Yogyakarta 13 126 139 3,723.00 83,066.00 86,789.00 69,898.30 Distribution West Java 1,228 1,579 2,807 1,359,482.00 2,601,787.50 3,961,269.50 1,359,482.00 - West Java 1,218 1,478 2,696 1,353,257.00 2,129,680.50 3,482,937.50 1,353,257.00 - Banten 10 101 111 6,225.00 472,107.00 478,332.00 6,225.00 Distribution Jaya & Tangerang 51 750 801 111,237.00 1,348,471.00 1,459,708.00 1,711,672.00

Total Indonesia 3,381 6,108 9,489 5,261,306.08 6,471,948.52 11,733,254.60 5,244,013.42

Source: PLN Statistics, 2004, PT PLN (Persero)

172

Table 7.14c Captive Power Plants, 2005



Reserved CP

Total Main CP Reserved

CP Total


Region of Naggroe Aceh. D 232 48 280 456,172.00 0.00 456,172.00 0.00

Region of North Sumatera 65 64 129 95,498.00 116,575.00 212,073.00 210,265.00

Region of West Sumatera 0 0 0 53,094.50 92,416.50 145,511.00 0.00

Region of Riau 107 481 588 830,159.00 118,273.00 948,432.00 118,273.00 Region of South Sumatera, Jambi & Bengkulu

210 296 506 890,965.00 183,768.20 1,074,733.20 0.00

- South Sumatera 114 143 257 610,943.00 117,145.00 728,088.00 0.00 - Jambi 63 81 144 244,658.00 54,588.00 299,246.00 0.00 - Bengkulu 33 72 105 35,364.60 12,035.20 47,399.80 0.00 Region of Bangka Belitung 0 0 0 0.00 0.00 0.00 0.00

Region of Lampung 0 95 95 0.00 131,031.00 131,031.00 46,073.00 Region of West Kalimantan 0 0 0 0.00 0.00 0.00 0.00

Region of South & Central Kalimantan 0 0 0 0.00 0.00 0.00 0.00

- South Kalimantan 0 0 0 0.00 0.00 0.00 0.00 - Central Kalimantan 0 0 0 0.00 0.00 0.00 0.00 Region of East Kalimantan 71 139 210 749,853.50 103,734.00 853,587.50 99,504.70

Region North, Central Sulawesi & Gorontalo 78 249 327 40,885.00 50,359.00 91,244.00 0.00

- North Sulawesi 43 140 183 12,944.00 37,396.00 50,340.00 0.00 - Gorontalo 8 35 43 18,250.00 4,511.50 22,761.50 0.00 - Central Sulawesi 27 74 101 9,691.00 8,451.50 18,142.50 0.00 Region of South & Southeast Sulawesi 90 325 415 27,152.00 77,037.00 104,189.00 1,166,143.80

- South Sulawesi 65 246 311 24,585.00 63,804.00 88,389.00 64,016.80 - South East Sulawesi 25 79 104 2,567.00 13,233.00 15,800.00 1,102,127.00 Region of Maluku 0 108 108 0.00 16,840.17 16,840.17 16,840.17 - Maluku 0 60 60 0.00 12,015.62 12,015.62 12,015.62 - North Maluku 0 48 48 0.00 4,824.55 4,824.55 4,824.55 Region of Papua 0 0 0 0.00 0.00 0.00 0.00 Distribution of Bali 21 330 351 8,265.00 199,873.50 208,138.50 177,649.55 Region of West Nusa Tenggara 52 78 130 17,245.12 15,205.30 32,450.42 0.00

Region of East Nusa Tenggara 12 118 130 1,870.00 8,586.50 10,456.50 3,512.50

PT PLN Batam 103 59 162 161,187.00 55,925.30 217,112.30 0.00 PT PLN Tarakan 3 33 36 3,211.60 18,198.50 21,410.10 0.00 Total Non Java 1,044 2,423 3,467 3,335,558.32 1,187,822.97 4,523,381.29 1,838,261.72 Distribution East Java 266 995 1,261 512,000.00 793,000.00 1,305,000.00 799,000.00 Distribution Central Java & Yogyakarta 0 0 0 0.00 0.00 0.00 0.00

- Central Java 0 0 0 0.00 0.00 0.00 0.00 - Yogyakarta 0 0 0 0.00 0.00 0.00 0.00 Distribution West Java & Banten 0 0 0 0.00 0.00 0.00 0.00

- West Java 0 0 0 0.00 0.00 0.00 0.00 - Banten 0 0 0 0.00 0.00 0.00 0.00 Distribution Jaya & Tangerang 51 750 801 111,237.00 1,348,471.00 1,459,708.00 1,711,672.00

Total Java 317 1,745 2,062 623,237.00 2,141,471.00 2,764,708.00 2,510,672.00 Total Indonesia 1,361 4,168 5,529 3,958,795.32 3,329,293.97 7,288,089.29 4,348,933.00 Source: PLN Statistics, 2005, PT PLN (Persero)

173

VIII. SELECTED WORLD ENERGY STATISTICS


SELECTED WORLD ENERGY STATISTICS

175

Table 8.1 World Oil Proven Reserves; 1985, 1995, 2004, 2005

(Thousand Million Barrels)

at end

1985 at end

1995 at end

2004 at end

2005 2005 Share of

Total R/P Ratio

USA 36.4 29.8 29.3 29.3 2.4% 11.8 Canada 9.6 10.5 16.5 16.5 1.4% 14.8 Mexico 55.6 48.8 14.8 13.7 1.1% 10.0 Total North America 101.5 89.0 60.6 59.5 5.0% 11.9 Argentina 2.2 2.4 2.3 2.3 0.2% 8.7 Brazil 2.2 6.2 11.2 11.8 1.0% 18.8 Colombia 1.2 3.0 1.5 1.5 0.1% 7.3 Ecuador 1.1 3.4 5.1 5.1 0.4% 25.6 Peru 0.6 0.8 1.1 1.1 0.1% 27.1 Trinidad & Tobago 0.6 0.7 0.8 0.8 0.1% 13.0 Venezuela 54.5 66.3 79.7 79.7 6.6% 72.6 Other S. & Cent. America 0.5 1.1 1.3 1.3 0.1% 24.8 Total S. & Cent. America 62.9 83.8 103.0 103.5 8.6% 40.7 Azerbaijan n.a n.a 7.0 7.0 0.6% 42.4 Denmark 0.4 0.9 1.3 1.3 0.1% 9.3 Italy 0.6 0.7 0.8 0.7 0.1% 17.0 Kazakhstan n.a n.a 39.6 39.6 3.3% 79.6 Norway 5.6 10.8 9.7 9.7 0.8% 8.9 Romania 1.4 1.0 0.5 0.5 � 11.3 Russian Federation n.a n.a 72.4 74.4 6.2% 21.4 Turkmenistan n.a n.a 0.5 0.5 � 7.8 United Kingdom 5.6 4.5 4.0 4.0 0.3% 6.1 Uzbekistan n.a n.a 0.6 0.6 � 12.9 Other Europe & Eurasia 65.0 63.6 2.2 2.2 0.2% 12.9 Total Europe & Eurasia 78.6 81.5 138.7 140.5 11.7% 22.0 Iran 59.0 93.7 132.7 137.5 11.5% 93.0 Iraq 65.0 100.0 115.0 115.0 9.6% * Kuwait 92.5 96.5 101.5 101.5 8.5% * Oman 4.1 5.2 5.6 5.6 0.5% 19.6 Qatar 4.5 3.7 15.2 15.2 1.3% 38.0 Saudi Arabia 171.5 261.5 264.3 264.2 22.0% 65.6 Syria 1.5 2.6 3.2 3.0 0.2% 17.5 United Arab Emirates 33.0 98.1 97.8 97.8 8.1% 97.4 Yemen 0.1 0.1 2.9 2.9 0.2% 18.3 Other Middle East 0.2 0.1 0.1 0.1 � 4.6 Total Middle East 431.3 661.5 738.2 742.7 61.9% 81.0 Algeria 8.8 10.0 11.8 12.2 1.0% 16.6 Angola 2.0 3.1 9.0 9.0 0.8% 19.9 Chad - - 0.9 0.9 0.1% 14.3 Rep. of Congo (Brazzaville) 0.8 1.3 1.8 1.8 0.1% 19.3 Egypt 3.8 3.8 3.6 3.7 0.3% 14.6 Equatorial Guinea - 0.6 1.8 1.8 0.1% 13.6 Gabon 0.7 1.5 2.2 2.2 0.2% 25.8 Libya 21.3 29.5 39.1 39.1 3.3% 63.0 Nigeria 16.6 20.8 35.9 35.9 3.0% 38.1 Sudan 0.3 0.3 6.4 6.4 0.5% 46.3 Tunisia 1.8 0.4 0.7 0.7 0.1% 25.2 Other Africa 1.0 0.7 0.6 0.6 � 12.0 Total Africa 57.0 72.0 113.8 114.3 9.5% 31.8 Australia 2.9 4.0 4.0 4.0 0.3% 20.0 Brunei 1.4 1.1 1.1 1.1 0.1% 14.9 China 17.1 16.3 16.0 16.0 1.3% 12.1 India 3.8 5.5 5.6 5.9 0.5% 20.7 Indonesia 9.2 5.0 4.3 4.3 0.4% 10.4 Malaysia 3.5 5.2 4.3 4.2 0.3% 13.9 Thailand 0.1 0.3 0.5 0.5 � 5.2 Vietnam - 0.8 3.1 3.1 0.3% 21.8 Other Asia Pacific 1.1 1.0 0.8 1.0 0.1% 13.2 Total Asia Pacific 39.1 39.2 39.8 40.2 3.4% 13.8 TOTAL WORLD 770.4 1027.0 1194.1 1200.7 100.0% 40.6

Source : BP Statistical Review of World Energy June 2006

176

Table 8.2 World Oil Production, 2000 – 2005

(Thousand barrels daily) 2000 2001 2002 2003 2004 2005 USA 7,733 7,669 7,626 7,400 7,228 6,830 Canada 2,721 2,677 2,858 3,004 3,085 3,047 Mexico 3,450 3,560 3,585 3,789 3,824 3,759 Total North America 13,904 13,906 14,069 14,193 14,137 13,636 Argentina 819 830 818 806 754 725 Brazil 1,268 1,337 1,499 1,555 1,542 1,718 Colombia 711 627 601 564 551 549 Ecuador 409 416 401 427 535 541 Peru 100 98 98 92 94 111 Trinidad & Tobago 138 135 155 164 152 171 Venezuela 3,239 3,141 2,916 2,607 2,972 3,007 Other S. & Cent. America 130 137 152 153 144 142 Total S. & Cent. America 6,813 6,721 6,640 6,367 6,745 6,964 Azerbaijan 281 300 311 313 317 452 Denmark 363 348 371 368 390 377 Italy 88 79 106 107 105 118 Kazakhstan 744 836 1,018 1,111 1,297 1,364 Norway 3,346 3,418 3,333 3,264 3,188 2,969 Romania 131 130 127 123 119 114 Russian Federation 6,536 7,056 7,698 8,544 9,287 9,551 Turkmenistan 144 162 182 202 193 192 United Kingdom 2,667 2,476 2,463 2,257 2,028 1,808 Uzbekistan 177 171 171 166 152 126 Other Europe & Eurasia 466 466 501 509 496 463 Total Europe & Eurasia 14,942 15,443 16,281 16,965 17,572 17,534 Iran 3,818 3,730 3,414 3,999 4,081 4,049 Iraq 2,583 2,376 2,035 1,339 2,010 1,820 Kuwait 2,104 2,070 1,995 2,329 2,481 2,643 Oman 959 961 900 823 785 780 Qatar 855 854 783 917 990 1,097 Saudi Arabia 9,511 9,263 8,970 10,222 10,588 11,035 Syria 548 581 545 562 529 469 United Arab Emirates 2,626 2,534 2,324 2,611 2,656 2,751 Yemen 450 455 457 448 420 426 Other Middle East 48 47 48 48 48 48 Total Middle East 23,501 22,871 21,471 23,296 24,588 25,119 Algeria 1,578 1,562 1,680 1,852 1,946 2,015 Angola 746 742 905 885 986 1,242 Cameroon 88 81 75 68 62 58 Chad - - - 24 168 173 Rep. of Congo (Brazzaville) 275 271 258 243 240 253 Egypt 781 758 751 749 721 696 Equatorial Guinea 117 173 210 234 329 355 Gabon 327 301 295 240 235 234 Libya 1,469 1,421 1,374 1,486 1,607 1,702 Nigeria 2,155 2,274 2,103 2,263 2,502 2,580 Sudan 174 211 233 255 325 379 Tunisia 78 71 75 68 72 74 Other Africa 56 53 63 71 75 72 Total Africa 7,844 7,918 8,022 8,438 9,266 9,835 Australia 809 733 731 624 541 554 Brunei 193 203 210 214 211 206 China 3,252 3,306 3,346 3,401 3,481 3,627 India 780 780 801 798 816 784 Indonesia 1,456 1,389 1,288 1,183 1,152 1,136 Malaysia 754 748 785 831 857 827 Thailand 164 174 191 223 220 276 Vietnam 328 350 354 364 427 392 Other Asia Pacific 200 195 193 195 186 199 Total Asia Pacific 7,936 7,877 7,899 7,832 7,890 8,000 TOTAL WORLD 74,941 74,736 74,382 77,091 80,198 81,088 Includes crude oil, shale oil, oil sands and NGLs (natural gas liquids - the liquid content of natural gas where this is recovered separately). Source : BP Statistical Review of World Energy June 2006

177

Table 8.3 World Oil Consumption, 2000 – 2005

(Thousand barrels daily) 2000 2001 2002 2003 2004 2005 USA 19,701 19,649 19,761 20,033 20,732 20,655 Canada 1,937 2,023 2,067 2,132 2,248 2,241 Mexico 1,884 1,899 1,837 1,885 1,898 1,978 Total North America 23,522 23,571 23,665 24,050 24,877 24,875 Argentina 431 405 364 372 394 421 Brazil 1,855 1,896 1,853 1,785 1,776 1,819 Chile 236 230 228 229 244 257 Colombia 232 245 222 222 223 230 Ecuador 129 132 131 137 144 148 Peru 155 148 147 140 152 139 Venezuela 496 545 594 479 525 553 Other S. & Cent. America 1,126 1,138 1,149 1,173 1,188 1,208 Total S. & Cent. America 4,661 4,739 4,688 4,537 4,647 4,776 Austria 244 265 271 293 285 294 Azerbaijan 123 81 74 86 92 103 Belarus 143 149 145 152 153 137 Belgium & Luxembourg 702 669 691 748 785 809 Bulgaria 84 87 88 98 102 109 Czech Republic 169 178 174 185 203 211 Denmark 215 205 200 193 189 189 Finland 224 222 226 239 224 233 France 2,007 2,023 1,967 1,965 1,978 1,961 Germany 2,763 2,804 2,714 2,664 2,634 2,586 Greece 406 411 414 404 435 429 Hungary 145 142 140 132 136 151 Iceland 19 18 19 18 20 19 Republic of Ireland 170 185 182 178 185 196 Italy 1,956 1,946 1,943 1,927 1,873 1,809 Kazakhstan 158 186 193 183 188 208 Lithuania 49 56 53 51 54 57 Netherlands 897 942 952 962 1,003 1,071 Norway 201 213 208 219 210 213 Poland 427 415 420 435 460 478 Portugal 324 327 338 317 322 320 Romania 203 217 226 199 230 240 Russian Federation 2,583 2,566 2,606 2,645 2,714 2,753 Slovakia 73 68 76 71 68 73 Spain 1,452 1,508 1,526 1,559 1,593 1,618 Sweden 318 318 317 332 319 315 Switzerland 263 281 267 259 258 262 Turkey 677 645 656 668 688 650 Turkmenistan 79 83 86 95 103 110 Ukraine 255 273 278 286 293 294 United Kingdom 1,697 1,697 1,693 1,717 1,764 1,790 Uzbekistan 138 135 130 148 155 161 Other Europe & Eurasia 402 427 453 475 482 502 Total Europe & Eurasia 19,564 19,743 19,726 19,903 20,195 20,350 Iran 1,319 1,331 1,429 1,513 1,575 1,659 Kuwait 202 206 222 238 266 280 Qatar 44 54 79 77 84 98 Saudi Arabia 1,536 1,551 1,572 1,684 1,805 1,891 United Arab Emirates 255 292 320 333 355 376 Other Middle East 1,379 1,421 1,425 1,394 1,407 1,436 Total Middle East 4,735 4,854 5,047 5,238 5,492 5,739

178

Table 8.3 World Oil Consumption, 2000 – 2005 (Continued)

(Thousand barrels daily) 2000 2001 2002 2003 2004 2005 Algeria 192 200 222 231 240 254 Egypt 564 548 534 550 567 616 South Africa 475 488 501 513 523 529 Other Africa 1,226 1,239 1,254 1,274 1,315 1,363 Total Africa 2,458 2,475 2,511 2,568 2,646 2,763 Australia 837 845 846 851 856 884 Bangladesh 66 80 80 78 80 82 China 4,772 4,872 5,288 5,803 6,772 6,988 China Hong Kong SAR 201 243 268 269 314 285 India 2,254 2,284 2,374 2,420 2,573 2,485 Indonesia 1,049 1,088 1,115 1,132 1,150 1,168 Japan 5,577 5,435 5,359 5,455 5,286 5,360 Malaysia 441 448 489 480 493 477 New Zealand 134 136 141 148 150 152 Pakistan 373 366 357 321 325 353 Philippines 348 347 332 330 336 314 Singapore 654 716 699 668 748 826 South Korea 2,229 2,235 2,282 2,300 2,283 2,308 Taiwan 816 819 844 868 880 884 Thailand 725 701 766 836 913 946 Other Asia Pacific 363 383 406 400 427 445 Total Asia Pacific 20,839 20,998 21,644 22,359 23,586 23,957 TOTAL WORLD 75,779 76,379 77,280 78,655 81,444 82,459 Source : BP Statistical Review of World Energy June 2006

179

Table 8.4 World Oil Refinery Capacities, 2000 – 2005

Thousand barrels daily 1997 1998 1999 2000 2001 2002 2003 2004 2005 USA 15,711 16,261 16,512 16,595 16,785 16,757 16,894 17,125 17,335 Canada 1,811 1,844 1,861 1,861 1,917 1,923 1,959 1,915 1,927 Mexico 1,449 1,449 1,449 1,481 1,481 1,463 1,463 1,463 1,463 Total North America 18,971 19,554 19,822 19,937 20,183 20,143 20,316 20,503 20,725 Argentina 653 650 645 626 614 611 611 611 611 Brazil 1,739 1,750 1,845 1,863 1,823 1,868 1,940 1,940 1,940 Neth. Antilles & Aruba 545 545 545 545 545 545 545 545 570 Venezuela 1,192 1,199 1,222 1,280 1,277 1,277 1,277 1,277 1,357 Other S. & Cent. America 2,269 2,180 2,224 2,230 2,219 2,266 2,240 2,254 2,285 Total S. &. Cent. America 6,398 6,324 6,481 6,544 6,478 6,567 6,613 6,627 6,763 Belgium 698 732 736 770 785 803 805 782 778 France 1,872 1,918 1,933 1,984 1,961 1,987 1,967 1,977 1,978 Germany 2,170 2,206 2,240 2,262 2,274 2,286 2,304 2,314 2,322 Greece 403 403 403 403 412 412 412 412 412 Italy 2,243 2,271 2,294 2,294 2,294 2,294 2,294 2,294 2,294 Netherlands 1,196 1,196 1,212 1,212 1,233 1,237 1,237 1,239 1,242 Norway 308 310 323 318 307 310 310 310 310 Russian Federation 5,929 5,533 5,399 5,351 5,304 5,372 5,407 5,412 5,412 Spain 1,265 1,247 1,247 1,247 1,247 1,333 1,333 1,358 1,363 Sweden 422 422 422 421 422 422 422 421 422 Turkey 713 713 713 713 713 713 713 693 613 United Kingdom 1,823 1,848 1,777 1,778 1,769 1,785 1,813 1,843 1,848 Other Europe and Eurasia 6,135 6,090 5,996 5,890 5,901 5,975 6,038 6,015 6,036 Total Europe and Eurasia 25,177 24,889 24,695 24,643 24,622 24,929 25,055 25,070 25,030 Iran 1,387 1,492 1,574 1,574 1,574 1,574 1,584 1,624 1,684 Iraq 634 634 634 639 644 644 644 644 644 Kuwait 880 895 895 690 745 770 905 905 915 Saudi Arabia 1,704 1,762 1,838 1,846 1,861 1,861 1,911 2,061 2,061 United Arab Emirates 298 235 290 440 674 711 645 620 620 Other Middle East 1,164 1,169 1,175 1,173 1,164 1,254 1,255 1,255 1,255 Total Middle East 6,067 6,187 6,406 6,362 6,662 6,814 6,944 7,109 7,179 Total Africa 2,928 2,881 2,983 3,034 3,217 3,294 3,313 3,311 3,311 Australasia 890 906 924 924 916 933 860 867 813 China 4,559 4,592 5,401 5,407 5,643 5,479 5,487 6,289 6,587 India 1,236 1,356 2,190 2,219 2,261 2,289 2,333 2,513 2,558 Indonesia 1,015 1,095 1,118 1,126 1,126 1,091 1,056 1,056 1,056 Japan 5,056 5,144 5,087 5,010 4,705 4,728 4,645 4,531 4,531 Singapore 1,246 1,246 1,246 1,255 1,255 1,255 1,255 1,255 1,255 South Korea 2,598 2,598 2,598 2,598 2,598 2,598 2,598 2,598 2,598 Taiwan 732 732 732 732 874 1,159 1,159 1,159 1,159 Thailand 824 863 872 872 872 874 860 876 876 Other Asia Pacific 1,107 1,152 1,233 1,292 1,386 1,351 1,313 1,259 1,261 Total Asia Pacific 19,263 19,684 21,401 21,435 21,636 21,757 21,566 22,403 22,694 TOTAL WORLD 78,804 79,519 81,788 81,955 82,798 83,504 83,807 85,023 85,702


180

Table 8.5 World Natural Gas Proven Reserves; 1985, 1995, 2004, 2005

(Trillion cubic meter)

at end

1985 at end

1995 at end

2004 at end

2005 2005 Share of

Total R/P Ratio

USA 5.41 4.62 5.45 5.45 3.0% 10.4 Canada 2.78 1.93 1.59 1.59 0.9% 8.6 Mexico 2.17 1.92 0.42 0.41 0.2% 10.4 Total North America 10.37 8.47 7.46 7.46 4.1% 9.9 Argentina 0.68 0.62 0.55 0.50 0.3% 11.1 Bolivia 0.13 0.13 0.76 0.74 0.4% 71.1 Brazil 0.09 0.15 0.33 0.31 0.2% 27.3 Colombia 0.11 0.22 0.12 0.11 0.1% 16.7 Peru + 0.20 0.33 0.33 0.2% * Trinidad & Tobago 0.32 0.35 0.53 0.55 0.3% 18.8 Venezuela 1.73 4.06 4.29 4.32 2.4% * Other S. & Cent. America 0.24 0.23 0.17 0.17 0.1% 87.7 Total S. & Cent. America 3.32 5.96 7.07 7.02 3.9% 51.8 Azerbaijan n.a n.a 1.37 1.37 0.8% * Denmark 0.09 0.12 0.08 0.07 � 6.5 Germany 0.30 0.22 0.20 0.19 0.1% 11.8 Italy 0.26 0.30 0.18 0.17 0.1% 14.0 Kazakhstan n.a n.a 3.00 3.00 1.7% * Netherlands 1.86 1.82 1.45 1.41 0.8% 22.3 Norway 0.57 1.81 2.39 2.41 1.3% 28.3 Poland 0.10 0.15 0.11 0.11 0.1% 25.3 Romania 0.27 0.41 0.30 0.63 0.3% 48.6 Russian Federation n.a n.a 47.80 47.82 26.6% 80.0 Turkmenistan n.a n.a 2.90 2.90 1.6% 49.3 Ukraine n.a n.a 1.11 1.11 0.6% 58.7 United Kingdom 0.65 0.70 0.53 0.53 0.3% 6.0 Uzbekistan n.a n.a 1.86 1.85 1.0% 33.2 Other Europe & Eurasia 40.37 57.64 0.46 0.46 0.3% 47.0 Total Europe & Eurasia 44.45 63.16 63.73 64.01 35.6% 60.3 Bahrain 0.21 0.15 0.09 0.09 0.1% 9.1 Iran 13.99 19.35 26.74 26.74 14.9% * Iraq 0.82 3.36 3.17 3.17 1.8% * Kuwait 1.04 1.49 1.57 1.57 0.9% * Oman 0.22 0.45 1.00 1.00 0.6% 56.9 Qatar 4.44 8.50 25.78 25.78 14.3% * Saudi Arabia 3.69 5.54 6.83 6.90 3.8% 99.3 Syria 0.12 0.24 0.31 0.31 0.2% 57.3 United Arab Emirates 3.15 5.86 6.06 6.04 3.4% * Yemen - 0.43 0.48 0.48 0.3% * Other Middle East + + 0.05 0.05 � 26.7 Total Middle East 27.67 45.37 72.09 72.13 40.1% * Algeria 3.35 3.69 4.55 4.58 2.5% 52.2 Egypt 0.26 0.65 1.87 1.89 1.1% 54.4 Libya 0.63 1.31 1.49 1.49 0.8% * Nigeria 1.34 3.47 5.23 5.23 2.9% * Other Africa 0.59 0.81 1.17 1.20 0.7% * Total Africa 6.16 9.93 14.30 14.39 8.0% 88.3 Australia 0.77 1.28 2.52 2.52 1.4% 67.9 Bangladesh 0.35 0.27 0.44 0.44 0.2% 30.7 Brunei 0.24 0.40 0.34 0.34 0.2% 28.3 China 0.87 1.67 2.20 2.35 1.3% 47.0 India 0.48 0.68 0.92 1.10 0.6% 36.2 Indonesia 1.98 1.95 2.77 2.76 1.5% 36.3 Malaysia 1.49 2.27 2.46 2.48 1.4% 41.4 Myanmar 0.27 0.27 0.50 0.50 0.3% 38.5 Pakistan 0.62 0.60 0.80 0.96 0.5% 32.2 Papua New Guinea 0.02 0.43 0.43 0.43 0.2% * Thailand 0.22 0.18 0.35 0.35 0.2% 16.5 Vietnam 0.00 0.15 0.24 0.24 0.1% 45.6 Other Asia Pacific 0.25 0.41 0.38 0.37 0.2% 34.7 Total Asia Pacific 7.57 10.54 14.35 14.84 8.3% 41.2 TOTAL WORLD 99.54 143.42 179.00 179.83 100.0% 65.1 Source : BP Statistical Review of World Energy June 2006

181

Table 8.6 World Natural Gas Production, 1997 – 2005

(Billion cubic metres) 1997 1998 1999 2000 2001 2002 2003 2004 2005 USA 543.1 549.2 541.6 550.6 565.8 544.3 551.4 539.4 525.7 Canada 165.8 171.3 177.4 183.2 186.8 187.8 182.7 183.6 185.5 Mexico 31.7 34.3 37.2 35.8 35.3 35.3 36.4 37.4 39.5 Total North America 740.6 754.8 756.2 769.6 787.9 767.4 770.5 760.4 750.6 Argentina 27.4 29.6 34.6 37.4 37.1 36.1 41.0 44.9 45.6 Bolivia 2.7 2.8 2.3 3.2 4.7 4.9 6.4 8.5 10.4 Brazil 6.0 6.3 6.7 7.2 7.6 9.2 10.0 11.0 11.4 Colombia 5.9 6.3 5.2 5.9 6.1 6.2 6.1 6.4 6.8 Trinidad & Tobago 7.4 8.6 11.7 14.1 15.2 17.3 24.7 28.1 29.0 Venezuela 30.8 32.3 27.4 27.9 29.6 28.4 25.2 28.1 28.9 Other S. & Cent. America 2.4 2.5 2.1 2.2 2.3 2.3 2.2 2.8 3.5 Total S. & Cent. America 82.5 88.4 90.0 97.9 102.6 104.4 115.7 129.7 135.6 Azerbaijan 5.6 5.2 5.6 5.3 5.2 4.8 4.8 4.7 5.3 Denmark 7.9 7.6 7.8 8.1 8.4 8.4 8.0 9.4 10.4 Germany 17.1 16.7 17.8 16.9 17.0 17.0 17.7 16.4 15.8 Italy 19.3 19.0 17.5 16.2 15.2 14.6 13.7 13.0 12.0 Kazakhstan 7.6 7.4 9.3 10.8 10.8 10.6 12.9 20.6 23.5 Netherlands 67.1 63.6 59.3 57.3 61.9 59.9 58.4 68.8 62.9 Norway 43.0 44.2 48.5 49.7 53.9 65.5 73.1 78.5 85.0 Poland 3.6 3.6 3.4 3.7 3.9 4.0 4.0 4.4 4.3 Romania 15.0 14.0 14.0 13.8 13.6 13.2 13.0 12.8 12.9 Russian Federation 532.6 551.3 551.0 545.0 542.4 555.4 578.6 591.0 598.0 Turkmenistan 16.1 12.4 21.3 43.8 47.9 49.9 55.1 54.6 58.8 Ukraine 17.4 16.8 16.9 16.7 17.1 17.4 17.7 19.1 18.8 United Kingdom 85.9 90.2 99.1 108.4 105.9 103.6 102.9 96.0 88.0 Uzbekistan 47.8 51.1 51.9 52.6 53.5 53.8 53.6 55.8 55.7 Other Europe & Eurasia 13.4 12.4 11.5 11.3 11.0 11.3 10.7 11.0 9.8 Total Europe & Eurasia 899.1 915.5 934.9 959.5 967.7 989.4 1024.4 1055.9 1061.1 Bahrain 8.0 8.4 8.7 8.8 9.1 9.5 9.6 9.8 9.9 Iran 47.0 50.0 56.4 60.2 66.0 75.0 81.5 84.9 87.0 Kuwait 9.3 9.5 8.6 9.6 8.5 8.0 9.1 9.7 9.7 Oman 5.0 5.2 5.5 8.7 14.0 15.0 16.5 17.2 17.5 Qatar 17.4 19.6 22.1 23.7 27.0 29.5 31.4 39.2 43.5 Saudi Arabia 45.3 46.8 46.2 49.8 53.7 56.7 60.1 65.7 69.5 Syria 3.8 4.3 4.5 4.2 4.1 5.0 5.2 5.3 5.4 United Arab Emirates 36.3 37.1 38.5 38.4 39.4 43.4 44.8 46.3 46.6 Other Middle East 3.3 3.2 3.4 3.4 3.0 2.6 1.8 2.5 3.4 Total Middle East 175.4 184.0 193.8 206.8 224.8 244.7 259.9 280.4 292.5 Algeria 71.8 76.6 86.0 84.4 78.2 80.4 82.8 82.0 87.8 Egypt 11.6 12.2 14.7 18.3 21.5 22.7 25.0 26.9 34.7 Libya 6.0 5.8 4.7 5.3 5.6 5.6 5.8 6.5 11.7 Nigeria 5.1 5.1 6.0 12.5 14.9 14.2 19.2 21.8 21.8 Other Africa 4.9 5.0 5.4 5.9 6.6 6.8 6.9 7.0 7.0 Total Africa 99.4 104.8 116.9 126.5 126.8 129.6 139.7 144.3 163.0 Australia 29.8 30.4 30.8 31.2 32.5 32.6 33.2 35.3 37.1 Bangladesh 7.6 7.8 8.3 10.0 10.7 11.4 12.3 13.3 14.2 Brunei 11.7 10.8 11.2 11.3 11.4 11.5 12.4 12.2 12.0 China 22.7 23.3 25.2 27.2 30.3 32.7 35.0 41.0 50.0 India 23.0 24.7 25.9 26.9 27.2 28.7 29.9 30.1 30.4 Indonesia 67.2 64.3 71.0 68.5 66.3 70.4 72.8 75.4 76.0 Malaysia 38.6 38.5 40.8 45.3 46.9 48.3 51.8 53.9 59.9 Myanmar 1.5 1.8 1.7 3.4 7.2 8.4 9.6 10.2 13.0 New Zealand 5.2 4.6 5.3 5.6 5.9 5.6 4.3 3.8 3.7 Pakistan 15.6 16.0 17.3 18.8 19.8 20.6 23.2 26.9 29.9 Thailand 15.2 16.3 17.7 18.6 18.0 18.9 19.6 20.3 21.4 Vietnam 0.5 0.9 1.3 1.6 2.0 2.4 2.4 4.2 5.2 Other Asia Pacific 3.5 3.6 3.6 3.7 3.9 5.5 6.7 6.5 7.3 Total Asia Pacific 242.2 242.7 260.1 272.0 282.2 297.0 313.1 333.0 360.1 TOTAL WORLD 2239.3 2290.1 2351.9 2432.3 2492.1 2532.6 2623.3 2703.8 2763.0 Source : BP Statistical Review of World Energy June 2006

182

Table 8.7 World Natural Gas Consumption, 1997 – 2005

(Billion cubic metres) 1997 1998 1999 2000 2001 2002 2003 2004 2005 USA 653.2 642.2 644.3 669.7 641.4 661.6 643.1 645.0 633.5 Canada 83.8 85.0 83.1 83.0 82.8 85.6 92.2 92.7 91.4 Mexico 32.3 35.4 37.4 38.5 39.0 42.7 45.8 48.6 49.6 Total North America 769.3 762.6 764.8 791.2 763.2 789.9 781.1 786.3 774.5 Argentina 28.5 30.5 32.4 33.2 31.1 30.3 34.6 37.9 40.6 Brazil 6.0 6.3 7.1 9.3 11.7 14.4 15.9 19.0 20.2 Chile 2.8 3.3 4.6 5.2 6.3 6.5 7.1 8.3 7.6 Colombia 5.9 6.2 5.2 5.9 6.1 6.1 6.0 6.3 6.8 Ecuador 0.1 0.1 0.1 0.1 0.2 0.1 0.1 0.2 0.2 Peru 0.2 0.4 0.4 0.3 0.4 0.4 0.5 0.9 1.6 Venezuela 30.8 32.3 27.4 27.9 29.6 28.4 25.2 28.1 28.9 Other S. & Cent. America 8.5 10.0 11.3 11.9 13.6 14.4 15.9 17.1 18.3 Total S. & Cent. America 82.9 89.1 88.5 94.0 98.9 100.7 105.3 117.7 124.1 Austria 8.1 8.3 8.5 8.1 8.6 8.5 9.4 9.5 10.0 Azerbaijan 5.6 5.2 5.6 5.4 7.8 7.8 8.0 8.6 8.8 Belarus 14.8 15.0 15.3 16.2 16.1 16.6 16.3 18.5 18.9 Belgium & Luxembourg 12.5 13.8 14.7 14.9 14.6 14.8 16.0 16.5 16.8 Bulgaria 4.1 3.5 3.0 3.3 3.0 2.7 2.8 2.9 3.2 Czech Republic 8.5 8.5 8.6 8.3 8.9 8.7 8.7 8.7 8.5 Denmark 4.4 4.8 5.0 4.9 5.1 5.2 5.2 5.2 5.0 Finland 3.2 3.7 3.7 3.7 4.1 4.0 4.5 4.3 4.0 France 34.6 37.0 37.7 39.7 41.7 41.7 43.3 44.5 45.0 Germany 79.2 79.7 80.2 79.5 82.9 82.6 85.5 85.9 85.9 Greece 0.2 0.8 1.4 1.9 1.9 2.0 2.3 2.5 2.5 Hungary 10.8 10.9 11.0 10.7 11.9 12.0 13.1 13.0 13.4 Iceland - - - - - - - - - Republic of Ireland 3.1 3.1 3.3 3.8 4.0 4.1 4.1 4.1 3.9 Italy 53.2 57.2 62.2 64.9 65.0 64.6 70.9 73.6 79.0 Kazakhstan 7.1 7.3 7.9 9.7 10.1 11.1 13.3 15.4 17.8 Lithuania 2.6 2.3 2.4 2.7 2.8 2.9 3.1 3.1 3.2 Netherlands 39.1 38.7 37.9 39.2 39.1 39.3 40.3 41.1 39.5 Norway 3.7 3.8 3.6 4.0 3.8 4.0 4.3 4.6 4.5 Poland 10.5 10.6 10.3 11.1 11.5 11.2 11.2 13.1 13.6 Portugal 0.1 0.8 2.3 2.4 2.6 2.8 3.0 3.1 3.0 Romania 20.0 18.7 17.2 17.1 16.6 17.2 18.3 17.5 17.3 Russian Federation 350.4 364.7 363.6 377.2 372.7 388.9 392.9 401.9 405.1 Slovakia 6.3 6.4 6.4 6.5 6.9 6.5 6.3 6.1 5.9 Spain 12.3 13.1 15.0 16.9 18.2 20.8 23.6 27.4 32.3 Sweden 0.8 0.9 0.8 0.7 0.7 0.8 0.8 0.8 0.8 Switzerland 2.5 2.6 2.7 2.7 2.8 2.8 2.9 3.0 3.1 Turkey 9.4 9.9 12.0 14.1 16.0 17.4 20.9 22.1 27.4 Turkmenistan 10.1 10.3 11.3 12.6 12.9 13.2 14.6 15.5 16.6 Ukraine 74.3 68.8 73.0 73.1 70.9 69.8 68.0 72.9 72.9 United Kingdom 84.5 87.9 92.5 96.9 96.4 95.1 95.3 97.0 94.6 Uzbekistan 45.4 47.0 49.3 47.1 51.1 52.4 47.2 44.8 44.0 Other Europe & Eurasia 14.7 14.6 12.9 13.5 14.7 13.8 14.2 14.4 15.3 Total Europe & Eurasia 936.1 959.9 981.3 1013.0 1025.4 1045.2 1070.6 1101.2 1121.9

183

Table 8.7 World Natural Gas Consumption, 1997 – 2005 (Continued)

(Billion cubic metres) 1997 1998 1999 2000 2001 2002 2003 2004 2005 Iran 47.1 51.8 58.4 62.9 70.2 79.2 82.9 86.5 88.5 Kuwait 9.3 9.5 8.6 9.6 8.5 8.0 9.1 9.7 9.7 Qatar 14.5 14.8 14.0 9.7 11.0 11.1 12.2 14.9 15.9 Saudi Arabia 45.3 46.8 46.2 49.8 53.7 56.7 60.1 65.7 69.5 United Arab Emirates 29.0 30.4 31.4 31.4 32.3 36.4 37.9 40.2 40.4 Other Middle East 19.6 20.5 21.5 22.1 22.8 23.6 23.9 25.3 27.0 Total Middle East 164.9 173.7 180.1 185.4 198.4 215.1 226.1 242.3 251.0 Algeria 20.2 20.9 21.3 19.8 20.5 20.2 21.4 22.0 24.1 Egypt 11.6 12.0 14.3 18.3 21.5 22.7 24.6 26.2 25.5 South Africa - - - - - - - - - Other Africa 14.4 14.9 15.2 17.0 17.1 17.2 19.2 20.4 21.6 Total Africa 46.1 47.7 50.9 55.2 59.1 60.1 65.2 68.6 71.2 Australia 21.4 22.4 23.2 23.9 24.5 25.2 26.1 25.3 25.7 Bangladesh 7.6 7.8 8.3 10.0 10.7 11.4 12.3 13.3 14.2 China 19.0 19.7 20.9 23.8 26.8 28.6 33.2 39.0 47.0 China Hong Kong SAR 2.6 2.5 2.7 2.5 2.5 2.4 1.5 2.2 2.2 India 23.0 24.7 25.9 26.9 27.2 28.7 29.9 32.7 36.6 Indonesia 31.9 27.8 31.8 32.3 33.5 34.5 33.4 36.9 39.4 Japan 66.0 68.7 71.7 74.9 76.6 75.2 82.6 78.7 81.1 Malaysia 16.7 17.4 16.1 24.3 25.8 26.8 31.8 33.9 34.9 New Zealand 5.1 4.5 5.2 5.5 5.7 5.5 4.1 3.7 3.6 Pakistan 15.6 16.0 17.3 18.8 19.8 20.6 23.2 26.9 29.9 Philippines ^ ^ ^ ^ 0.1 1.8 2.7 2.4 3.0 Singapore 1.5 1.5 1.5 1.7 4.5 4.9 5.3 6.6 6.5 South Korea 16.4 15.4 18.7 21.0 23.1 25.7 26.9 31.5 33.3 Taiwan 5.1 6.4 6.2 6.7 7.4 8.5 8.7 10.2 10.7 Thailand 14.2 15.1 16.4 19.2 22.2 23.9 26.3 27.4 29.9 Other Asia Pacific 4.3 4.7 5.0 5.1 5.2 5.3 5.6 7.8 8.9 Total Asia Pacific 250.4 254.3 270.9 296.7 315.7 329.0 353.8 378.5 406.9 TOTAL WORLD 2249.7 2287.3 2336.5 2435.4 2460.8 2540.0 2601.9 2694.7 2749.6


184

Table 8.8 World Coal Proven Reserves by Type, 2005

(Million tonnes)

Anthracite and

bituminous Sub-bituminous

and Lignite Total Share of

total R/P ratio USA 111,338 135,305 246,643 0 240 Canada 3,471 3,107 6,578 0 101 Mexico 860 351 1,211 0 121 Total North America 115,669 138,763 254,432 0 231 Brazil - 10,113 10,113 0 * Colombia 6,230 381 6,611 0 112 Venezuela 479 - 479 0 56 Other S. & Cent. America 992 1,698 2,690 0 * Total S. & Cent. America 7,701 12,192 19,893 0 269 Bulgaria 4 2,183 2,187 0 83 Czech Republic 2,094 3,458 5,552 0 90 France 15 - 15 � 25 Germany 183 6,556 6,739 0 33 Greece - 3,900 3,900 0 54 Hungary 198 3,159 3,357 0 351 Kazakhstan 28,151 3,128 31,279 0 362 Poland 14,000 - 14,000 0 88 Romania 22 472 494 0 16 Russian Federation 49,088 107,922 157,010 0 * Spain 200 330 530 0 27 Turkey 278 3,908 4,186 0 68 Ukraine 16,274 17,879 34,153 0 436 United Kingdom 220 - 220 � 11 Other Europe & Eurasia 1,529 21,944 23,473 0 370 Total Europe & Eurasia 112,256 174,839 287,095 0 241 South Africa 48,750 - 48,750 0 198 Zimbabwe 502 - 502 0 126 Other Africa 910 174 1,084 0 493 Middle East 419 - 419 � 399 Total Africa & Middle East 50,581 174 50,755 0 200 Australia 38,600 39,900 78,500 0 213 China 62,200 52,300 114,500 0 52 India 90,085 2,360 92,445 0 217 Indonesia 740 4,228 4,968 0 37 Japan 359 - 359 � 323 New Zealand 33 538 571 0 111 North Korea 300 300 600 0 20 Pakistan - 3,050 3,050 0 * South Korea - 80 80 � 28 Thailand - 1,354 1,354 0 64 Vietnam 150 - 150 � 5 Other Asia Pacific 97 215 312 � 25 Total Asia Pacific 192,564 104,325 296,889 0 92 TOTAL WORLD 478,771 430,293 909,064 1 155 � Less than 0.05% * More than 500 years Source : BP Statistical Review of World Energy June 2006

185

Table 8.9 World Coal Production, 1995-2005

(Million Ton Oil Equivalent) 1997 1998 1999 2000 2001 2002 2003 2004 2005

USA 580.3 598.4 579.7 565.6 587.3 565.6 549.3 567.9 576.2

Canada 43.0 40.8 39.2 37.1 37.6 34.9 32.2 34.9 34.4

Mexico 4.5 4.8 4.9 5.4 5.4 5.2 4.6 4.7 4.8

Total North America 627.8 644.0 623.8 608.1 630.3 605.7 586.0 607.4 615.3

Brazil 2.1 2.0 2.1 2.9 2.1 1.9 1.8 2.0 2.2

Colombia 21.0 21.9 21.3 24.9 28.5 25.7 32.5 34.9 38.4

Venezuela 3.9 4.7 4.8 5.8 5.6 5.9 5.1 5.9 6.2

Other S. & Cent. America 1.1 0.4 0.5 0.5 0.5 0.4 0.3 0.2 0.5

Total S. & Cent. America 28.1 29.1 28.7 34.0 36.8 33.9 39.7 43.0 47.3

Bulgaria 4.9 5.0 4.2 4.4 4.4 4.4 4.6 4.5 4.4

Czech Republic 27.9 26.0 23.1 25.0 25.4 24.3 24.2 23.5 23.5

France 4.3 3.6 3.3 2.3 1.5 1.1 1.3 0.4 0.2

Germany 66.9 61.3 59.4 56.5 54.1 55.0 54.1 54.7 53.2

Greece 7.7 8.1 8.0 8.2 8.5 9.1 9.5 9.6 9.6

Hungary 3.3 3.0 3.1 2.9 2.9 2.7 2.8 2.3 2.0

Kazakhstan 37.3 36.0 30.0 38.5 40.7 37.8 43.3 44.4 44.0

Poland 92.1 79.6 77.0 71.3 71.7 71.3 71.4 70.5 68.7

Romania 7.4 5.7 5.1 6.4 7.1 6.6 7.0 6.7 6.5

Russian Federation 109.3 103.9 112.0 115.8 121.5 114.8 124.9 128.6 137.0

Spain 9.8 9.3 8.6 8.0 7.6 7.2 6.8 6.7 6.4

Turkey 13.1 13.9 13.3 13.9 14.2 11.5 10.5 10.5 12.8

Ukraine 39.8 39.9 41.3 42.2 43.8 43.0 41.5 41.9 40.7

United Kingdom 29.4 25.0 22.5 19.0 19.4 18.2 17.2 15.3 12.5

Other Europe & Eurasia 15.9 16.7 13.4 14.0 14.3 15.2 15.6 15.6 14.6

Total Europe & Eurasia 469.2 437.0 424.3 428.6 437.3 422.2 434.6 435.2 436.2

Total Middle East 0.6 0.6 0.7 0.6 0.5 0.4 0.6 0.6 0.6

South Africa 124.6 127.1 125.6 126.6 126.0 124.1 133.9 136.9 138.9

Zimbabwe 3.4 3.5 3.2 2.8 2.9 2.6 2.0 2.4 2.6

Other Africa 1.2 1.4 1.3 1.2 1.2 1.3 1.2 1.3 1.3

Total Africa 129.2 132.0 130.1 130.7 130.0 128.0 137.0 140.6 142.8

Australia 148.1 149.8 160.6 166.2 179.8 184.0 189.5 197.0 202.4

China 690.0 628.7 645.9 656.7 697.6 733.7 868.4 1007.3 1107.7

India 149.6 150.3 147.4 157.0 160.3 168.1 175.9 191.0 199.6

Indonesia 33.7 38.3 45.3 47.4 56.9 63.6 69.4 81.4 83.2

Japan 2.4 2.0 2.2 1.7 1.8 0.8 0.7 0.7 0.6

New Zealand 2.0 2.0 2.1 2.2 2.4 2.7 3.2 3.2 3.2

Pakistan 1.4 1.5 1.5 1.4 1.5 1.6 1.5 1.5 1.6

South Korea 2.0 2.0 1.9 1.9 1.7 1.5 1.5 1.4 1.3

Thailand 6.9 6.1 5.7 5.1 5.6 5.7 5.3 5.6 5.9

Vietnam 6.4 6.4 4.9 6.5 7.5 9.2 10.8 14.7 18.3

Other Asia Pacific 17.2 15.7 18.0 19.3 19.7 19.0 19.5 20.4 21.2

Total Asia Pacific 1059.7 1002.7 1035.5 1065.5 1134.8 1189.9 1345.6 1524.2 1644.9

TOTAL WORLD 2314.5 2245.5 2243.1 2267.4 2369.8 2380.0 2543.6 2751.0 2887.2


186

Table 8.10 World Coal Consumption, 1997-2005


USA 540.4 545.8 544.9 569.1 552.3 552.0 562.5 566.2 575.4 Canada 26.8 28.1 27.8 29.4 32.0 31.0 30.6 30.5 32.5 Mexico 5.7 5.9 6.0 6.2 6.8 7.6 8.6 7.0 6.0 Total North America 573.0 579.7 578.7 604.6 591.1 590.6 601.7 603.7 613.9 Argentina 0.8 0.8 0.9 0.8 0.6 0.5 0.7 0.8 0.8 Brazil 11.5 11.4 11.9 12.5 12.2 11.5 11.8 12.8 13.5 Chile 4.2 3.7 3.9 3.0 2.3 2.4 2.3 2.9 2.4 Colombia 3.0 2.8 2.4 2.7 2.7 2.5 2.4 2.0 2.3 Ecuador - - - - - - - - - Peru 0.4 0.4 0.5 0.5 0.4 0.4 0.5 0.6 0.6 Venezuela ^ ^ 0.1 ^ ^ 0.1 0.1 0.1 0.1 Other S. & Cent. America 0.4 0.5 0.6 0.6 0.7 0.9 1.3 1.4 1.4 Total S. & Cent. America 20.3 19.7 20.2 20.2 19.0 18.2 19.0 20.4 21.1 Austria 3.1 3.0 3.2 3.2 2.9 3.0 2.9 2.4 2.5 Azerbaijan - - - - ^ ^ ^ ^ ^ Belarus 0.6 0.4 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Belgium & Luxembourg 7.5 7.9 6.9 7.6 7.6 6.7 6.5 6.4 6.4 Bulgaria 7.8 8.2 6.6 6.3 6.9 6.5 7.3 7.7 7.4 Czech Republic 22.8 20.5 19.0 21.0 21.2 20.6 20.8 20.5 20.5 Denmark 6.7 5.6 4.7 4.0 4.2 4.2 5.7 4.6 3.6 Finland 4.5 3.4 3.6 3.5 4.0 4.4 5.8 5.3 2.5 France 13.4 16.1 14.3 13.9 12.1 12.4 13.3 12.8 13.3 Germany 86.8 84.8 80.2 84.9 85.0 84.6 87.2 85.4 82.1 Greece 7.6 8.8 9.1 9.2 9.3 9.8 9.4 9.0 9.0 Hungary 3.7 3.4 3.4 3.2 3.4 3.1 3.4 3.1 2.7 Iceland 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Republic of Ireland 2.0 1.9 1.6 1.9 1.9 1.7 1.8 1.8 1.9 Italy 11.0 11.6 11.6 13.0 13.7 14.2 15.3 17.1 16.9 Kazakhstan 22.4 22.9 19.8 23.2 22.5 22.8 25.2 26.5 27.2 Lithuania 0.1 0.1 0.1 0.1 0.1 0.1 0.2 0.2 0.2 Netherlands 9.5 9.4 7.7 8.6 8.5 8.9 9.1 9.1 8.7 Norway 0.6 0.7 0.7 0.7 0.6 0.5 0.5 0.6 0.5 Poland 70.1 63.8 61.0 57.6 58.0 56.7 57.7 57.3 56.7 Portugal 3.6 3.6 3.6 4.5 3.7 4.1 3.8 3.9 3.8 Romania 8.4 7.0 6.7 7.0 7.2 7.6 7.8 7.4 7.1 Russian Federation 106.3 100.0 104.1 106.0 109.0 103.9 109.4 106.8 111.6 Slovakia 4.7 4.5 4.3 4.0 4.1 4.0 4.2 4.1 4.3 Spain 17.7 17.7 20.5 21.6 19.5 21.9 20.5 21.0 21.4 Sweden 2.1 2.0 2.0 1.9 2.0 2.2 2.2 2.3 2.2 Switzerland 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Turkey 22.3 24.0 22.6 25.5 21.8 21.2 21.8 23.0 26.1 Turkmenistan - - - - - - - - - Ukraine 38.0 36.9 38.5 38.8 39.4 38.3 39.0 38.1 37.4 United Kingdom 39.6 39.7 35.6 36.7 40.0 36.6 38.8 38.1 39.1 Uzbekistan 1.2 1.2 0.9 1.0 1.1 1.0 1.0 1.2 1.1 Other Europe & Eurasia 21.3 21.7 17.0 18.0 17.3 19.0 20.1 20.9 21.3 Total Europe & Eurasia 545.8 530.8 509.6 527.3 527.2 520.5 540.8 536.7 537.5

187

Table 8.10 World Coal Consumption, 1997-2005 (Continued)


Iran 0.9 1.0 1.0 1.1 1.1 1.1 1.1 1.1 1.1 Kuwait - - - - - - - - - Qatar - - - - - - - - - Saudi Arabia - - - - - - - - - United Arab Emirates - - - - - - - - - Other Middle East 5.4 5.8 5.7 6.2 7.2 7.6 7.9 8.0 7.9 Total Middle East 6.3 6.8 6.7 7.3 8.3 8.7 9.0 9.1 9.0 Algeria 0.3 0.5 0.5 0.5 0.6 0.9 0.8 0.8 0.9 Egypt 0.8 0.8 0.6 0.6 0.7 0.7 0.5 0.5 0.5 South Africa 84.3 83.4 82.3 81.9 80.6 83.5 89.3 94.5 91.9 Other Africa 6.8 7.0 6.5 6.4 7.4 7.2 6.6 7.0 7.0 Total Africa 92.3 91.6 89.9 89.4 89.3 92.3 97.2 102.9 100.3 Australia 45.1 47.3 47.9 48.3 49.6 52.3 50.9 52.4 52.2 Bangladesh 0.3 0.1 ^ 0.3 0.4 0.4 0.4 0.4 0.4 China 700.2 651.9 656.2 667.4 681.3 713.8 853.1 978.2 1081.9 China Hong Kong SAR 3.5 4.4 3.9 3.7 4.9 5.4 6.6 6.6 7.2 India 160.2 159.8 158.9 169.1 172.1 181.7 188.4 203.7 212.9 Indonesia 8.2 9.3 11.6 13.7 16.7 18.0 17.9 22.1 23.5 Japan 89.8 88.4 91.5 98.9 103.0 106.6 112.2 120.8 121.3 Malaysia 1.7 1.6 1.8 1.9 2.6 3.6 4.2 5.7 6.3 New Zealand 1.2 1.1 1.2 1.1 1.3 1.3 1.9 2.0 2.1 Pakistan 2.1 2.1 2.1 2.0 2.1 2.4 2.9 3.5 4.1 Philippines 2.4 2.7 2.9 4.3 4.5 4.7 4.7 5.0 5.9 Singapore - - - - - - - - - South Korea 34.8 36.1 38.2 43.0 45.7 49.1 51.1 53.1 54.8 Taiwan 21.9 23.8 24.9 28.9 30.8 32.9 35.3 36.8 38.2 Thailand 8.7 7.3 7.9 7.8 8.8 9.2 9.4 10.6 11.8 Other Asia Pacific 19.9 18.4 19.1 21.7 22.5 22.0 22.5 25.4 25.7 Total Asia Pacific 1100.0 1054.3 1068.2 1112.2 1146.5 1203.2 1361.5 1526.2 1648.1

TOTAL WORLD 2337.7 2282.9 2273.2 2360.9 2381.3 2433.5 2629.2 2798.9 2929.8


188

Table 8.11 World Primary Energy Production by Source, 1980-2004

Natural Natural Gas Nuclear Electric Hydroelectric Geothermal 3

Year Coal Gas 1 Crude Oil 2 Plant Liquids Power 3 Power 3 and Other 4 Total

1980 71.24 54.73 128.04 [R] 5.1 7.58 17.9 2.94 [R] 287.53 [R]

1981 71.63 55.56 120.11 [R] 5.37 [R] 8.53 18.26 3.1 282.56 [R]

1982 74.25 55.49 114.45 [R] 5.35 [R] 9.51 18.71 3.27 [R] 281.05 [R]

1983 74.25 56.12 113.97 5.36 [R] 10.72 19.69 3.56 [R] 283.68 [R]

1984 78.38 61.78 116.88 [R] 5.73 [R] 12.99 20.19 [R] 3.7 [R] 299.65 [R]

1985 82.2 64.22 115.37 [R] 5.83 [R] 15.3 20.42 [R] 3.78 [R] 307.13 [R]

1986 84.28 65.32 120.18 [R] 6.15 [R] 16.25 20.89 [R] 3.78 [R] 316.85 [R]

1987 86.08 68.48 121.07 [R] 6.35 [R] 17.64 20.9 [R] 3.79 [R] 324.33 [R]

1988 87.94 71.8 125.84 [R] 6.65 [R] 19.23 21.48 [R] 3.96 [R] 336.9 [R]

1989 89.43 74.24 127.83 [R] 6.69 [R] 19.74 21.53 [R] 4.34 [R] 343.8 [R]

1990 90.93 75.87 129.35 [R] 6.87 [R] 20.36 22.35 [R] 3.93 [R] 349.66 [R]

1991 86.29 76.69 128.73 [R] 7.12 [R] 21.18 22.83 [R] 4.03 [R] 346.86 [R]

1992 86.05 [R] 76.9 128.93 [R] 7.36 [R] 21.28 22.71 [R] 4.29 [R] 347.53 [R]

1993 84.28 [R] 78.41 128.72 [R] 7.66 [R] 22.01 23.94 [R] 4.31 [R] 349.32 [R]

1994 86.27 79.18 130.56 [R] 8.27 [R] 22.41 24.15 [R] 4.49 [R] 355.32 [R]

1995 88.87 [R] 80.24 133.32 8.55 [R] 23.26 25.34 [R] 4.64 [R] 364.23 [R]

1996 88.92 83.99 [R] 136.61 [R] 8.76 24.11 25.79 [R] 4.81 [R] 372.98 [R]

1997 92.15 [R] 84.29 [R] 140.52 8.94 [R] 23.88 26.07 [R] 4.91 [R] 380.75 [R]

1998 90.86 [R] 85.95 [R] 143.14 [R] 9.17 [R] 24.32 26.06 [R] 4.89 [R] 384.39 [R]

1999 90.43 [R] 87.89 140.79 9.47 [R] 25.09 [R] 26.56 [R] 5.09 [R] 385.32 [R]

2000 91.36 [R] 91.34 [R] 146.55 [R] 9.87 [R] 25.66 [R] 27.01 [R] 5.35 [R] 397.13 [R]

2001 96.89 [R] 93.74 [R] 145.32 [R] 10.32 [R] 26.39 [R] 26.39 [R] 5.25 [R] 404.3 [R]

2002 97.05 [R] 96.72 [R] 143.11 [R] 10.53 [R] 26.68 [R] 26.44 [R] 5.58 [R] 406.12 [R]

2003 104.61 [R] 98.93 [R] 147.97 [R] 11.02 [R] 26.45 [R] 26.83 [R] 5.9 [R] 421.71 [R]

2004P 113.3 102.19 154.79 11.48 27.47 27.53 6.33 443.1 1 Dry production. 2 Includes lease condensate 3 Net generation, i.e., gross generation less plant use. 4 Includes net electricity generation from wood, waste, solar, and wind. Data for the United States also

include other renewable energy. R=Revised. P=Preliminary. Source: Energy Information Agency, www.eia.doe.gov

189

Table 8.12 World Primary Energy Consumption, 1997-2005


USA 2207.6 2222.0 2260.3 2312.0 2258.4 2291.1 2298.6 2344.7 2336.6 Canada 285.5 282.6 284.2 289.8 289.9 296.7 302.8 311.4 317.5 Mexico 122.2 128.2 131.7 135.8 135.3 135.3 140.4 143.8 147.2 Total North America 2615.4 2632.8 2676.1 2737.6 2683.5 2723.1 2741.8 2799.9 2801.3 Argentina 55.8 58.1 57.5 58.9 57.7 54.3 58.7 62.2 66.8 Brazil 160.6 166.9 171.3 176.9 174.1 177.9 180.3 187.0 194.5 Chile 22.1 21.6 22.5 22.8 23.5 23.9 24.2 26.5 27.0 Colombia 27.8 27.3 25.2 25.4 26.3 25.7 26.0 26.8 27.8 Ecuador 8.1 8.2 7.7 7.7 7.7 7.7 7.8 8.2 8.4 Peru 10.9 11.3 11.7 11.9 11.7 11.8 11.7 12.4 12.8 Venezuela 61.1 63.8 59.8 61.9 65.2 66.1 58.5 65.4 69.2 Other S. & Cent. America 79.0 82.0 83.7 85.0 85.5 87.8 91.1 92.7 95.0 Total S. & Cent. America 425.5 439.2 439.4 450.4 451.7 455.2 458.3 481.2 501.4 Austria 30.7 31.6 32.3 32.2 33.3 33.3 34.2 33.7 34.6 Azerbaijan 11.1 11.1 11.1 11.5 11.3 11.1 12.0 12.9 13.7 Belarus 22.7 22.5 21.4 21.7 21.9 22.1 22.2 24.2 23.8 Belgium & Luxembourg 60.3 63.0 64.1 66.4 64.0 64.9 68.6 71.1 72.7 Bulgaria 20.7 20.7 18.0 17.8 18.4 18.2 18.9 19.6 20.3 Czech Republic 41.7 39.9 38.5 40.0 41.5 41.5 43.6 44.3 44.4 Denmark 21.7 20.6 19.9 18.8 18.6 18.4 19.6 18.3 17.2 Finland 25.1 25.6 25.7 26.0 26.4 26.7 28.9 28.6 25.6 France 241.0 247.2 251.5 254.9 258.4 256.7 259.8 263.4 262.1 Germany 337.8 334.5 328.5 330.5 336.2 330.1 332.1 330.7 324.0 Greece 27.2 28.6 30.1 31.8 31.7 32.7 32.3 33.8 33.5 Hungary 23.8 23.8 23.7 23.0 24.1 23.5 23.8 23.8 24.9 Iceland 2.1 2.2 2.3 2.4 2.5 2.6 2.6 2.7 2.6 Republic of Ireland 11.6 12.4 13.2 13.9 14.6 14.5 14.2 14.6 14.9 Italy 163.9 168.5 173.7 176.4 177.2 175.9 181.2 184.3 183.9 Kazakhstan 40.7 39.4 35.4 41.0 42.3 44.1 47.9 51.2 55.2 Lithuania 8.6 9.2 7.8 7.0 8.1 8.6 9.1 9.2 8.3 Netherlands 84.7 84.5 83.2 86.4 88.3 89.0 90.4 93.1 94.7 Norway 39.3 40.4 41.5 45.9 41.0 42.9 38.3 39.0 45.2 Poland 98.6 94.1 91.1 88.4 88.6 87.1 88.5 90.9 91.7 Portugal 20.5 22.7 23.3 24.8 25.0 24.7 25.3 24.3 23.0 Romania 45.2 41.3 36.9 37.0 37.3 38.6 37.8 39.0 39.8 Russian Federation 610.9 611.4 621.1 636.0 637.5 646.6 656.9 670.5 679.6 Slovakia 17.1 17.6 17.5 18.1 18.6 18.7 18.1 17.6 18.2 Spain 111.7 118.1 122.7 129.2 133.0 134.7 141.2 145.5 147.4 Sweden 50.4 51.6 51.6 48.6 52.1 48.5 46.2 48.4 49.7 Switzerland 28.9 29.1 30.1 29.4 31.5 29.5 29.4 29.0 27.9 Turkey 69.6 72.1 70.7 76.3 71.5 75.1 79.9 85.3 89.7 Turkmenistan 12.1 12.6 13.8 14.9 15.3 15.8 17.4 18.5 19.8 Ukraine 138.9 133.7 136.5 136.7 135.9 134.1 134.2 139.9 139.7 United Kingdom 220.4 223.5 221.6 223.5 227.0 221.7 225.1 227.0 227.3 Uzbekistan 50.5 51.9 53.5 51.4 54.8 56.2 52.4 50.5 50.1 Other Europe & Eurasia 74.1 74.0 67.6 67.0 68.2 70.1 73.5 75.7 78.1 Total Europe & Eurasia 2763.7 2779.2 2780.0 2828.8 2856.0 2858.2 2905.4 2960.6 2984.0

190

Table 8.12 World Primary Energy Consumption, 1997-2005 (Continued)


Iran 106.1 108.2 114.7 122.0 128.6 142.2 149.7 156.2 162.0 Kuwait 15.3 17.7 18.1 19.0 18.2 18.6 20.3 22.5 23.1 Qatar 14.7 15.0 14.2 10.4 12.0 13.2 14.0 16.7 18.1 Saudi Arabia 104.8 110.8 111.4 116.4 120.2 123.7 131.7 142.8 149.8 United Arab Emirates 43.9 41.7 42.0 41.1 43.7 48.6 50.4 53.5 54.6 Other Middle East 85.8 88.6 90.6 94.0 97.4 98.8 97.9 99.9 102.5 Total Middle East 370.6 382.0 390.9 402.9 420.1 445.1 464.0 491.7 510.2 Algeria 26.5 27.5 27.9 26.9 27.9 28.9 30.2 31.3 33.9 Egypt 39.9 41.9 44.7 47.5 49.4 49.5 51.5 54.0 55.8 South Africa 109.4 108.8 107.9 108.4 107.0 110.9 117.3 123.6 120.5 Other Africa 85.4 88.4 91.8 93.1 95.2 96.8 99.0 102.7 106.3 Total Africa 261.2 266.7 272.2 275.8 279.5 286.2 298.0 311.7 316.5 Australia 105.2 108.1 110.5 111.2 113.4 116.6 116.3 117.6 118.7 Bangladesh 10.6 11.0 11.0 12.7 14.1 14.8 15.5 16.4 17.4 China 960.9 916.9 934.1 966.7 1000.0 1057.8 1228.7 1423.5 1554.0 China Hong Kong SAR 15.1 15.4 15.6 15.6 18.9 20.4 20.9 23.8 22.9 India 285.6 296.0 304.0 320.4 324.2 338.7 348.2 376.1 387.3 Indonesia 84.0 80.0 89.1 95.2 101.4 104.4 103.9 112.1 116.4 Japan 508.3 501.5 506.2 514.8 513.0 510.2 510.9 520.8 524.6 Malaysia 37.8 37.3 38.3 45.8 47.8 51.3 56.3 60.4 61.2 New Zealand 17.2 17.0 17.4 17.8 18.0 18.5 17.9 18.4 17.8 Pakistan 37.4 39.6 40.8 41.9 42.9 43.8 45.8 49.8 55.9 Philippines 22.6 22.9 22.7 22.6 22.7 23.5 24.4 24.9 25.2 Singapore 33.8 34.7 32.9 35.0 40.5 39.9 38.7 44.1 48.1 South Korea 179.6 165.5 180.5 191.1 195.9 205.0 211.8 217.3 224.6 Taiwan 72.9 77.5 81.1 85.4 86.8 91.0 94.7 98.0 100.3 Thailand 60.9 57.4 58.8 61.2 63.3 68.8 74.7 80.6 85.6 Other Asia Pacific 45.0 45.1 47.2 51.8 54.5 55.0 56.1 61.9 63.8 Total Asia Pacific 2476.7 2426.0 2490.2 2589.5 2657.4 2759.5 2964.8 3245.9 3423.7 TOTAL WORLD 8913.2 8925.9 9048.8 9285.0 9348.2 9527.3 9832.2 10291.0 10537.1 * In this Review, primary energy comprises commercially traded fuels only. Source : BP Statistical Review of World Energy June 2006

191

Table 8.13 World Primary Energy Consumption by Fuel, 2004-2005

(Million tonnes oil equivalent) 2004 2005

Oil Natural

Gas Coal Hydro electric Total Oil Natural

Gas Coal Hydro electric Total

USA 948.8 580.5 566.2 61.4 2,344.7 944.6 570.1 575.4 60.6 2,336.6 Canada 100.6 83.4 30.5 76.4 311.4 100.1 82.3 32.5 81.7 317.5 Mexico 85.2 43.8 7.0 5.7 143.8 87.8 44.6 6.0 6.3 147.2 Total North America 1,134.6 707.7 603.7 143.5 2,799.9 1,132.6 697.1 613.9 148.6 2,801.3 Argentina 18.7 34.1 0.8 6.9 62.2 20.1 36.5 0.8 7.9 66.8 Brazil 81.9 17.1 12.8 72.6 187.0 83.6 18.2 13.5 77.0 194.5 Chile 11.3 7.5 2.9 4.8 26.5 11.9 6.8 2.4 5.9 27.0 Colombia 10.1 5.7 2.0 9.0 26.8 10.4 6.1 2.3 9.0 27.8 Ecuador 6.4 0.2 - 1.7 8.2 6.6 0.2 - 1.7 8.4 Peru 7.2 0.8 0.6 4.0 12.4 6.4 1.4 0.6 4.3 12.8 Venezuela 24.2 25.3 0.1 15.9 65.4 25.4 26.1 0.1 17.6 69.2 Other S. & Cent. America 58.1 15.4 1.4 17.8 92.7 58.8 16.4 1.4 18.3 95.0 Total S. & Cent. America 217.9 105.9 20.4 132.6 481.2 223.3 111.7 21.1 141.7 501.4 Austria 13.8 8.5 2.4 9.0 33.7 14.2 9.0 2.5 9.0 34.6 Azerbaijan 4.6 7.7 ^ 0.6 12.9 5.1 7.9 ^ 0.7 13.7 Belarus 7.5 16.6 0.1 ^ 24.2 6.7 17.0 0.1 ^ 23.8 Belgium & Luxembourg 38.4 14.9 6.4 0.6 71.1 39.5 15.2 6.4 0.6 72.7 Bulgaria 4.7 2.6 7.7 0.7 19.6 5.0 2.9 7.4 0.8 20.3 Czech Republic 9.5 7.8 20.5 0.6 44.3 9.9 7.7 20.5 0.7 44.4 Denmark 9.1 4.7 4.6 ^ 18.3 9.1 4.5 3.6 ^ 17.2 Finland 10.6 3.9 5.3 3.4 28.6 11.0 3.6 2.5 3.1 25.6 France 94.0 40.1 12.8 14.7 263.4 93.1 40.5 13.3 12.8 262.1 Germany 124.0 77.3 85.4 6.2 330.7 121.5 77.3 82.1 6.3 324.0 Greece 21.3 2.2 9.0 1.2 33.8 20.9 2.3 9.0 1.3 33.5 Hungary 6.3 11.7 3.1 ^ 23.8 7.0 12.1 2.7 ^ 24.9 Iceland 1.0 - 0.1 1.6 2.7 0.9 - 0.1 1.6 2.6 Republic of Ireland 8.9 3.6 1.8 0.2 14.6 9.4 3.5 1.9 0.2 14.9 Italy 89.7 66.2 17.1 11.3 184.3 86.3 71.1 16.9 9.6 183.9 Kazakhstan 9.0 13.9 26.5 1.8 51.2 10.0 16.0 27.2 2.0 55.2 Lithuania 2.6 2.8 0.2 0.2 9.2 2.7 2.9 0.2 0.2 8.3 Netherlands 46.2 37.0 9.1 ^ 93.1 49.6 35.5 8.7 ^ 94.7 Norway 9.6 4.1 0.6 24.7 39.0 9.8 4.0 0.5 30.9 45.2 Poland 21.1 11.8 57.3 0.8 90.9 21.9 12.2 56.7 0.9 91.7 Portugal 15.4 2.8 3.9 2.3 24.3 15.3 2.7 3.8 1.1 23.0 Romania 10.9 15.7 7.4 3.7 39.0 11.3 15.6 7.1 4.6 39.8 Russian Federation 128.5 361.7 106.8 40.8 670.5 130.0 364.6 111.6 39.6 679.6 Slovakia 3.2 5.5 4.1 1.0 17.6 3.5 5.3 4.3 1.1 18.2 Spain 77.6 24.7 21.0 7.8 145.5 78.8 29.1 21.4 5.2 147.4 Sweden 15.3 0.7 2.3 12.7 48.4 15.1 0.7 2.2 15.5 49.7 Switzerland 12.0 2.7 0.1 8.0 29.0 12.2 2.8 0.1 7.5 27.9 Turkey 32.0 19.9 23.0 10.4 85.3 30.0 24.6 26.1 9.0 89.7 Turkmenistan 4.6 13.9 - - 18.5 4.9 14.9 - - 19.8 Ukraine 13.9 65.6 38.1 2.7 139.9 13.9 65.6 37.4 2.8 139.7 United Kingdom 81.7 87.3 38.1 1.7 227.0 82.9 85.1 39.1 1.7 227.3 Uzbekistan 7.5 40.3 1.2 1.6 50.5 7.8 39.6 1.1 1.6 50.1 Other Europe & Eurasia 23.3 12.9 20.9 16.8 75.7 24.3 13.8 21.3 16.9 78.1 Total Europe & Eurasia 957.6 991.1 536.7 187.3 2,960.6 963.3 1,009.7 537.5 187.2 2,984.0

192

Table 8.13 World Primary Energy Consumption by Fuel, 2004-2005 (Continued)

(Million tonnes oil equivalent) 2004 2005

Oil Natural

Gas Coal Hydro electric Total Oil Natural

Gas Coal Hydro electric Total

Iran 74.6 77.9 1.1 2.7 156.2 78.4 79.6 1.1 2.8 162.0 Kuwait 13.7 8.7 - - 22.5 14.4 8.7 - - 23.1 Qatar 3.3 13.4 - - 16.7 3.8 14.3 - - 18.1 Saudi Arabia 83.7 59.1 - - 142.8 87.2 62.6 - - 149.8 United Arab Emirates 17.4 36.2 - - 53.5 18.3 36.4 - - 54.6 Other Middle East 68.1 22.8 8.0 1.1 99.9 69.2 24.3 7.9 1.1 102.5 Total Middle East 260.7 218.1 9.1 3.8 491.7 271.3 225.9 9.0 3.9 510.2 Algeria 10.6 19.8 0.8 0.1 31.3 11.2 21.7 0.9 0.1 33.9 Egypt 26.8 23.6 0.5 3.1 54.0 29.2 23.0 0.5 3.1 55.8 South Africa 24.8 - 94.5 0.8 123.6 24.9 - 91.9 0.8 120.5 Other Africa 61.9 18.3 7.0 15.4 102.7 64.0 19.4 7.0 15.9 106.3 Total Africa 124.2 61.8 102.9 19.4 311.7 129.3 64.1 100.3 19.9 316.5 Australia 38.8 22.8 52.4 3.6 117.6 39.7 23.1 52.2 3.7 118.7 Bangladesh 3.9 12.0 0.4 0.3 16.4 4.0 12.8 0.4 0.3 17.4 China 318.9 35.1 978.2 80.0 1,423.5 327.3 42.3 1,081.9 90.8 1,554.0 China Hong Kong SAR 15.3 2.0 6.6 - 23.8 13.8 1.9 7.2 - 22.9 India 120.2 29.5 203.7 19.0 376.1 115.7 33.0 212.9 21.7 387.3 Indonesia 54.7 33.2 22.1 2.1 112.1 55.3 35.5 23.5 2.1 116.4 Japan 241.4 70.9 120.8 23.1 520.8 244.2 73.0 121.3 19.8 524.6 Malaysia 22.8 30.5 5.7 1.4 60.4 22.0 31.4 6.3 1.5 61.2 New Zealand 7.0 3.3 2.0 6.2 18.4 7.0 3.2 2.1 5.5 17.8 Pakistan 16.0 24.2 3.5 5.5 49.8 17.4 26.9 4.1 6.9 55.9 Philippines 15.8 2.1 5.0 1.9 24.9 14.7 2.7 5.9 1.9 25.2 Singapore 38.1 5.9 - - 44.1 42.2 5.9 - - 48.1 South Korea 104.9 28.4 53.1 1.3 217.3 105.5 30.0 54.8 1.2 224.6 Taiwan 41.7 9.2 36.8 1.5 98.0 41.6 9.6 38.2 1.8 100.3 Thailand 44.0 24.6 10.6 1.4 80.6 45.6 26.9 11.8 1.3 85.6 Other Asia Pacific 20.3 7.0 25.4 9.3 61.9 21.1 8.0 25.7 8.9 63.8 Total Asia Pacific 1,103.6 340.6 1,526.2 156.5 3,245.9 1,116.9 366.2 1,648.1 167.4 3,423.7 TOTAL WORLD 3,798.6 2,425.2 2,798.9 643.2 10,291.0 3,836.8 2,474.7 2,929.8 668.7 10,537.1 * In this Review, primary energy comprises commercially traded fuels only. Excluded, therefore, are fuels such as wood, peat Source : BP Statistical Review of World Energy June 2006

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Table 8.14 World Hydroelectricity Consumption, 2000-2005

(Million tonnes oil equivalent)

2000 2001 2002 2003 2004 2005

USA 63.0 49.6 60.4 63.1 61.4 60.6 Canada 81.1 75.5 79.4 76.4 76.4 81.7 Mexico 7.5 6.4 5.6 4.5 5.7 6.3 Total North America 151.6 131.5 145.4 144.0 143.5 148.6 Argentina 6.5 8.4 8.1 7.7 6.9 7.9 Brazil 68.9 60.6 64.7 69.2 72.6 77.0 Chile 4.3 4.9 5.2 5.1 4.8 5.9 Colombia 6.9 7.1 7.6 8.1 9.0 9.0 Ecuador 1.7 1.6 1.7 1.6 1.7 1.7 Peru 3.7 4.0 4.1 4.2 4.0 4.3 Venezuela 14.2 13.7 13.5 13.7 15.9 17.6 Other S. & Cent. America 18.5 17.0 17.9 18.2 17.8 18.3 Total S. & Cent. America 124.8 117.3 122.9 127.8 132.6 141.7 Austria 9.8 9.8 9.5 8.7 9.0 9.0 Azerbaijan 0.3 0.3 0.5 0.6 0.6 0.7 Belarus ^ ^ ^ ^ ^ ^ Belgium & Luxembourg 0.6 0.6 0.6 0.5 0.6 0.6 Bulgaria 0.6 0.4 0.6 0.7 0.7 0.8 Czech Republic 0.5 0.6 0.6 0.4 0.6 0.7 Denmark ^ ^ ^ ^ ^ ^ Finland 3.3 3.1 2.4 2.1 3.4 3.1 France 16.4 18.0 15.1 14.7 14.7 12.8 Germany 5.9 6.3 6.4 5.5 6.2 6.3 Greece 0.9 0.6 0.8 1.2 1.2 1.3 Hungary ^ ^ ^ ^ ^ ^ Iceland 1.4 1.5 1.6 1.6 1.6 1.6 Republic of Ireland 0.3 0.2 0.3 0.2 0.2 0.2 Italy 11.5 12.2 10.7 10.0 11.3 9.6 Kazakhstan 1.7 1.8 2.0 2.0 1.8 2.0 Lithuania 0.1 0.2 0.2 0.2 0.2 0.2 Netherlands ^ ^ ^ ^ ^ ^ Norway 32.2 27.4 29.4 24.0 24.7 30.9 Poland 0.9 1.0 0.9 0.7 0.8 0.9 Portugal 2.7 3.3 1.9 3.6 2.3 1.1 Romania 3.3 3.4 3.6 3.0 3.7 4.6 Russian Federation 37.4 39.8 37.2 35.6 40.8 39.6 Slovakia 1.1 1.2 1.2 0.8 1.0 1.1 Spain 8.3 9.9 6.0 9.9 7.8 5.2 Sweden 17.8 17.9 15.0 12.1 12.7 15.5 Switzerland 8.7 9.7 8.3 8.3 8.0 7.5 Turkey 7.0 5.4 7.6 8.0 10.4 9.0 Turkmenistan - - - - - - Ukraine 2.6 2.8 2.2 2.1 2.7 2.8 United Kingdom 1.8 1.5 1.7 1.3 1.7 1.7 Uzbekistan 1.3 1.2 1.6 1.7 1.6 1.6 Other Europe & Eurasia 15.9 15.4 15.1 16.0 16.8 16.9 Total Europe & Eurasia 194.5 195.3 183.1 175.8 187.3 187.2

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Table 8.14 World Hydroelectricity Consumption, 2000-2005 (Continued)

(Million tonnes oil equivalent)

2000 2001 2002 2003 2004 2005

Iran 0.9 0.9 1.8 2.2 2.7 2.8 Kuwait - - - - - - Qatar - - - - - - Saudi Arabia - - - - - - United Arab Emirates - - - - - - Other Middle East 1.0 1.0 1.1 1.1 1.1 1.1 Total Middle East 1.8 1.9 2.9 3.2 3.8 3.9 Algeria ^ ^ ^ 0.1 0.1 0.1 Egypt 3.2 3.3 3.2 2.9 3.1 3.1 South Africa 0.9 0.8 0.9 0.8 0.8 0.8 Other Africa 13.4 14.1 15.2 15.3 15.4 15.9 Total Africa 17.6 18.2 19.3 19.1 19.4 19.9 Australia 3.7 3.7 3.6 3.7 3.6 3.7 Bangladesh 0.2 0.2 0.2 0.3 0.3 0.3 China 50.3 62.8 65.2 64.2 80.0 90.8 China Hong Kong SAR - - - - - - India 17.4 16.3 15.5 15.7 19.0 21.7 Indonesia 2.3 2.6 2.3 2.1 2.1 2.1 Japan 20.7 20.8 21.1 23.3 23.1 19.8 Malaysia 1.7 1.5 1.2 1.3 1.4 1.5 New Zealand 5.6 5.1 5.7 5.4 6.2 5.5 Pakistan 4.0 4.1 4.6 5.8 5.5 6.9 Philippines 1.8 1.6 1.6 1.8 1.9 1.9 Singapore - - - - - - South Korea 1.3 0.9 1.2 1.6 1.3 1.2 Taiwan 2.0 2.1 1.4 1.6 1.5 1.8 Thailand 1.4 1.4 1.7 1.7 1.4 1.3 Other Asia Pacific 8.1 8.9 8.8 9.5 9.3 8.9 Total Asia Pacific 120.2 132.1 134.1 137.7 156.5 167.4 TOTAL WORLD 610.5 596.3 607.8 607.6 643.2 668.7 Source : BP Statistical Review of World Energy June 2006

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Table 8.15 World Spot Crude Oil Prices, 1980 – 2005

US dollars per barrel

Year Dubai Brent Nigerian Forcados

West Texas Intermdiate

1980 35.69 36.83 36.98 37.96 1981 34.32 35.93 36.18 36.08 1982 31.80 32.97 33.29 33.65 1983 28.78 29.55 29.54 30.30 1984 28.06 28.78 28.14 29.39 1985 27.53 27.56 27.75 27.98 1986 13.10 14.43 14.46 15.10 1987 16.95 18.44 18.39 19.18 1988 13.27 14.92 15.00 15.97 1989 15.62 18.23 18.30 19.68 1990 20.45 23.73 23.85 24.50 1991 16.63 20.00 20.11 21.54 1992 17.17 19.32 19.61 20.57 1993 14.93 16.97 17.41 18.45 1994 14.74 15.82 16.25 17.21 1995 16.10 17.02 17.26 18.42 1996 18.52 20.67 21.16 22.16 1997 18.23 19.09 19.33 20.61 1998 12.21 12.72 12.62 14.39 1999 17.25 17.97 18.00 19.31 2000 26.20 28.50 28.42 30.37 2001 22.81 24.44 24.23 25.93 2002 23.74 25.02 25.04 26.16 2003 26.78 28.83 28.66 31.07 2004 33.64 38.27 38.13 41.49 2005 49.35 54.52 55.69 56.59

* 1972 - 1985 Arabian Light 1986 - 2005 Dubai dated + 1976 -1983 Forties 1984 -2005 Brent dated ++ 1976 -1983 Posted WTI prices 1984 -2005 Spot WTI (Cushing) prices Source : BP Statistical Review of World Energy June 2006

196

Table 8.16 World Average Gas Prices, 1984 – 2005

(US dollars per million Btu) LNG Natural Gas Crude Oil

Japan European UK USA Canada OECD Year

cif Union cif (Heren NBP Index) @ Henry Hub & (Alberta) & countries cif

1984 - 3.76 - - - 5.00

1985 5.23 3.83 - - - 4.75

1986 4.10 3.65 - - - 2.57

1987 3.35 2.59 - - - 3.09

1988 3.34 2.36 - - - 2.56

1989 3.28 2.09 - 1.70 - 3.01

1990 3.64 2.82 - 1.64 1.05 3.82

1991 3.99 3.18 - 1.49 0.89 3.33

1992 3.62 2.76 - 1.77 0.98 3.19

1993 3.52 2.53 - 2.12 1.69 2.82

1994 3.18 2.24 - 1.92 1.45 2.70

1995 3.46 2.37 - 1.69 0.89 2.96

1996 3.66 2.43 1.85 2.76 1.12 3.54

1997 3.91 2.65 2.03 2.53 1.36 3.29

1998 3.05 2.26 1.92 2.08 1.42 2.16

1999 3.14 1.80 1.64 2.27 2.00 2.98

2000 4.72 3.25 2.68 4.23 3.75 4.83

2001 4.64 4.15 3.22 4.07 3.61 4.08

2002 4.27 3.46 2.58 3.33 2.57 4.17

2003 4.77 4.40 3.26 5.63 4.83 4.89

2004 5.18 4.56 4.69 5.85 5.03 6.27

2005 6.05 6.28 6.69 8.79 7.25 8.73 @ Source: Heren Energy Ltd. & Source: Natural Gas Week Note: cif = cost+insurance+freight (average prices) Source : BP Statistical Review of World Energy June 2006

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Table 8.17 World Average Coal Prices, 1987 – 2005

(US dollars per tonne)

Northwest Europe marker price †

US Central Appalachian coal

spot price index ‡

Japan coking coal import cif price

Japan steam coal import cif price

1987 31.30 - 53.44 41.28

1988 39.94 - 55.06 42.47

1989 42.08 - 58.68 48.86

1990 43.48 31.59 60.54 50.81

1991 42.80 29.00 60.45 50.30

1992 38.53 28.54 57.82 48.45

1993 33.68 29.85 55.26 45.71

1994 37.18 31.71 51.77 43.66

1995 44.50 26.98 54.47 47.58

1996 41.25 29.87 56.68 49.54

1997 38.92 29.76 55.51 45.53

1998 32.00 31.01 50.76 40.51

1999 28.79 31.28 42.83 35.74

2000 35.99 29.91 39.69 34.58

2001 39.29 49.75 41.33 37.96

2002 31.65 32.96 42.01 36.90

2003 42.52 38.49 41.57 34.74

2004 71.90 64.36 60.96 51.34

2005 61.07 70.82 89.33 62.91 † Source: McCloskey Coal Information Service ‡ Price is for CAPP 12,500 BTU, 1.2 SO2 coal. Source: Platts Note: cif = cost+insurance+freight (average prices) Source : BP Statistical Review of World Energy June 2006

199

IX. CURRENT AND FUTURE ENERGY TECHNOLOGY


CURRENT AND FUTURE ENERGY TECHNOLOGY

201

Current and Future Energy Technology 9.1 Petroleum Technology

Petroleum is an organic compound made up of a variety of hydrogen and carbon

atoms (hydrocarbons) that range from a light gas or methane to a number of heavy solids such

as bitumen. Petroleum also contains small quantities of oxygen, nitrogen and sulphur. The main

advantage of mineral oil compared to most other energy carriers is its high energy density that

makes it easier to handle and transport in atmospheric tanks at reasonable cost. The calorific

value of mineral oil is very high – around 42-43 MJ/kg. The ratio of hydrogen to carbon is

typically around 2:1 – two hydrogen atoms per carbon atom. The typical emission of CO2

amounts to 73-75 grams per MJ. This is equivalent to some 3.1 kg of CO2 per kg of mineral oil.

Exploration and Drilling. Seismic surveys are the most common exploration tool used

in the search for oil and gas. Geophysicists record sound waves reflected back to the surface

from structures kilometers below the seabed. They produce maps of the sub-surface showing

the location of geological features such as sedimentary basins, faults and hopefully petroleum

traps such as anticlines. Gravity and magnetic aerial surveys are also used to indicate the

extent of sedimentary rocks over wide areas. Drilling is the only way to make sure whether a

structure identified by seismic surveys actually contains hydrocarbons. Onshore, the drilling

process is relatively simple. A drill bit, made of either industrial diamonds or tungsten carbide, is

attached to a length of drill pipe and rotated at high speed. Extra pipe lengths are added as the

drill bit penetrates deeper into the rock. Specially prepared heavy mud is circulated through the

pipe and drill bit, to cool and lubricate the drill bit and carry rock cuttings to the surface for

analysis and to reduce the risk of high pressure petroleum blowing out at the surface. Offshore,

the exploration drilling is more complicated because of the movement of the rig caused by

swells and tides. Jack-up rigs are used in waters of less than 100 meters and semi-submersible

rigs are designed for use in depths of up to 300 meters. They are most efficient in calm,

protected waters. Drill ships are used extensively for deep water drilling in depths of more than

300 meters. Horizontal drilling is common these days, which enables increased production from

thin reservoirs. Fields which previously was considered too small to be economically viable can

now is tapped. A large field may require two or three production platforms, with up to 60

production wells from each platform. Wells can be drilled to over 5000 meters below the sea-

bed. Some reach as far as eight kilometers from the platform.

Refining. The petroleum refining industry is currently changing to meeting the

environmental regulation on fuel quality. Building new refineries or revamping existing facilities

in order to satisfy these regulations, mainly, reduction of benzene and aromatics in gasoline,

reduction of sulfur in all liquid fuels, and synthesis of oxygenates. The challenge to go beyond

these objectives is in catalyst science and technology. To reduce aromatics in gasoline, the

need is to shift naphtha reforming to paraffin hydroisomerization, to achieve octane

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requirements with less dependence on aromatics. In answer to environmental pressure, the

need is to develop heterogeneous iso-butane alkylation catalysts to replace current liquid

homogeneous catalysts, such as hydrogen fluoride and sulfuric acid. More effective catalysts

for hydrodesulfurization and benzene removal are needed.

To meet the demand for truly clean transportation fuels, fuel production will be

integrated with lube oil and petrochemical production. The production of jet fuel and diesel fuel

will surpass that of gasoline, and all of the products from the fuel–lube oil–petrochemical

complex will be synthesized almost free of pollutants. The raw material used by the complex will

be extended from crude oils to other resources, including natural gas, heavy oils, tar sands,

shale oil, and coal. Process technologies will be developed to reduce the cost of production and

to avoid the generation of pollutants except the emission of CO2. Facing the eventual

displacement of internal combustion engines by transportation vehicles powered by hydrogen

fuel cells, the oil industry may elect to provide hydrogen by producing it from hydrocarbons

onboard the vehicle. In refining, several processes are involved such as:

Distillation. Crude oil is a mixture of hydrocarbons with different boiling temperatures; it

can be separated by distillation into groups of hydrocarbons that boil between two specified

boiling points. Two types of distillation are performed: atmospheric and vacuum. Atmospheric

distillation takes place in a distilling column at or near atmospheric pressure. The crude oil is

heated to 350 - 400oC and the vapor and liquid are piped into the distilling column. The liquid

falls to the bottom and the vapor rises, passing through a series of trays. Heavier hydrocarbons

condense more quickly and settle on lower trays and lighter hydrocarbons remain as a vapor

longer and condense on higher trays. Liquid fractions are drawn from the trays and removed. In

this way the light gases, methane, ethane, propane and butane pass out the top of the column,

petrol is formed in the top trays, kerosene and gas oils in the middle, and fuel oils at the bottom.

Residue drawn of the bottom may be burned as fuel, processed into lubricating oils, waxes and

bitumen or used as feedstock for cracking units. To recover additional heavy distillates from this

residue, it may be piped to a second distillation column where the process is repeated under

vacuum, called vacuum distillation. This allows heavy hydrocarbons with boiling points of 450oC

and higher to be separated without them partly cracking into unwanted products such as coke

and gas. The heavy distillates recovered by vacuum distillation can be converted into lubricating

oils by a variety of processes (Figure 9.1).

Reforming. Reforming is a process which uses heat, pressure and a catalyst to bring

about chemical reactions which upgrade naphthas into high octane petrol and petrochemical

feedstock. The naphthas are hydrocarbon mixtures containing many paraffin and naphthenes.

This naphtha feedstock comes from the crude oil distillation or catalytic cracking processes, it

also comes from thermal cracking and hydrocracking processes. Reforming converts a portion

of these compounds to isoparaffins and aromatics, which are used to blend higher octane

petrol. paraffins are converted to isoparaffins, naphthenes, and naphthenes are converted to

aromatics

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Figure 9.1 Crude oil distillation scheme

Cracking processes breakdown heavier hydrocarbon molecules (high boiling point oils)

into lighter products such as petrol and diesel. These processes include catalytic cracking,

thermal cracking and hydrocracking.

Catalytic Cracking is used to convert heavy hydrocarbon fractions obtained by vacuum

distillation into a mixture of more useful products such as petrol and light fuel oil. In this process,

the feedstock undergoes a chemical breakdown, under controlled heat (450 - 500oC) and

pressure, in the presence of a catalyst-a substance which promotes the reaction without itself

being chemically changed. Silica-alumina or silica-magnesia has proved to be the most effective

catalysts. The cracking reaction yields petrol, LPG, unsaturated olefin compounds, cracked gas

oils, a liquid residue called cycle oil, light gases and a solid coke residue. Cycle oil is recycled to

cause further breakdown and the coke, which forms a layer on the catalyst, is removed by

burning. The other products are passed through a fractionator to be separated and separately

processed.

Fluid Catalytic Cracking uses a catalyst in the three phase fluidized flows. Feedstock

entering the process immediately meets a stream of very hot catalyst and vaporizes. The

resulting vapors keep the catalyst fluidized as it passes into the reactor, where the cracking

takes place and where it is fluidized by the hydrocarbon vapor. The catalyst next passes to a

steam stripping section where most of the volatile hydrocarbons are removed. It then passes to

a regenerator vessel where it is fluidized by a mixture of air and the products of combustion

which are produced as the coke on the catalyst is burnt off. The catalyst then flows back to the

reactor. The catalyst thus undergoes a continuous circulation between the reactor, stripper and

regenerator sections. The catalyst is usually a mixture of alumina and silica. Most recently, the

introduction of synthetic zeolite catalysts has allowed much shorter reaction times and improved

yields and octane numbers of the cracked gasolines.

Thermal Cracking uses heat to breakdown the residue from vacuum distillation. The

lighter elements produced from this process can be made into distillate fuels and petrol.

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Cracked gases are converted to petrol blending components by alkylation or polymerization.

Naphtha is upgraded to high quality petrol by reforming. Gas oil can be used as diesel fuel or

can be converted to petrol by hydrocracking. The heavy residue is converted into residual oil or

coke which is used in the manufacture of electrodes, graphite and carbides.

Hydrocracking can increase the yield of petrol components, as well as being used to

produce light distillates. It produces no residues, only light oils. Hydrocracking is catalytic

cracking in the presence of hydrogen. The extra hydrogen saturates, or hydrogenates, the

chemical bonds of the cracked hydrocarbons and creates isomers with the desired

characteristics. Hydrocracking is also a treating process, because the hydrogen combines with

contaminants such as sulphur and nitrogen, allowing them to be removed. Gas oil feed is mixed

with hydrogen, heated, and sent to a reactor vessel with a fixed bed catalyst, where cracking

and hydrogenation take place. Products are sent to a fractionator to be separated. The

hydrogen is recycled. Residue from this reaction is mixed again with hydrogen, reheated, and

sent to a second reactor for further cracking under higher temperatures and pressures. In

addition to cracked naphtha for making petrol, hydrocracking yields light gases useful for

refinery fuel, or alkylation as well as components for high quality fuel oils, lube oils and

petrochemical feedstock. Following the cracking processes it is necessary to build or rearrange

some of the lighter hydrocarbon molecules into high quality petrol or jet fuel blending

components or into petrochemicals. The former can be achieved by several chemical processes

such as alkylation and isomerisation.

Alkylation. Olefins such as propylene and butylene are produced by catalytic and

thermal cracking. Alkylation refers to the chemical bonding of these light molecules with

isobutane to form larger branched-chain molecules (isoparaffins) that make high octane petrol.

Olefins and isobutane are mixed with an acid catalyst and cooled. They react to form alkylate,

plus some normal butane, isobutane and propane. The resulting liquid is neutralized and

separated in a series of distillation columns. Isobutane is recycled as feed and butane and

propane sold as liquid petroleum gas (LPG).

Isomerisation refers to chemical rearrangement of straight-chain hydrocarbons

(paraffins), so that they contain branches attached to the main chain (isoparaffins). This is done

for two reasons: they create extra isobutane feed for alkylation; they improve the octane of

straight run pentanes and hexanes and hence make them into better petrol blending

components. Isomerisation is achieved by mixing normal butane with a little hydrogen and

chloride and allowed to react in the presence of a catalyst to form isobutane, plus a small

amount of normal butane and some lighter gases. Products are separated in a fractionator. The

lighter gases are used as refinery fuel and the butane recycled as feed. Pentanes and hexanes

are the lighter components of petrol. Isomerisation can be used to improve petrol quality by

converting these hydrocarbons to higher octane isomers. The process is the same as for butane

isomerisation.

205

Polymerisation. Under pressure and temperature, over an acidic catalyst, light

unsaturated hydrocarbon molecules react and combine with each other to form larger

hydrocarbon molecules. Such process can be used to react butenes (olefin molecules with four

carbon atoms) with isobutane (branched paraffin molecules, or isoparaffins, with four carbon

atoms) to obtain a high octane olefinic petrol blending component called polymer gasoline.

Hydrotreating and Sulphur Plants. Hydrotreating is one way of removing many of the

contaminants from many of the intermediate or final products. In the hydrotreating process, the

entering feedstock is mixed with hydrogen and heated to 300 - 380oC. The oil combined with the

hydrogen then enters a reactor loaded with a catalyst which promotes several reactions:

hydrogen combines with sulphur to form hydrogen sulphide (H2S), nitrogen compounds are

converted to ammonia, any metals contained in the oil are deposited on the catalyst, some of

the olefins, aromatics or naphthenes become saturated with hydrogen to become paraffins and

some cracking takes place, causing the creation of some methane, ethane, propane and

butanes.

Sulphur Recovery Plants. The hydrogen sulphide created from hydrotreating is a toxic

gas that needs further treatment. The usual process involves two steps: the removal of the

hydrogen sulphide gas from the hydrocarbon stream the conversion of hydrogen sulphide to

elemental sulphur, a non-toxic and useful chemical. Solvent extraction, using a solution of

diethanolamine (DEA) dissolved in water, is applied to separate the hydrogen sulphide gas from

the process stream. The hydrocarbon gas stream containing the hydrogen sulphide is bubbled

through a solution of diethanolamine solution (DEA) under high pressure, such that the

hydrogen sulphide gas dissolves in the DEA. The DEA and hydrogen mixture is the heated at a

low pressure and the dissolved hydrogen sulphide is released as a concentrated gas stream

which is sent to another plant for conversion into sulphur. Conversion of the concentrated

hydrogen sulphide gas into sulphur occurs in two stages. Combustion of part of the H2S stream

in a furnace, producing sulphur dioxide (SO2) water (H2O) and sulphur (S). Reaction of the

remainder of the H2S with the combustion products in the presence of a catalyst. The H2S

reacts with the SO2 to form sulphur. As the reaction products are cooled the sulphur drops out of

the reaction vessel in a molten state. Sulphur can be stored and shipped in either a molten or

solid state.

206

9.2 Natural Gas Technology Natural gas is colorless and odorless in its pure form, and a promising energy

alternative due to its availability and its similar property to petroleum. Natural gas, in which

methane is the primary component, is the simplest fossil molecule of highest hydrogen to

carbon ratio (4:1). Natural gas has a high calorific value of around 55.8 MJ/kg. Because of its

high hydrogen-to-carbon fraction the CO2 emission becomes very low compared to coal and oil

at the same calorific value. The typical emission of carbon dioxide is 56 g per MJ. While the

predominant usage of natural gas is as fuel, natural gas is also an important feedstock to the

petrochemical industry for a wide range of chemicals, including methanol, fertilizer and

hydrogen.

Gas technology plays a key role in transforming natural gas industry into more

competitive market. Today’s technological challenges are focusing towards greater flexibility in

development of natural gas fields. The main technology development objective is finding

transportation modes that enable to transport natural gas from remote area to markets cost-

effectively under difference sizes of fields. Figure 9.2 showed the options to transport natural

gas from supply side to the markets. Firstly, to transport the gas in gases form to market such

as pipelines and Compressed Natural Gas (CNG), in liquid form - Liquefied Natural Gas (LNG),

and in solid form – Gas to hydrate (GTH). Secondly, to convert the gas chemically into stable

liquids, mainly, Gas to Liquids (GTL) and Gas to Chemicals (GTC). Finally, the gas is converted

into electricity/power via thermodynamic and electro-catalytic conversions, called Gas to Wire

(GTW).

Figure 9.2 Strategies of natural gas utilization

Pipeline, CNG, LNG, and GTH are the physical mode of transporting natural gas in a

gaseous phase in which volume is reduced. Pipeline gas usually has diameter of 6-46 inches

and operates up to 340 bars. LNG is obtained by lowering the temperature below -162oC

(cryogenic conditions). The density of LNG is 415 kg/m3 compared to 0.7168 kg/m3 in gaseous

with volume ratio of 1/600. CNG is natural gas pressurized and stored in bottle-like tanks at

GAS

SUPPLY

GAS

MARKETS

Pipeline gas

Compressed Natural Gas (CNG)

Gas to Liquids (GTL)

Gas to Chemicals (GTC)

Liquefied Natural Gas (LNG)

Gas to Hydrate (GTH)

Gas to Wire (GTW)

207

pressures up to 3,000 psig with volume ratio ~ 1/300. GTH is a transportation mode of natural

gas in the form of solid of natural gas hydrates (NGH). The hydrates are crystalline substance,

of which cluster made of water molecules holds in it methane molecules and carbon dioxide

molecules as guests. NGH is an artificially manufactured hydrate using such components as

guests. NGH can hold gas about 170 times its volume at -20oC under atmospheric pressure.

New innovations being considered are to reduce investment cost of pipeline by creating new

materials for manufacturing cheaper gas pipeline than conventional pipeline, to reduce cost of

LNG processing by expanding the size of LNG production units, and to develop over pressure-

containment vessel by increasing the gas-to-container weight ratio through new materials or

optimizing pressure/temperature relationship.

GTL and GTC, are the chemical conversion of natural gas into more easily

transportable and useful chemicals or fuels. These technologies may be broadly divided into two

major processes, which are described as direct and indirect routes. Direct conversion of

methane into methanol, ethylene or C2+ is an interesting alternative without synthesis gas

production reactions. Oxidative coupling of methane to produce ethylene and direct conversion

of methane to methanol/formaldehyde are that most researched reactions. Most direct

processes require oxygen to provide a thermodynamic driving force. However, direct oxidation

reactions are controlled by kinetic aspect and the formation of the undesired product of CO2

which severely limits the yield that may be achieved. There are some direct processes which do

not require oxygen as an oxidant such as direct conversion methane to aromatics and

decomposition of methane to produce simultaneously hydrogen and nano-size of carbon, but,

the yields obtained are generally small. Theoretically, direct routes should be having a distinct

economic advantage over indirect routes, but to date, no direct processes in the commercial

stages is being developed. The indirect routes depend on the formation of synthesis gas

(mixture of CO and H2) as intermediate product in the first step, either by partial oxidation or

reforming reactions, followed by conversion of synthesis gas into valuable products such as

synthetic fuels, methanol, dimethyl ether (DME) and olefins.

For mature technology of steam reforming, innovations are carried out mainly to

improve catalyst performance due to coke formation in conventional nickel catalyst. For catalytic

partial oxidation, the process needs practically pure oxygen, which requires air separation and

involves hazards of handling of large quantities of undiluted oxygen and oxygen-methane

mixture. Recent research directions are focusing on development of membrane reactor,

millisecond reactor using structured catalyst and combined steam reforming and partial

oxidation reaction that is called auto-thermal reforming.

Production of synthetic fuels which is sulfur-free and has very low aromatic from

synthesis gas are obtained by Fischer-Tropsch (FT) reaction, which is frequently also called as

GTL. Type of catalyst for FT reaction highly depends on the type of main products such as

gasoline, diesel, and wax, chemical. The catalyst must have active properties to hydrogenation

reaction, capability to produce metal carbonyl due to this carbonyl role in production of long-

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chained hydrocarbons. Fe and Co are commonly used as catalyst for FT GTL processes. Diesel

products are typically produced by low temperature FT process in which Cetane number is

about 74 as compared of 40 in conventional diesel. The aromatic content is about 2% as

compared of 32% in conventional diesel. The emission levels of hydrocarbons, CO, NOX and

particles from FT diesel are 56, 33, 28 and 21%, respectively which is lower than ones of

conventional diesel. Gasoline products are yielded by high temperature FT process. Gasoline

produced has aromatic content of about 5% and very low benzene that fulfill the threshold,

however alkenes is very high that it must be introduced into subsequent processes such as

hydrogenation, isomerization and reforming in order to obtain high octane number. Gas based

GTL is technologically proven and is entering a commercialization stage throughout the world

with commercial production capacity in Bintulu Malaysia by Shell, called Shell Middle Distillate

Synthesis (SMDS), in Mossel Bay South Africa by Mossgas GTL project (now Petro SA), and

Oryx Qatar using Sasol technology.

DME is in liquid phase under 20oC and pressure of 5 bars. Considering it attractive

properties, DME would be as fuel substitutes for LPG and diesel. From safety and properties

aspect, DME can be handled like LPG and it is suitable to compression ignition engines due to

the Cetane number of 60. DME is conventionally produced through methanol dehydration

reaction, consisted of three steps of reaction of methane, i.e., synthesis gas production, and

methanol synthesis and methanol dehydration. Alternatively, direct conversion synthesis gas

into DME with reaction 2CO + 4H2 → CH3OCH3 + H2O is interesting. This process is developed

in pilot-scale by licensors such as Topsoe and NKK Japan. Two other potential processes are

methanol-to-gasoline (MTG), which has been developed by Mobil, and methanol-to-olefin

(MTO), by UOP. The MTG process will yield high octane gasoline which is also rich in

aromatics.

GTW is to bring the gas as electricity to market. Natural gas is converted to electricity

by thermodynamic cycle such as simple cycle of steam turbine or gas turbine, combine cycle,

micro turbine, and by electro-catalytic processes such as fuel cells. New technology innovations

focusing on developing natural gas gasification combined cycle for CO2 sequestration are

proposed. Micro turbines have advantages of reducing the number of moving parts, its

compactness and lightness, and low emissions rates. Fuel cells have the ability to generate

electricity using electrochemical reactions that are an extremely exciting for the clean and

efficient generation of electricity. Basically, a fuel cell works by passing fuel (usually hydrogen)

and oxidants over electrodes that are separated by an electrolyte membrane. Oxygen flows into

the cathode and hydrogen into the anode. In the anode, hydrogen dissociated in the present of

noble metal catalyst, forming proton (hydrogen ions) and yielding electrons to the anode. Anode

reaction: H2 2H+ + 2e-. Hydrogen ions are transported through an electrolyte, as liberated

electrons flow through electrical load to the cathode to participate in the catalytic oxidation

reaction, forming water. Cathode reaction: 2H+ + 2e- + ½ O2 H2O. This produces a chemical

reaction that generates electricity without requiring the combustion of fuel, or the addition of

heat as is common in the traditional generation of electricity. Micro turbines and fuel cells are

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suitable for distributed power generation due to tension variation control and supply reliability

are better, and transmission and distribution costs are smaller by reason of the proximity to the

load centers.

Gas Combustion. Natural gas is burned to produce lower NOX emission than another

fossil fuel, free of SOX. NOX is emitted in percentage of about 40% by coal and about 57% by

petroleum. CO2 is emitted in percentage of about 60% by coal and of about 75% by petroleum.

Therefore, natural gas is the most environmentally friendly fossil fuel. Efficiency of natural gas

fueled furnace, particularly conventional furnace, is about 60% to about 90% for pulse

combination furnace and boiler. The strengthen environmental regulation causes the role of

catalyst in natural gas combustion becomes more important due to combustion products are

extremely low levels of NOX and simultaneously low levels of carbon monoxide (CO) and

unburned hydrocarbons (UHC). Another type of residential and industrial application is radiant

premixed catalytic combustion. In this system catalyst is in form of honeycomb, tube or fibers.

Mixture of gas and air are introduced into the catalyst which is burnt by both catalytic and gas-

phase oxidation, radiating energy from catalyst surface. In power density of about 120 kW/m2

and near reaction stoichiometry this system gives emission of NOX less than 5 ppm and CO of

about 150 ppm

Natural Gas Storage. Natural gas can be stored in a variety of ways. Usually, it is held

in underground formations, i.e. in depleted oil or gas reservoirs, in natural aquifers, in cavities

created in large underground salt deposits and in reconditioned hard rock mine. Gas is injected

and withdrawn from these formations using much of the same type of well drilling and

production equipment found in a working natural gas field.

Methane Hydrate is a cage-like lattice of ice containing trapped molecules of methane.

Actually, the name for its parent class of compounds is clathrates. Methane hydrates form in

generally two types of geologic settings: on land in permafrost regions where cold temperatures

persist in shallow sediments and beneath the ocean floor at water depths greater than about

500 meters where high pressures dominate. The hydrate deposits themselves may be several

hundred meters thick. These crystals, although unmistakably a combination of both water and

natural gas, would often form at temperatures well above the freezing point of ordinary ice.

Worldwide, estimates of the natural gas potential of methane hydrates approach 400 million

trillion cubic feet - a staggering figure compared to the 5,000 trillion cubic feet that make up the

world's currently known gas reserves. This huge potential, alone, warrants a new look at

advanced technologies that might one day reliably and cost-effectively detect and produce

natural gas from methane hydrates.

Coal Bed Methane. Methane, or natural gas, is usually associated with petroleum.

However, this gas can also be found in coal beds. Methane is produced by microbial processes

or from a thermal process due to the depth and heat of the coal bed. Methane reserves are

most often found in coal seams close to the Earth's surface. Water gets trapped in these seams

and creates pressure, which holds the gas inside the seam. Coal is usually has a large surface

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area enabling coal beds to storing a large amount of methane gas. Coal beds provide a

relatively cheap source of natural gas, because the beds are often close to the surface which

makes access and well drilling easier.

9.3 Coal Technology Coal plays an important role in the world’s energy system and hence global economic

and social development. However, further development in coal industries should recognize their

ability to meet the challenge of environmental sustainability. Programs and technologies aiming

to significantly reduce the potential greenhouse impact of coal and other carbon-intense would

determine the sustainable role of coal in the global energy mix.

The technologies employed and being developed to meet coal’s environmental

challenges-collectively referred as clean coal technology (CCT). Clean coal technology

represents a continuously developing range of option to suit different conditions and challenges

in the life-cycle of coal. In general the life-cycle of coal can be classified into several activities: (i)

coal extraction through surface and underground mining, (ii) coal beneficiation / preparation, (iii)

coal storage and transportation, and (iv) coal utilization. The environmental issues regarding the

activities through out the life-cycle coal can be summaries as follows:

• reducing the impact of coal mining activities on the existing forests and coal mine

rehabilitation,

• reducing SO2 emission and improve thermal efficiency by coal cleaning,

• reducing potential loss in energy content due to spontaneous combustion during coal

storage and transportation.

• reducing greenhouse gas emission, particulate and trace elements from coal utilization

activities.

In general, Figure 9.3 represents the life-cycle of coal and the area of clean coal

technology developments.

Coal Mining involves two widely applied techniques, i.e. surface and underground

mining. Surface mining only economic when the coal seam is near the surface. The equipment

used includes: draglines; power shovels; large trucks, which transport overburden and coal;

bucket wheel excavators; and high capacity conveyors. This method is widely used in the USA,

Australia and Indonesia. Currently, almost two-thirds of hard coal production worldwide comes

from underground mines. Good coal mining

practices including coal mine rehabilitation would secure safety and sustainability of the mining

area and its surrounding.

Coal Beneficiation. Depend upon the site geological structure, as-mined coal has

variable quality and contains substances such as clay, sand and carbonates. Coal preparation

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or coal washing/cleaning – also known as coal beneficiation is required to clean and to remove

mineral matter from mined coal. The coal is also sized and blended to meet customer

specifications. Cleaner coal usually has better quality representing by higher value and lower

sulfur and mineral constituents.

The coal beneficiation process involves characterization, liberation, separation and

disposition. The composition of the different raw coal particles is identified during the

characterization process. Liberation involves crushing the mined coal and reducing it to very fine

particles. Separation is the partitioning of the individual particles into their appropriate size

groupings and separating the mineral matter particles from the coal. Finally the disposition stage

involves the dewatering and storage of the cleaned coal and the disposal of the mineral matter.

Coal Storage and Transportation. During long-term storage in open air stockpiles or

long-distance transportation most coals are susceptible to weathering and oxidation. This

oxidation is undesirable because it consumes or reduces the energy available in the coal. In

addition to degrading the energy potential of the coal, the exothermic reaction of coal raises the

internal temperature of the stockpile, increasing the risk of spontaneous combustion. The

application of stockpile management principles could reduce weathering and oxidation

problems.

Figure 9.3 The life cycle of coal and the area of clean coal technology

BENEFICIATION STORAGE and

TRANSPORTATION PRE-COMBUSTION

POST-COMBUSTION

UTILIZATION : POWER GENERATION

• Sustainable mining activities

• Mine site rehabilitation

• Coal up-grading, briquetting,

• Bio-coal, synergies with renewables

• Improve storage design and efficiency

• Gasification, liquefaction

• Pulverized coal combustion

• Fluidized bed combustion: AFBC, CFBC, PFBC, IGCC

• Pressurized pulverized bed combustion

• Supercritical and ultra supercritical technology

• Activated carbon injection

• Electrostatic precipitators

• Fabric fulters • Flue gas

desulphurization • Hot gas filtration

systems • SCR dan SNCR • Wet particle

scrubbers

MINING

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Coal Utilization

Pre-combustion technologies

Coal gasification process is carried out in an apparatus called coal gasifier. A gasifier

converts hydrocarbon feedstock into gaseous components. In a gasifier, coal is fed at the top of

the gasifier through a lockhopper. The coal reacts while moving down through the gasifier. The

coal ash is removed from the bottom of the gasifier. From the bottom of the bed, steam and

oxygen injected, and react with the coal as the gases move up through the bed. This

countercurrent actions result in wide temperature difference between the top and bottom of the

gasifier. A gasifier differs from a combustor in that the amount of air or oxygen available inside

the gasifier is carefully controlled so that only a relatively small portion of the fuel burns

completely. This "partial oxidation" process provides the heat. Rather than burning, most of the

carbon-containing feedstock is chemically broken apart by the gasifier's heat and pressure,

setting into motion chemical reactions that produce "syngas." Syngas is primarily hydrogen,

carbon monoxide and other gaseous constituents, the proportions of which can vary depending

upon the conditions in the gasifier and the type of feedstock.

Coal liquefaction. Direct liquefaction processes include those that normally, proceed to

liquids in a single processing sequence, using solid coal as the primary reactant. Some direct

liquefaction schemes also involve chemical pretreatment steps. Indirect liquefaction processes

involve gasification as the first step conversion, followed by catalytic recombination of the

resulting synthesis gas mixture (CO + H2) to form hydrocarbon and oxygenates.

Hydrogenation or hydro-liquefaction and pyrolysis are the two means used for direct

liquefaction. In direct hydrogenation the primary reactions are a combination of homogeneous

thermal cracking. Process schemes that apply pyrolysis chemistry normally involve thermolysis

in an inert or reducing atmosphere and produce two principal products from coal: a tar and char.

Indirect liquefaction includes 3 (three) kinds of operating condition:

- The low pressure synthesis process, which operated at relatively low pressures, in the range

of 100-200kPa (1-2 atm). Catalysts were primarily cobalt based, with catalyst lives of one to

two months.

- The medium pressure synthesis process, which operated at pressures of 500-2,000 kPa (5-

20 atm). Cobalt catalysts similar to those used for the normal pressure typically used at

temperatures ranging from 170 to 200oC in tubular “heat exchanger” type reactors.

- The high pressure synthesis process, which operated at pressures of 10 to 20 MPa (100-200

atm) and temperatures in the 400oC ranges. The plant utilizes iron catalyst in both fixed and

fluidized reactor schemes.

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Efficient combustion technologies

Pulverized Coal Combustion. Conventional coal-fired generation today is normally via

the route of pulverized coal combustion (PCC). PCC can be used to fire a wide variety of coals,

although it is not always appropriate for those with high ash content. In PCC power stations,

coal is first pulverized then blown into a furnace where it is combusted at high temperature. The

resulting heat is used to raise steam, which drives a steam turbine and generator. Efficiencies

have been steadily rising – and hence emissions reducing – for many years and the trend

continues.

Fluidized Bed Combustion. In fluidized bed combustion (FBC), coal is burnt in a bed

of heated particles suspended in flowing air. At sufficiently high air velocity, the bed acts as a

fluid resulting in rapid mixing of the particles. This fluidizing action allows complete coal

combustion at relatively low temperatures. This improves combustion, heat transfer and

recovery of waste products. The higher heat exchanger efficiencies and better mixing of FBC

systems allows them to operate at lower temperatures than conventional (pulverized) coal-

burning systems. By elevating pressures within a bed, a high pressure gas stream can be used

to drive a gas turbine, generating electricity. FBC systems are popular because of the

technology’s fuel flexibility; almost any combustible material can be burnt. Fluidized bed

combustion (FBC), in its various forms, can reduce SOx and NOx by 90% or more.

Fluidized bed combustion technologies include atmospheric pressure fluidized bed

combustion in both bubbling (BFBC) and circulating (CFBC) beds, pressurized fluidized bed

combustion (PFBC), while pressurized circulating fluidized bed combustion (PCFBC) is being

demonstrated.

Circulating Fluidized Bed Combustion (CFBC) is the version of the technology that has

been most widely applied and for which there is the most extensive operating history.

Circulating fluidized bed combustion (CFBC) is of particular value for low grade, high ash coals

that are difficult to pulverize and which may have variable combustion characteristics, while still

ensuring low emissions of NOx and SOx. CFBC uses the same thermodynamic cycle as PCC

and therefore its power generation efficiency is in the same range, which is normally between

38% and 40%.

Pressurized Fluidized Bed Combustion (PFBC) is based on the combustion of coal

under pressure in a deep bubbling fluidized bed at 850°C. Depending on the velocity of the air

through the fluidized bed, two PFBC variants exist – bubbling bed PFBC (lower velocities) and

circulating bed PFBC (higher velocities).

Integrated Gasification Combined Cycle. In Integrated Gasification Combined Cycle

(IGCC) systems, coal is not combusted directly, but reacted with oxygen and steam to produce

a ‘syngas’ composed mainly of hydrogen and carbon monoxide. The syngas is cleaned of

impurities and then burned in a gas turbine to generate electricity and to produce steam for a

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steam power cycle. IGCC technology offers high efficiency levels and as much as 95-99% of

NOx and SOx emissions are removed.

Pressurized Pulverized Coal Combustion. Pressurized pulverized combustion of coal

(PPCC) is a technology currently under development, mainly in Germany. Similar to

conventional pulverized coal combustion, in that it is based on the combustion of a finely ground

cloud of coal particles, the heat released from combustion generates high pressure, high

temperature steam, which is used in steam turbine-generators to produce electricity. The

pressurized flue gases exit the boiler and are expanded through a gas turbine to generate

further electricity and to drive the gas turbine’s compressor; hence this is a form of combined

cycle power generation.

Supercritical & Ultra Supercritical Technology. Supercritical pulverized coal-fired

power plant operate at higher steam temperatures and pressures than conventional sub critical

PCC plant, and offer higher efficiencies – up to 45% – and hence lower emissions, including

emissions of CO2, for a given power output. Even higher efficiencies – up to 50% – can be

expected in ultra supercritical (USC) power plant, operating at very high temperatures and

pressure.

Post-combustion technologies

Activated Carbon Injection. Activated carbon injection involves activated carbon being

injected into the flue gas stream exiting the boiler and absorbing pollutants such as mercury

onto particulate matter, which is then removed in existing particulate control equipment.

Electrostatic Precipitators (ESPs). Electrostatic precipitators are the most widely

used particulate emissions control technology in coal-fired power generating facilities.

Particulate/dust laden flue gases are passed horizontally between collecting plates, where an

electrical field creates a charge on the particles. The particles are then attracted towards the

collecting plates, where they accumulate. In dry electrostatic precipitators the agglomerated

particles are then removed in a dry form by mechanical rapping or vibration to create a powder

for disposal. In wet electrostatic precipitators the particles are sprayed and washed off as slurry.

Fabric Filters. Fabric filters, also known as bag houses, collect particulates from the flue gas on

a tightly woven fabric by sieving and other mechanisms. The choice between electrostatic

separation and fabric filtration depends on coal type, plant size, and boiler type and

configuration. Fabric filters are useful for collecting particles with resistivities either too low or

too high for collection with electrostatic precipitators.

Flue Gas Desulphurization. Flue gas desulphurization (FGD) technologies are used to

remove sulphur emissions post-combustion. FGD technologies can be classified into six main

categories: wet scrubbers; spray dry scrubbers; sorbent injection processes; dry scrubbers; re-

generable processes; and combined SO2/NOx removal processes. Wet scrubbers tend to

dominate the global FGD market. The technology uses alkaline sorbent slurry, which is

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predominantly lime or limestone based. A ‘scrubbing vessel’ or scrubber is located downstream

of the boiler and flue gas cleaning plant, in which the sulphur dioxide in the flue gases reacts

with the limestone sludge, forming gypsum.

Hot Gas Filtration Systems. Hot gas filtration systems operate at higher temperatures

(500-1000°C) and pressures (1 - 2 MPa) than conventional particulate removal technologies,

eliminating the need for cooling of the gas. A range of technologies such as cyclones, ceramic

barrier filters, high-temperature fabric filters, granular bed filters and high-temperature ESPs

have been under development for many years. Some of these are in the demonstration stage

but further development is needed to enable commercial exploitation.

Selective Catalytic Reduction (SCR) & Selective Non-Catalytic Reduction (SNCR). In selective catalytic reduction systems, ammonia vapor is used as the reducing agent and is

injected into the flue gas stream, passing over a catalyst. The optimum temperature is usually

between 300°C and 400°C. The key difference between SCR and SNCR is the presence in

SCR systems of a catalyst, which accelerates the chemical reactions. The catalyst is needed

because SCR systems operate at much lower temperatures than SNCR; typical temperatures

for SNCR are 870-1200°C.

Wet Particle Scrubbers. Wet particle scrubbers for particulate control are used in a

limited number of coal-fired plants, with most of these installations located in the USA, to

capture fly ash in addition to sulphur dioxide (SO2). Water is injected into the flue gas stream to

form droplets. The fly ash particles impact with the droplets forming a wet by-product, which

then requires disposal. Wet particle scrubbers have a removal efficiency of 90-99.9%.

9.4 Renewable Energy Technology Renewable energy uses energy sources that are continually replenished by nature—the

sun, the wind, water, the earth’s heat, and plants. Renewable energy technologies turn these

fuels into usable forms of energy—most often electricity, but also heat, chemicals, or

mechanical power. One can classify renewable energy as follows:

Bio-energy or biomass energy

Wind energy (moving air masses driven by solar energy)

Solar energy

Hydropower

Ocean/Marine energy (such as wave energy, marine current energy, and energy from

tidal barrages)

Geothermal energy

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BIOMASS ENERGY

Biomass energy or bio-energy is the energy derived from biomass - a term that

generally refers to any plant or animal matters. Bio-energy in the form of heat can be produced

by using biomass directly as a fuel or by converting it to biogas or liquid bio-fuels. The heat

produced can be converted to electricity by delivering hot fluid through a gas turbine. The main

sources of biomass include industrial waste such as sugar cane waste (bagasse), wood waste

from forestry operations, and wastes from crop harvest such as straw and husks. Organic

wastes from animal husbandry may also be converted to biogas. Therefore, biomass energy

may be classified in the forms of:

1. Biofuels.

Biofuels are fuels for vehicles derived from biomass chemical or biochemical conversions

such as ethanol or biodiesel; fuels for engines obtained from biomass gasification via

physical or chemical conversion process to a secondary gaseous fuel; and fuels obtained

from biological conversion via bacterial anaerobic digestion to methane-rich biogas as a

gaseous fuel.

2. Biopower

Biopower is electricity generated from biomass combustion or gasification

Biofuels

Biomass can be converted directly into liquid fuels—liquid biofuels—for use in vehicles.

Conversion routes for producing biofuels from biomass and the differences in maturity of biofuel

options are illustrated in the following Figure 9.4.

Source: Girard and Fallot, 2006, brown box and arrow depict 1st generation biofuels, blue box and arrow indicate 2nd generation biofuels.

Figure 9.4 Production pathway of biofuels

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Biofuels such as ethanol prepared by fermentation of starch/sugar-rich plant, biodiesels

straight vegetable oil (SVO) and fatty acid methyl esters (FAME) from oil crops are called 1st

generation because these technologies already exist.

The second generation biofuels assure clear advantages over first generation biofuels,

in terms of land-use efficiency, and environmental performance. Large quantities of

lignocellulosic feedstock from biomass residues and wastes are already available, and can be

more readily prolonged compared to food crops.

Ethanol

Ethanol can be mass-produced by fermentation of sugar or by hydration of ethylene

from petroleum and other sources. Current interest in ethanol lies in the production derived from

crops (bio-ethanol), since it is a sustainable energy resource that offers environmental and

long-term economic advantages over fossil fuels, like gasoline or diesel. It is readily obtained

from the starch or sugar in a wide variety of crops. Ethanol fuel production depends on

availability of land area, soil, water, and sunlight

Biodiesel

First generation biodiesel uses oilseed-yielding plants like palm, jatropha, castor, soy,

rapeseed, etc. from which straight vegetable oils (SVO) can be derived by physical and

chemical treatments. SVO can then be further processed into fatty acid methyl esters (FAME),

which are also known as biodiesels. Another route for biodiesels is through hydro thermal

upgrading (HTU) of unprocessed bio-oils so that no transesterification is needed.

.Biopower

Most electricity generated using biomass today is by direct combustion using

conventional boilers. These boilers burn primarily waste wood products generated by the

agriculture and wood-processing industries. When burned, the wood waste produces steam,

which is used to spin a turbine. The spinning turbine activates a generator that produces

electricity.

The low-cost option for the use of biomass is cofiring with coal in existing boilers.

Cofiring refers to the practice of introducing biomass as a supplementary energy source in high-

efficiency boilers. The current coal-fired power generating system substituting biomass-based

renewable carbon for fossil carbon represents a direct system for carbon mitigation. Extensive

demonstrations and trials have shown that effective substitutions of biomass energy can be

made up to about 15 percent of the total energy input with little more than burner and feed

intake system modifications to existing stations. Since the size of large-scale power boilers

ranges from 100 MW to 1.3 GW, the biomass potential in a single boiler ranges from 15 MW to

150 MW. Preparation of biomass for cofiring involves well-known commercial technologies.

Since biomass in general has significantly less sulfur than coal, there is a SO2 benefit, and early

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test results suggest that there is a potential reduction of NOx of up to 30 percent with woody

biomass. Investment levels are very site specific and are affected by the available space for

yarding and storing biomass, installation of size reduction and drying facilities, and the nature of

the boiler burner modifications. .

Another potentially attractive biopower option is based on gasification. Gasification for

power production involves the devolatilization and conversion of biomass in an atmosphere of

steam and air to produce a medium- or low-calorific gas. This "biogas" is then used as fuel in

combined cycle power generation involving a gas turbine topping cycle and a steam turbine

bottoming cycle. Biomass gasification systems will also stand ready to provide fuel to fuelcell

and hybrid fuel-cell/gas turbine systems, particularly in developing countries or rural areas that

do not have access to cheap fossil fuels or that have an undependable transmission

infrastructure. The first generation of biomass GCC systems would realize efficiencies nearly

double those of the existing industry. In a cogeneration application, efficiencies could exceed 80

percent. This technology is very near to commercial availability, with one mid-size plant

operating in Finland. Small modular biomass gasification systems are well suited for providing

isolated communities with electricity. Producing electricity from biomass is most cost effective if

biomass power or biopower plants are located near biomass feedstocks

In addition, the decay of biomass in landfills produces gas (primarily methane) naturally,

which can be harvested and burned in a boiler to produce steam for generating electricity.

WIND ENERGY

A wind turbine converts the energy in the wind into electrical energy or mechanical

energy to pump water or grind grain. Wind turbines are rated by their maximum power output in

kilowatts (kW) or megawatts (1,000 kW, or MW). For commercial utility-sized projects, the most

common turbines available in the market are in the range of 600 kW to 1 MW – large enough to

supply electricity to 600 - 1,000 homes. The newest commercial turbines are rated at 1.5-2.5

megawatts. A typical 600 kW turbine has a blade diameter of 35 meters and is mounted on a 50

meters concrete or steel tower. Most commercial wind turbines operating today are at sites with

average wind speeds greater than six meters/ second (m/s) or 22 km/h. A prime wind site will

have an annual average wind speed in excess of 7.5 m/s (27 km/h).

Advantages

Wind energy is fueled by the wind, so it's a clean fuel source. Wind energy doesn't

pollute the air like power plants that rely on combustion of fossil fuels, such as coal or natural

gas. Wind turbines don't produce atmospheric emissions that cause acid rain or greenhouse

gasses.

Wind energy relies on the renewable power of the wind, which can't be used up. Wind is

actually a form of solar energy; winds are caused by the heating of the atmosphere by the sun,

the rotation of the earth, and the earth's surface irregularities. Wind energy is one of the lowest-

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priced renewable energy technologies available today, costing between 4 and 6 cents per

kilowatt-hour, depending upon the wind resource and project financing of the particular project.

Wind turbines can be built on farms or ranches, thus benefiting the economy in rural

areas, where most of the best wind sites are found. Farmers and ranchers can continue to work

the land because the wind turbines use only a fraction of the land. Wind power plant owners

make rent payments to the farmer or rancher for the use of the land.

Disadvantages

Wind power must compete with conventional generation sources on a cost basis.

Depending on how energetic a wind site is, the wind farm may or may not be cost competitive.

Even though the cost of wind power has decreased dramatically in the past 10 years, the

technology requires a higher initial investment than fossil-fueled generators.

The major challenge to using wind as a source of power is that the wind is intermittent

and it does not always blow when electricity is needed. Wind energy cannot be stored (unless

batteries are used); and not all winds can be harnessed to meet the timing of electricity

demands. Good wind sites are often located in remote locations, far from cities where the

electricity is needed. Effective storing of electricity could enhance the value and reduce the

uncertainty of wind-generated electricity through the levelling out of delivered power. There is a

need for different storage techniques at different time scales.

Although wind power plants have relatively little impact on the environment compared to

other conventional power plants, there is some concern over the noise produced by the rotor

blades, aesthetic (visual) impacts, and sometimes birds have been killed by flying into the

rotors. Most of these problems have been resolved or greatly reduced through technological

development or by properly siting wind plants.

Stand-alone turbines will be built in vast numbers, but the installed total capacity may

not be large. However, the value of electricity from these machines can be of great importance,

such as in remote locations where grid connection is not feasible. System integration of wind

generators with other power sources such as photovoltaic solar cells (PV) or diesel generating

systems is essential in small grids where high reliability is required

SOLAR ENERGY

Solar energy can be used as (a) solar thermal and (b) photovoltaic solar electricity.

Solar Thermal

The sun’s energy can be collected directly to create both high temperature steam

(greater than 100oC) and low temperature heat (less than 100oC) for use in a variety of heat and

power applications. High temperature solar thermal systems use mirrors and other reflective

surfaces to concentrate solar radiation. Parabolic dish systems concentrate solar radiation to a

single point to produce temperatures in excess of 100oC. Line-focus parabolic concentrators

focus solar radiation along a single axis to generate high temperatures. Central receiver

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systems use mirrors to focus solar radiation on a central boiler. The resulting high temperatures

can be used to create steam to either drive electric turbine generators, or to power chemical

processes such as the production of hydrogen.

Low temperature solar thermal systems collect solar radiation to heat air and water for

industrial applications including: space heating for homes, offices and greenhouses, domestic

and industrial hot water, pool heating, desalination, solar cooking, and crop drying.

These technologies include passive and active systems. Passive systems collect

energy without the need for pumps or motors, generally through the orientation, materials, and

construction of a collector. These properties allow the collector to absorb, store, and use solar

radiation. Passive systems are particularly suited to the design of buildings (where the building

itself acts as the collector) and thermo siphoning solar hot water systems. In colder climates, a

passive solar system can reduce heating costs by up to 40 percent while in hotter climates,

passive systems can reduce the absorption of solar radiation and thus reduce cooling costs.

The most common active systems use pumps to circulate water or another heat absorbing fluid

through a solar collector. These collectors are most commonly made of copper tubes bonded to

a metal plate, painted black, and encapsulated within an insulated box covered by a glass

panel.

Photovoltaic Solar Electricity

A photovoltaic (PV) cell generally consists of two or more semiconductor layers. These

layers have the interesting property of generating electrons when they absorb sunlight. Sunlight

is composed of photons, or particles of solar energy. When photons are absorbed by the

semiconductor, the energy of the photon is transferred to an electron in an atom of the material.

This energised electron is able to escape from the material to become part of the direct current

(DC) in an electric circuit. A number of different types of semiconductor materials can be used in

PV cells. These include silicon, copper indium diselenide, cadmium telluride and gallium

arsenide – each has its advantages and disadvantages and there is no one ideal material for all

types of applications. Silicon is the most common type of semiconductor material used at this

time and happens to be one of the most abundant materials on Earth.

Most PV cells are made of one of three types of very pure silicon – monocrystalline (the

cell contains one silicon crystal), polycrystalline (the cell contains many sili

con crystals) or amorphous (a thin layer of non-crystalline silicon). Monocrystalline silicon cells

are the most efficient but also the most costly to produce. Amorphous silicon cells are the least

efficient but are flexible and so can be attached to flexible steel or plastic surfaces. These are

very useful for certain applications. The semiconductor material is attached to a metallic grid

that collects the electrons generated and transfers them to the external load. Another metallic

grid backs the semiconductor layers to complete the electrical circuit and transfer the electrons

back to the semiconductor material. A PV cell is covered with low-iron content glass or some

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other kind of transparent encapsulant to seal the cell from the external environment. This glass

cover is backed with an anti-reflective coating to allow as much sunlight as possible to penetrate

through to the semiconductor layers.

Photovoltaic cells come in many sizes, but most are 10 cm by 10 cm and generate

about half a volt of electricity. PV cells are encapsulated into modules, several of which are

combined into an array to produce higher voltages and increased power. A 12-volt module, for

example, depending on its power output, could have 30 to 40 PV cells. A module producing 50

watts of power measures approximately 40 cm by 100 cm. PV arrays are not highly efficient,

converting only 12 to 15 per cent of the sun’s light into electricity, but laboratory prototypes are

reaching 30 per cent efficiency. PV modules generate direct current (DC). Most electric devices

require 220-volt alternating current (AC) as supplied by utilities. A device known as an inverter

converts DC to AC current. Inverters vary in size and in the quality of electricity they supply.

Less expensive inverters are suitable for simple loads, such as lights and water pumps, but

models with good quality waveform output are needed to power electronic devices such as TVs,

stereos, microwave ovens and computers. A PV array is usually part of a system that may also

include energy storage devices (usually batteries), support frames and electronic controllers; all

these systems are collectively referred to as the balance-of-system or BOS.

Efficiency of photovoltaic cells

The conversion efficiency of a PV cell is the proportion of light energy falling on the cell

surface that is converted to electrical energy. Much research has gone into improving the

efficiency of PV cells while also reducing the cost of production. This is very important in order

to make PV energy competitive with other sources of energy, such as coal or gas, and to

develop systems that use as little surface area as possible per unit of energy produced. The

earliest PV cells were less than 2% efficient. Today, mass produced PV modules using

monocrsytalline silicon are generally 15-18% efficient (the actual efficiency depending on such

factors as the strength of light and the temperature), although some of the newest modules

being manufactured have been verified as over 20% efficient. Modules made of polycrystalline

silicon cells are 12-15% efficient. Amorphous silicon cells are only 6-10% efficient, but this is

compensated by the fact that their performance degrades less than other cells at normal

working temperatures. To make an efficient silicon PV cell, the crystalline structure of the silicon

must be very pure, which makes the cost of manufacturing this material quite high. Furthermore,

the silicon doping processing must be done very carefully and precisely, which again adds to

the manufacturing costs. However, manufacturing costs are decreasing as the manufacturing

technology improves and demand increases. Because the sun's energy is abundant and free,

efficiency is usually not the major factor limiting the use of PV today. This is because there is

usually more than enough area on a structure for PV modules to generate the energy required,

particularly if the PV material can perform another function, such as acting as a roof or a wall

cladding. The cost of manufacturing the PV module is usually the limiting factor today.

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PV modules have a power and voltage rating determined under "standard conditions" of

solar input of 1000W/m2 and a temperature of 25oC. Thus, a module rated at 75Wp (the "p"

stands for "peak") will produce 75 watts of power under standard conditions. Typical system

size varies from 50 watt (W) to 1 kilowatt (kW) for stand-alone systems with battery storage and

small water pumping systems; from 500 W to 5 kW for roof-top grid connected systems and

larger water pumping systems; and from 10 kW to megawatts for grid connected ground-based

systems and larger building integrated systems.

HYDROPOWER

The energy in falling water can be converted into electrical energy or into mechanical

energy to pump water. The amount of energy that can be captured is a function of the vertical

distance the water drops and the volume of the water. The definition of small-scale hydropower

varies, only projects that have less than 10 megawatts (MW) of generating capacity are

considered here. This definition also includes mini-hydro (<1 MW), micro-hydro (<100 kilowatts,

or kW), and pico-hydro (<1 kW).

Most conventional hydroelectric plants include four major components:

1. Dam. It raises the water level of the river to create falling water. It also controls the flow of

water. The reservoir formed is, in effect, stored energy.

2. Turbine. The force of falling water pushing against the turbine's blades causes the turbine to

spin. A water turbine is much like a windmill, except the energy is provided by falling water

instead of wind. The turbine converts the kinetic energy of falling water into mechanical

energy.

3. Generator. It is connected to the turbine by shafts and possibly gears so when the turbine

spins it causes the generator to spin also. It converts the mechanical energy from the

turbine into electric energy. Generators in hydropower plants work just like the generators in

other types of power plants.

4. Transmission lines. They conduct electricity from the hydropower plant to homes and

business.

The main components of a small-scale hydro (SSH) system are a turbine and a

generator. Other components include the physical structures to direct and control the flow of

water, mechanical and/or electronic controllers, and structures to house the associated

equipment. Small-scale hydro systems are modular and can generally be sized to meet

individual or community needs. However, the financial viability of a project is subject to the

available water resource and the distance the generated electricity must be transmitted.

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Advantages

Hydropower is a fueled by water, so it's a clean fuel source. Hydropower doesn't pollute the air

like power plants that burn fossil fuels, such as coal or natural gas. Hydropower relies on the

water cycle, which is driven by the sun, thus it's a renewable power source. Hydropower is

generally available as needed; engineers can control the flow of water through the turbines to

produce electricity on demand.

Hydropower plants provide benefits in addition to clean electricity. Impoundment

hydropower creates reservoirs that offer a variety of recreational opportunities, notably fishing,

swimming, and boating. Other benefits may include water supply and flood control.

Disadvantages

Most of the adverse impacts of dams are caused by habitat alterations. Reservoirs

associated with large dams can cover land and river habitat with water and displace human

populations. Diverting water out of the stream channel (or storing water for future electrical

generation) can dry out streamside vegetation. Insufficient stream flow degrades habitat for fish

and other aquatic organisms in the affected river below the dam.

Water in the reservoir is stagnant compared to a free-flowing river, so water-borne

sediments and nutrients can be trapped, resulting in the undesirable growth and spread of algae

and aquatic weeds. In some cases, water spilled from high dams may become supersaturated

with nitrogen gas and cause gas-bubble disease in aquatic organisms inhabiting the tailwaters

below the hydropower plant.

Hydropower projects can also affect aquatic organisms directly. The dam can block

upstream movements of migratory fish. Downstream-moving fish may be drawn into the power

plant intake flow and pass through the turbine. These fish are exposed to physical stresses

(pressure changes, shear, turbulence, strike) that may cause disorientation, physiological

stress, injury, or death. Fish populations can be impacted if fish cannot migrate upstream past

impoundment dams to spawning grounds or if they cannot migrate downstream to the ocean.

Upstream fish passage can be aided using fish ladders or elevators. Downstream fish passage

is aided by diverting fish from turbine intakes using screens or racks or even underwater lights

and sounds, and by maintaining a minimum spill flow past the turbine.

In the US, biological tests are being conducted that will quantify the physical stresses

that cause injury or death to fish. In addition to these tests, tools are being developed to help

both the engineers and biologists to include a sensor fish, which is a "crash dummy fish." It will

be able to measure the physical stresses in a turbine passage and can be used instead of live

fish to gather information. Another tool is the development of a computational fluid dynamics

program that models potential fish behavior in the turbine passage. The test results and tools

will help turbine manufacturers design a more environmentally friendly turbine, which will reduce

the physical stresses exposed to fish. New products such as greaseless bearings eliminate the

possibility of petroleum products being released in the water.

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OCEAN/MARINE ENERGY

Oceans cover two-thirds of the earth’s surface. These bodies of water are vast

reservoirs of renewable energy. In a four-day period, the planet's oceans absorb an amount of

thermal energy from the sun and kinetic energy from the wind equivalent to all the world's

known oil reserves. Several technologies exist for harnessing these vast reserves of energy for

useful purposes. The most promising are ocean thermal energy conversion (OTEC) and wave

power plants. Both of these produce electricity from the oceans' reserves of renewable energy.

As the ultimate source of energy from the oceans is the sun, ocean energy systems are

renewable, have no fuel costs and are relatively nonpolluting when compared to conventional

sources of energy such as coal, oil and natural gas.

Ocean Thermal Energy Conversion (OTEC) power plants exploit the difference in

temperature between warm surface waters heated by the sun and colder waters found at ocean

depths to generate electricity. A temperature difference of 20°C or more between surface waters

and water at depths of up to 1000 m is required. OTEC power plants can be located either on-

shore or at sea, with the generated electricity transmitted to shore by electrical cables or used

on site for the manufacture of electricity intensive products or fuels. There are three potential

types of OTEC power plants, open-cycle, and closed-cycle and hybrid systems. Closed-cycle

systems use the ocean's warm surface water to vaporize a working fluid, which has a low-

boiling point, such as ammonia. The vapor expands and turns a turbine. The turbine then

activates a generator to produce electricity. Open-cycle systems actually boil the seawater by

operating at low pressures. This produces steam that passes through a turbine/generator.

Hybrid systems combine both closed-cycle and open-cycle systems.

GEOTHERMAL ENERGY

Geothermal energy is the energy contained in the heated rock and fluid that fills the

fractures and pores within the earth's crust. It originates from radioactive decay deep within the

Earth and can exist as hot water, steam, or hot dry rocks. Commercial forms of geothermal

energy are recovered from wells drilled 100–4,500 meters below the Earth’s surface. The

technology is well proven, relatively uncomplicated, and involves extracting energy via

conventional wells, pumps, and/or heat exchangers. Geothermal energy can be used directly or

indirectly, depending on the temperature of the geothermal resource. Geothermal resources are

classified as low temperature (less than 90°C), moderate temperature (90°C - 150°C), and high

temperature (greater than 150°C). The highest temperature resources are generally used only

for electric power generation and found in volcanic regions. Geothermal energy can be used

directly in temperatures ranging from about 35°C to 150°C to heat buildings, greenhouses,

aquaculture facilities and to provide industrial process heat. Indirectly, high temperature

geothermal steam can be used to drive a turbine and create electricity or in heat pumps.

Using geothermal energy directly is 50 to 70 percent efficient compared to the 5 to 20

percent possible for the indirect use of generating electricity (although using the waste heat from

generating electricity can also be used and thus boost the overall efficiency). Applications that

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use geothermal energy directly can also draw from both high and low temperature geothermal

energy resources.

Economics of Geothermal Energy

Geothermal power plants can produce electricity as cheaply as some conventional

power plants. It costs 4.5 to seven cents per kWh to produce electricity from hydrothermal

systems. In comparison, new coal-fired plants produce electricity at about four cents per kWh.

The cost of producing electricity over time is lower because the price and availability of the fuel

is stable and predictable. The fuel does not have to be imported or transported to the power

plant. The power plant literally sits on top of its fuel source. Initial construction costs for

geothermal power plants are high because geothermal wells and power plants must be

constructed at the same time.

Geothermal Energy and the Environment

Geothermal energy is a renewable energy source that does little damage to the

environment. Geothermal steam and hot water do contain naturally occurring traces of hydrogen

sulfide (a gas that smells like rotten eggs) and other gases and chemicals that can be harmful in

high concentrations. Geothermal power plants emit only about one to three percent of the sulfur

compounds that coal and oil-fired power plants do. Geothermal power plants use "scrubber"

systems to clean the air of hydrogen sulfide and the other gases. Sometimes the gases are

converted into marketable products, such as liquid fertilizer. Newer geothermal power plants

can even inject these gases back into the geothermal wells.

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9.5 Electricity Technology

The technological challenges in power generation are to develop more efficient (high

thermal efficiency) and more environmental friendly plants. There are promising advanced

power generation such as gas turbine based technologies especially combined cycle gas

turbine (CCGT), integrated gasification combined cycle (IGCC), small engines suitable for

distributed applications such as microturbines, and various fuel cell technologies. These

technologies are strategically important to meet electricity production with high efficiency and

greatly reduced emissions to the environment and taking into account their full fuel cycles.

Combined Cycle Gas Turbine (CCGT). A technology which combines gas turbines

and steam turbines, connected to one or more electrical generators at the same plant. The gas

turbine, usually fuelled by natural gas or oil, produces mechanical power, which drives the

generator, and heat in the form of hot exhaust gases. These gases are fed to a heat recovery

steam generator (HRSG), where steam is raised at pressure to drive a conventional steam

turbine which is also connected to an electrical generator. The thermal efficiency of a CCGT

could reach about 55 % which is higher than an open cycle turbine.

Microturbines are small gas turbines used to generate electricity. They occupy a small

space and typically have power outputs in the range of 25 to 300 kW. The small size of

microturbines is a major advantage that allows them to be situated right at the source of

electricity demand. This eliminates energy losses that usually occur when transmitting electricity

from power stations. Advantages of microturbines are quiet operation with little vibration, low

emission levels and, thermal efficiencies of 15-30%, low maintenance and high reliability.

However, the main draw back of microturbines is the limit to the number of times that they can

be started up and shutdown.

Integrated Gasification Combined Cycle (IGCC). The gas turbine is driven by firing a

gas fuel derived from the gasification of liquid and solid carbonaceous materials, such as coal

and biomass, the cycle is known as an Integrated Gasification Combined Cycle (IGCC). IGCC's

are able to convert liquid and solid fuels to electricity at high efficiencies and with low emissions.

In this cycle, carbon monoxide from the synthetic gas with the help of air can be converted into

CO2 , which will then be captured and sequestered into underground and ocean storages to

reduce greenhouse gas.

Combined Heat and Power (CHP) plant is one in which there is simultaneous

generation of usable heat and power (usually electricity) in a single process. The basic elements

comprise one or more prime movers usually driving electricity generators, where the steam or

hot water generated in the process may be utilized via heat recovery equipment for a variety of

purposes, including industrial processes, community heating, and space heating. The direct use

of heat which might otherwise be wasted (or which would otherwise have to be provided from

some alternative fuel use) means that CHP units can offer greater conversion efficiency than

simple electricity generators.

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Power Generation from Biomass. Biomass fuels range from wood by-products, sugar

cane and other agricultural residues to domestic/industrial wastes. The major driving force that led to

the development of fluidized-bed combustion was the need for more efficient combustion

technologies for the utilization of low-grade fuels such as biomass. Both Bubbling Fluidized-Bed (BFB)

and Circulating Fluidized-Bed (CFB) technologies have both received significant attention. Biomass IGCC

power plant technology is an advanced power generation technology for large-scale gasification in

the range of 30-100 MWe. Although fully demonstrated plant, which has achieved higher efficiencies

and lower emissions than conventional technologies, biomass IGCC can not compete at present with

natural gas combined cycles and low-cost conventional CFBs. Furthermore, a secured fuel supply for

a biomass IGCC plant over its lifetime is questionable.

Fuel Cells. The fuel cell converts fuel into electricity electrochemically, without first

burning it to produce heat. Fuel cells have attractive features for electricity markets

characterized by increasing competition and environmental regulations: high thermodynamic

efficiency (40-60%), because fuel cells convert chemical energy directly to electrical energy and

not involve conversion of heat to mechanical energy., low maintenance requirements, quiet

operation, near-zero air pollutant emissions without exhaust-gas controls, and high reliability.

Fuel cells are likely to be economically viable even in small-scale applications. Its properties

make it possible to site systems in small, unobtrusive generating facilities close to end users.

Such distributed power sources make cogeneration designs economically attractive and offer

the potential of reducing losses for electricity transmission and distribution equipment. Low-

temperature phosphoric acid fuel cells (PAFCs) and proton exchange membrane fuel cells

(PEMCs) are well suited for combined heat and power applications in small-to medium-scale

commercial and residential buildings, providing domestic hot water and space heating and

cooling. PEMC has high power density, fast variable power output so that it is appropriate to

automotive. The PAFC is the only commercial fuel cell. Several hundred PAFC power plants

(~200 kWe natural gas fuelled units) are operating. Plug Power is focusing on smaller (less than

35-kilowatt-electric) units and plans to install in residential. In initial applications it is expected

that most systems would use mainly existing natural gas infrastructure and, like PAFCs, process

natural gas at the point of use in an external fuel processor into an H2-rich gas the fuel cell can

use.

High-temperature (600 -1000oC) molten carbonate fuel cells (MCFCs) and solid-oxide

fuel cells (SOFCs) are targeted to medium- to large-scale industrial applications. They are well

suited for cogeneration, including applications that use the waste heat to operate heat-driven air

conditioners. They also offer the option of using directly natural gas or syngas derived through

gasification from coal or other feedstocks without an external fuel processor. Comparison of fuel

cell technology by type are illustrated in the following table.

228

Type of Fuel Cell

Characteristics Polymer Electrolyte Membrane Fuel Cell

(PEMC)

Phosphoric Acid Fuel Cell (PAFC)

Molten Carbonate Fuel Cell (MCFC)

Solid Oxide Fuel Cell (SOFC)

Electrolyte Ion Exchange

Membrane Phosphoric Acid Alkali Carbonates

Mixture Yutria Stabilized

Fuel H2 H2 H2, CO, HC’s H2, CO, HC’s Operating Temperature, oC

80 200 650 1,000

Charge Carrier H+ H+ CO32- O2

Cathode Reaction

½O2+2H++2e H2O

½O2+2H++2e H2O

O2+2CO+4e- 2CO32-

O2+2CO2+4e- 2CO32-

O2+4e- 2O2-

O2+4e- 2O2-

Anode Reaction H2 2H++2e H2 2H++2e 2CO+2CO32- 4

CO2+4e- 2H2+2CO3

2 2H2O+2 CO2+4e-

2CO+2O2- 2 CO2+4e- 2H2+2O2- 2 H2O +4e-

Electrolyte State Solid Immobilized liquid Immobilized liquid Solid Material of cell Carbon or Metal

Based Graphite Based Stainless Steel Ceramic

Catalyst Platinum Platinum Nickel Perovskites

Heat Generation None Low Quality High High

Efficiency, %LHV <40 40-45 50-60 50-60

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X. ECONOMICS OF ALTERNATIVE FUELS AND ELECTRICITY GENERATION


ECONOMICS OF ENERGY ALTERNATIVE

231

The Economics of Alternative Fuels and Electricity Generation

Synthetic Liquid Fuels Liquid synthetic fuels are fuels obtained by natural gas conversions called gas to liquids

(GTL), by coal conversion called coal to liquids (CTL), or by biomass conversions called

biomass to liquids (BTL). In principle, liquid synthetic fuels can be produced by two processes,

i.e. indirect liquefaction through a stage involving synthetic gas (mixture of hydrogen and carbon

monoxide) and direct liquefaction. The indirect liquefaction process starts from reforming

reactions in gasification to produce synthetic gas, followed by Fischer-Tropsch (FT) which

produces synthetic crude. The next stage involves upgrading of synthetic crude to synthetic

fuels especially synthetic diesel fuels known as FT diesel fuels and other side products such as

liquefied petroleum gas (LPG), kerosene and naphta. FT diesel fuels have some advantages

compared to oil-based diesel fuels i.e. low sulfur content (< 5ppm), low aromatic content (<1%),

high centane number (~70), biodegradable and non toxic. The liquid synthetic fuels can be

produced without significant infrastructure modification of oil-based diesel fuels. Their

combustion emissions are lower than those from fossil fuels (ultraclean fuels).

Direct coal liquefaction used for the production of the liquid synthetic fuels proceeds by

reacting coal and a solvent with hydrogen gas at high pressure and temperature to produce coal

liquid. The following stages of the liquefaction are similar to those in the indirect liquefaction.

Even though its efficiency is high, the quality of the products of the direct liquefaction is lower

than that obtained by the indirect liquefaction.

GTL technology is already proven and has achieved commercial stage. More than 950

million barrel synthetic fuel via FT process has been marketed through the entire world. GTL

plant in commercial scale with capacity 45,000 bpd has been operated since 1991 in Mossel

Bay, South Africa by PetroSA using Sasol license, and Shell in Bintulu Malaysia, Shell Middle

Distillate Synthesis (SMDS) with capacity 12,500 has been operated since 1993. More than

800,000 bpd of GTL plants just under EPC or on planning stage in Qatar (Sasol, Chevron,

ExxonMobil, Shell, and ConocoPhilips) involving about US $ 25 billion investment. GTL refinery

Oryx I in Qatar has capacity 34,000 bpd and operate on June 2006, meanwhile Escravos GTL

Nigeria has capacity 34,000 bpd will start to operate on 2008.

The economic aspect of GTL and CTL projects is affected primarily by capital cost of

plant which is relatively more expensive than that of oil refinery and feedstock price. As an

illustration, GTL project Oryx I in Qatar needs investment cost about US $ 0.95 billion for

refinery capacity of 34,000 bpd or about US $ 28,000/bpd. CTL refinery with capacity 80,000

bpd in China needs investment for US $ 3 billion or US $ 37,500/bpd. However, petroleum

refinery (PR) needs about US $ 12,000 to 16,000/bpd. BTL refinery is also still expensive

requiring about US $ 90,000/bpd. The most expensive components in GTL and CTL refinery

capital cost are synthesis gas production unit and FT reactor, so further effort should be directed

on cost reduction of these units.

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By using simple calculation (Figure 10.1) with assumption that US $ 1 equals to Rp

9,000,-, synthetic fuel distribution cost may be just 15% of petroleum fuels production cost. With

tax of about 15%, then it can be estimated that for gas price of US $ 2-3.5/mmbtu (equal to US

$ 20-35/barrel), the GTL fuel cost will be approximately Rp 2,700-3,700 per liter. By utilizing

lignite worth about US $ 10-20/ton (equals to US $ 4-8/barrel) for producing synthetic fuels, the

price of CTL synthetic fuels is about Rp 2,600-2,900 per liter. As the crude oil cost around US $

30-50/barrel, petroleum fuel price is estimated to be around Rp 2,900-4,200 per liter.

0

10

20

30

40

50

60

70

80

PR30 PR50 GTL20 GTL35 CTL4 CTL8

US$

/lb

Feedstocks Capex Opex Dist. Cost Taxes

Note: PR stands for petroleum refinery Source: Sasol, IFP, Foster Wheeler (data further processed)

Figure 10.1 Production cost of synthetic fuels

Liquid Biofuels Biofuels currently used in industrialized countries is 1st generation biodiesel produced

from rapeseed and sunflower, and bioethanol from starches. They have a typical feature that

their costs comprise mainly biomass feedstock costs, which cannot be flexibly reduced and may

even increase if demands from other uses rise or in the event of adverse weather conditions.

Feedstocks for current (1st generation) biofuels in developing countries are palm oil,

castor, soy for biodiesels, and cassava, sorghum, molasses etc. for ethanol. They are in

competition with food production, so that their economy is also affected by the development of

agricultural commodities on the world market.

233

Ethanol For conventional ethanol, production costs depend on feedstocks, plant investment,

and operation, and also on the revenue from byproducts. The following figure shows indicative

production costs of bioethanols from various feedstocks. The table shows that the lowest cost of

production of ethanol is found in the production based on sugar cane and straw feedstocks.

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7

Gasoline high

Gasoline low

Bioethanol straw

Bioethanol straw 2010

Bioethanol Wheat high

Bioethanol Wheat low

Bioethanol corn high

Bioethanol corn low

Bioethanol surgar beet high

Bioethanol surgar beet low

Bioethanol surgar cane high

Bioethanol surgar cane low

Molasses

(US$/liter)

Biomass cost O & M cost Other cost

Adopted from Girard and Fallot, 2006, except Bioethanol from molasses. The larger part of other cost is capital cost.

Figure 10.2 Comparison of bioethanol production costs

Biodiesel As for bioethanol, the largest biodiesel cost component (about 50-80%) comes from

the feedstocks. Remaining are plant and operating costs. The plant size also affects the

production cost. Feedstock production costs vary depending on where the crop is grown, quality

of soils, climate, fertilizers and pesticides used for crop plantation.

234

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9

Diesel high

Diesel low

Biodiesel rapeseed longterm

Biodiesel rapeseed high

Biodiesel rapeseed low

Biodiesel jatropha

Biodiesel soybean high

Biodiesel soybean low

US$/liter

Biomass cost O & M cost Other cost

Adopted from Girard and Fallot, 2005. The larger part of other cost is capital cost. Long-term cost of biodiesel is an estimate on the basis of better use of co-products.

Figure 10.3 Comparison of biodiesel production costs

Electricity Generation

Cost breakdown estimation of electricity generations based on chiefly renewable

technology can be summarized in the following table. It consists of specific investment cost,

fixed operational and maintenance cost, variable operational and maintenance cost, efficiency,

and capacity factor.

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Table 10.1 Typical cost breakdown of electricity generation

Investment

cost ($/kWe) Fixed O&M

($/kWe) Variable O&M

($/kWh) Efficiency Capacity

factor Wind onshore large 810 25 n.a. 0.24 Wind onshore small 900 22 n.a. 0.24 Wind offshore 1620 42.75 n.a. 0.375 PV off-grid 10000 45 n.a. 0.2 PV grid-connected 4860 18 n.a. 0.15 Solar thermal power 2160 27 n.a. 0.25 Fission: light water reactor 2070 45 n.a. 0.33 0.85 Mini hydro 1260 28 0.466 Large hydro 1850 30 0.392 Tidal power 2000 37.5 0.23 Geothermal 1200 30 0.7 Proton exchange membrane fuel cells 3000 14.5 0.0055 0.5 0.9 Natural gas solid oxide fuel cells 1180 35 0.005 0.63 0.75 Micro gas turbine 800 0.3 0.9 Gas combined cycle (CC) 510 10 0.002 0.55 0.8 Integrated gasification combined cycle (IGCC) 1315 28 0.008 0.43 0.8 Solid waste incineration 7000 67 0.01 0.25 0.75 Biomass fired conventional 1600 43 0.002 0.38 0.75 Biomass IGCC 1900 0.015 0.35 0.75

Source: Smekens et al, 2003.

The table demonstrates that a gas combined cycle requires the lowest investment

cost/kWe as well as lowest operating cost. The cycle may be prepared by burning natural gas,

fossil fuels and coals. However, a combined cycle which is integrated with gasification (IGCC)

will increase both investment and operating costs. The costs will even higher if gasification

utilizes biomass as feedstocks.

Renewable energy in general requires relatively high investment cost and moderate

operating cost. Among various renewable energy types, wind energy onshore is estimated to

have lowest investment cost. Photovoltaic, fuel cell and light water fission are still considered to

be expensive due to high investment cost associated with these types of electricity generation.

237

XI. ENERGY REGULATIONS


ENERGY REGULATION

239

ENERGY REGULATIONS

Figure 11.1 Oil and Gas Regulation Hierarchical Tree Structure

240

Figure 11.1 Oil and Gas Regulation Hierarchical Tree Structure (Continued)

Translated from that of Indonesian version available in www.esdm.go.id

241

Figure 11.2 Electricity Regulation Hierarchical Tree Structure

Translated from that of Indonesian version available in www.esdm.go.id Note : This Electricity Law was overturned by the Indonesian Constitutional Court in 2004, and currently under reviewed by the Government of Indonesia.

242

Figure 11.3 Geothermal Energy Regulation Hierarchical Tree Structure

Translated from that of Indonesian version available in www.esdm.go.id

243

XII. ENERGY CONSERVATION


ENERGY CONSERVATION

245

Energy Conservation

With the tendency of continuing increase in energy prices and stringent environmental

regulations, many governments have encouraged the implementation of energy conservation

measures, which also known as measures concerning the rational use of energy. The first oil

crisis in 1973 has triggered Japan and European countries to launch energy conservation

initiatives. On the supply side, the diversification of energy sources has been pushed forward by

switching to alternative energies such as natural gas, nuclear power or renewable energy. On

the demand side, on the other hand, the industrial sector is playing a central role in terms of

energy conservation.

In the meantime, concern on global warming has encouraged developed nations at the

3rd Session of the Conference of the Parties in Kyoto 1997 to cut their Green House Gas (GHG)

emissions. This agreement also known as Kyoto protocol boosted further effort of energy

conservation. This is not surprising since more than 90% of GHG consists of carbon dioxide and

approximately 90% of carbon dioxide is emitted from combustion of fossil fuels. That means

nearly 80 percent of GHG emissions originates from energy use. On the basis of this

reasoning, improvement in energy efficiency by energy conservation program can solve energy

and environmental problems simultaneously.

As part of the Kyoto protocol, Japan for example, pledged a 6% reduction in

greenhouse gas emission from the 1990 level, to be achieved in terms of the average annual

value for the 2008-2012. As a result, the Long-term Energy Supply-Demand Outlook was

reviewed and revised aiming to attain the GHG emission reduction target committed to Kyoto

protocol as illustrated in Figure 11.1. In the case of Business as Usual (BAU), energy

consumption and the emission of greenhouse gas in 2010 will increase respectively to

456million kL of crude oil equivalent and to 347 million carbon tons as CO2. To attain Japan’s

target of the Kyoto protocol commitment, it would need not only to maintain the energy

consumption in 2010 at 400 million kL, which means reducing it by 56 million kL through energy

conservation, but also to introduce more active energy supply measures with lower CO2

emissions, including new and non-fossil fuel energy technologies.

246

Source: Japan Energy Conservation Handbook 2003/2004, ECCJ, 2003.

Figure 11.1 GHG emission reduction target committed to Kyoto protocol.

As mentioned above, since the first oil crisis in 1973, many industrialized nations have

launched energy conservation initiatives. In Japan, the Law concerning the Rational Use of

Energy (Energy Conservation Law) was adopted in 1979, thus energy consumption efficiency

standards for vehicles, air conditioners, and electric refrigerators were set for the first time.

Some Asian countries also adopted energy conservation law, for example South Korea and

Thailand.

The increase of oil price recently and in years to come (Figure 11.2) is expected to

affect many countries to once again consider wide range policy to promote energy conservation

activities. Compare to industrialized countries, many ASEAN countries including Indonesia

consume less energy per capita, but have higher energy intensity (Figure 11.3).

247

Figure 11.2 Oil price between 1973 to 2005

0

100

200

300

400

500

600

Japan OECD Thailand Indonesia Malaysia NorthAmerica

German

inde

ks (J

apan

= 1

00)

Energy Insensity Energy per Capita

Source : National Energy Blueprint 2005-2025 (Blue Print PEN 2005-2025)

Figure 11.3 Energy intensity and energy consumption in ASEAN and some developed countries

248

In general, energy conservation potential of industry, transportation, household and

commercial sectors in Indonesia is quite high. Table 11.1 shows that energy efficiency

improvement of 15 to 30 % is achievable for typical for various sectors in Indonesia.

Table 11.1 Energy Conservation Potential in Indonesia

Energy Conservation Potential Sector

Total Consumption

(Thousand BOE) (Thousand BOE) (%)

Industry 194.35 29.15 -58.31 15 - 30

Transportation 169.73 42.43 25

Household and Commercial

134.63 13.46 – 40.39 10 – 30

Source : DGEEU, 2006

In Indonesia the first regulation regarding the energy conservation program was

introduced in 1982, as a response to high oil price at that time. The related regulations for

energy conservation can be summarized as follows.

• Presidential Instruction No. 9/1982 concerning the Reporting System of Energy Use in

Government-office Buildings,

• Presidential Decree No. 43/1991 concerning the Energy Conservation,

• Minister of Mines and Energy Decree acting as BAKOREN Chief No. 100.K/148/M.PE/

1995 concerning National Master Plan of Energy Conservation,

• Minister of Energy and Mineral Resources Decree No. 2/2004 concerning the Policy on

Renewable Energy Development and Energy Conservation (Green Energy),

• Minister of Energy and Mineral Resources Decree No. 0983.K/16/MEM /2004

concerning National Energy Policy.

• Presidential Instruction No. 10 / 2005 concerning Efficient Use of Energy.

• Ministerial Regulation No. 0031/2005 on Energy Ministerial Regulation No. 0031/2005

on Energy Conservation Procedure

• Presidential Decree No.5/2006 on National Energy Presidential Decree No.5/2006 on

National Energy Policy.

249

To encourage the implementation of energy conservation efforts in buildings, several

National Standards (SNI) have been introduced, for example:

- SNI 03-6389-2000 : Energy Conservation on Building Envelope

- SNI 03-6390-2000 : Energy Conservation on Air Conditioning System for Building

- SNI 03-6196-2000 : Energy Audit Procedure for Building

- SNI 03-6197-2000 : Energy Conservation on Lighting System for Building.

Effects of energy conservation in Indonesia’s primary energy demand, is estimated in

National Energy Blueprint 2005-2025. As shown in Fig. 11.4, without energy conservation effort

Indonesia’s primary energy demand in 2025 is expected to reach fivefold of the 2005 level. A

nation wide policy and strong commitment to implement energy conservation in all sectors is

pre-requisite in reducing primary energy demand to threefold as encouraged under energy

conservation scenario. As stated earlier, energy conservation measures have to objectives, (i)

to reduces energy demand and (ii) to meet greenhouse gas emission target.

Source : National Energy Blueprint 2005-2025 (Blue Print PEN 2005-2025)

Figure 11.4 Prediction of energy conservation measures on Indonesia’s primary energy

demand.

------ Business as Usual With energy conservation scenario

Ener

gy d

eman

d (M

illio

n B

OE

)

Year------ Business as Usual With energy conservation scenarioWith energy conservation scenario

Ener

gy d

eman

d (M

illio

n B

OE

)

YearBusiness as Usual With energy conservation scenario

Year

251


APPENDICES

253

APPENDICES

A1. Gross Energy Content

Gas - Natural Gas 37.23 MJ/m3 (*) - Ethane (liquid) 18.36 GJ/ m3 - 70 % ethane – 30 % propane 3.308 Million Btu/Barrel - Propane (liquid) 25.53 GJ/ m3 - 60 % butane – 40 % propane 4.130 Million Btu/Barrel - Butanes (liquid) 28.62 GJ/ m3 - Isobutane 3.974 Million Btu/Barrel - Pentanes Plus 35.17 GJ/ m3 - LPG 4.0 Million Btu/Barrel 3.7 Million Btu/Barrel Crude Oil - Light 38.51 GJ/ m3 - Heavy 40.90 GJ/ m3 Coal - Anthracite 29.30 GJ/metric ton - Imported Coal 25.10 GJ/metric ton - Kalimantan Coal 25.10 GJ/metric ton - Ombilin Coal 28.40 GJ/metric ton - Tanjung Enim Coal 22.20 GJ/metric ton - Lignite 18.10 GJ/metric ton Petroleum Products - Aviation Gasoline 32.60 GJ/ m3 - Gasoline Super 34.20 GJ/ m3 - Gasoline Premium 34.20 GJ/ m3 - Aviation Turbo Fuel 34.60 GJ/ m3 - Kerosene 34.80 GJ/ m3 - ADO 38.10 GJ/ m3 - IDO 38.80 GJ/ m3 - Light Fuel Oil 38.68 GJ/ m3 - Heavy Fuel Oil 41.73 GJ/ m3 - Petroleum Coke 42.38 GJ/ m3 - Gasohol (10% ethanol, 90% gasoline) 120,900 Btu/gallon

- Middle Distillate or Diesel Fuel Oil 138,690 Btu/gallon

- Residual Fuel Oil 149,690 Btu/gallon

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Ethanol 84,400 Btu/gallon

Methanol 62,800 Btu/gallon

Biofuel Wood (wet, freshly cut) 10.9 MJ/kg

Wood (air dry, humid zone) 15.5 MJ/kg

Wood (air dry, dry zone) 16.6 MJ/kg

Wood (oven dry) 20.0 MJ/kg

Charcoal 29.0 MJ/kg

Bagasse (wet) 8.2 MJ/kg

Bagasse (air dry) 16.2 MJ/kg

Coffee husks 16.0 MJ/kg

Rice hulls (air dry) 14.4 MJ/kg

Wheat straw 15.2 MJ/kg

Corn (stalk) 14.7 MJ/kg

Corn (cobs) 15.4 MJ/kg

Cotton stalk 16.4 MJ/kg

Coconut husks 9.8 MJ/kg

Coconut shells 17.9 MJ/kg Chaff (Seed Casing) 14.6 MJ/kg Pyrolysis oil 17.5 MJ/kg Ecalene MT 28.4 MJ/kg Fat 37.665 MJ/kg Biodiesel 37.8 MJ/kg Sunflower oil 39.49 MJ/kg Castor Oil 39.5 MJ/kg Olive Oil 39.25-39.25 MJ/kg Animal Manure/Waste 10 MJ/kg

Electricity 3,413 Btu/kilowatt-hour Note : The (*) energy content of 37.23 MJ/m3 approximately the equivalent of 1,000 BTU/ft3 in the imperial system. The actual energy content will vary depending on the amount of natural gas liquids (mostly ethane) contained in the gas.

255

A.2 Conversion Factor

Type of Energy From To Barrel Oil Equivalent/ BOE

Refinery Fuels Refenery Feedstock Barrel 1.0423 Refinery Fuel Gas (RFG) Barrel 1.6728 Refinery Fuel Oil (RFO) Barrel 1.1236 Petroleum Products ADO Kilo Liter 6.4871 Aviation Gasoil (avgas) Kilo Liter 5.5530 Aviation Turbin Gas (avtur) Kilo Liter 5.8907 Fuel Oil (FO) Kilo Liter 6.9612 Industrial Diesel Oil (IDO) Kilo Liter 6.6078 Kerosene Kilo Liter 5.9274 Premium Kilo Liter 5.8275 Premix Kilo Liter 5.8275 Super Tt Kilo Liter 5.8275 Coal Antrasit Ton 4.9893 Import Coal Ton 4.2766 Ombilin Coal Ton 4.8452 Tanjung Enim Coal Ton 3.7778 Briqutte Ton 3.5638 Riau Peat Ton 2.5452 Lignit Ton 3.0649 Biomass Charcoal Ton 4.9713 Woods Ton 2.2979 Crude Oil, Condensate, and Products Condensate Barrel 0.9545 Crude Oil Barrel 1.0000 Products Barrel 1.0200 Geothermal MWh 1.5937 Natural Gas and Products Natural Gas Thousand SCF 0.1796 CNG Thousand KCal 0.0007 City Gas Thousand KCal 0.0007 LNG MMBTU 0.1796 LNG Ton 8.0532 LPG Ton 8.5246 Hydropower MWh 1.5937 Electricity MWh 0.6130

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Crude Oil

ton (metric) kilolitres barrels US Gallon ton/yearFrom To

Multiply by ton (metric) 1 1.165 7.33 307.86 --kilolitres 0.8581 1 6.2898 264.17 --barrels 0.1364 0.159 1 42 --US Gallon 0.00325 0.0038 0.0238 1 --Barrels/day -- -- -- -- 49.8

Natural Gas and LNG Billion cubic meters NG

Billion cubic feet

NG

Million ton oil equivalent

Million ton LNG

Trillion British thermal units

Million barrels oil equivalent

From To Multiply by

1 billion cubic meters NG

1 35.3 0.90 0.73 36 6.29

1 billion cubic feet NG

0.028 1 0.026 0.021 1.03 0.18

1 million ton oil equivalent

1.111 39.2 1 0.805 40.4 7.33

1 million ton LNG

1.38 48.7 1.23 1 52.0 8.68

1 trillion British thermal units

0.028 0.98 0.025 0.02 1 0.17

1 million barrels oil equivalent

0.16 5.61 0.14 0.12 5.8 1

Products

barrels to ton ton to barrels kilolitres to ton ton to kilolitresFrom To

Convert Multiply by LPG 0.086 11.6 0.542 1.844Gasoline 0.118 8.5 0.740 1.351Kerosene 0.128 7.8 0.806 1.240Gas Oil/ Diesel 0.133 7.5 0.839 1.192Fuel Oil 0.149 6.7 0.939 1.065

PREFIX UNIT Thousand : 103 Kilo : K Million : 106 Mega : MBillion : 109 Giga : G Trillion : 1012 Tera : T Quadrillion : 1015 Peta : P Quintillion : 1018 Exa : E

1 metric tons = 2204.62 lb = 1.1023 short tons 1 kilolitre = 6.2898 barrels = 1 cubic meters 1 kilocalorie (kcal) = 4.187 kJ = 3.968 BTU 1 kilo joule (kJ) = 0.239 kcal = 0.948 BTU 1 British Thermal Unit (BTU) = 0.252 kcal = 1.055 kJ1 kWh = 860 kcal = 3,600 kJ = 3,412 BTU

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A3. Glossary

ADO: Automation Diesel Oil.

Anthracite: The highest rank of coal; used primarily for residential and commercial space heating. It is a hard, brittle, and black lustrous coal, often referred to as hard coal, containing a high percentage of fixed carbon and a low percentage of volatile matter. The moisture content of fresh-mined anthracite generally is less than 15 percent. The heat content of anthracite ranges from 22 to 28 million Btu per ton on a moist, mineral-matter-free basis. This fuel typically has a heat content of 15 million Btu per ton or less.

API Gravity: An arbitrary scale expressing the gravity or density of liquid petroleum products. The measuring scale is calibrated in terms of degrees API. A lighter, less dense product has a higher API gravity.

API: The American Petroleum Institute.

APPI: Asia Pacific Petroleum Index

Ash: The non-combustible residue of a combusted substance composed primarily of alkali and metal oxides.

Asphalt: A dark brown-to-black cement-like material obtained by petroleum processing and containing bitumens as the predominant component; used primarily for road construction. It includes crude asphalt as well as the following finished products: cements, fluxes, the asphalt content of emulsions (exclusive of water), and petroleum distillates blended with asphalt to make cutback asphalts. Note: The conversion factor for asphalt is 5.5 barrels per short ton

Aviation Gasoline (Avgas) : A complex mixture of relatively volatile hydrocarbons with or without small quantities of additives, blended to form a fuel suitable for use in aviation reciprocating engines. Fuel specifications are provided in ASTM Specification D910 and Military Specification MIL-G-5572.

Aviation Turbine Fuel (Avtur): Aviation Turbine fuel used by turboprops and jet aircraft.

BAPPEDA: Badan Perencanaan Pembangunan Daerah (Bureau of Local Development Planning)

BAPPENAS: Badan Perencanaan Pembangunan Nasional (Bureau of National Development Planning)

Barrel: A unit of volume equal to 42 U.S. gallons.

Biodiesel: Any liquid biofuel suitable as a diesel fuel substitute or diesel fuel additive or extender. Biodiesel fuels are typically made from oils such as soybeans, rapeseed, or sunflowers, or from animal tallow. Biodiesel can also be made from hydrocarbons derived from agricultural products such as rice hulls.

Biofuels: Liquid fuels and blending components produced from biomass (plant) feedstocks, used primarily for transportation.

Biomass: Organic nonfossil material of biological origin constituting a renewable energy source.

Bituminous coal: A dense coal, usually black, sometimes dark brown, often with well-defined bands of bright and dull material, used primarily as fuel in steam-electric power generation, with substantial quantities also used for heat and power applications in manufacturing and to make coke. Its moisture content usually is less than 20 percent. The heat content of bituminous coal ranges from 21 to 30 million Btu per short ton of a moist, mineral-matter-free basis.

BMG: Badan Meteorologi dan Geofisika (Agency for Meteorology and Geophysics.

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BOE: barrels of oil equivalent.

BPPT: Badan Pengkajian dan Penerapan Teknologi (Agency for Assessment and Applications of Technology)

BPS: Biro Pusat Statistik (Bureau of Statistics)

British thermal unit (BTU): The quantity of heat required to raise the temperature of 1 pound of liquid water by 1 degree Fahrenheit at the temperature at which water has its greatest density (approximately 39 degrees Fahrenheit).

Capacity Factor: 100% x hour 8,760x capacity installed of kW

productionelectric gross annual of kWh ∑

∑

kWh of gross electric production is kWh (energy) generated before subtracted by own-use energy.

Charcoal: A material formed from the incomplete combustion or destructive distillation (carbonization) of organic material in a kiln or retort, and having a high energy density, being nearly pure carbon. (If produced from coal, it is coke.) Used for cooking, the manufacture of gunpowder and steel (notably in Brazil), as an absorbent and decolorizing agent, and in sugar refining and solvent recovery.

CIF (cost, insurance, freight): A type of sale in which the buyer of the product agrees to pay a unit price that includes the f.o.b. value of the product at the point of origin, plus all costs of insurance and transportation. This type of transaction differs from a “delivered” purchase in that the buyer accepts the quantity as determined at the loading port rather than pay on the basis of the quantity and quality ascertained at the unloading port. It is similar to the terms of an F.O.B. sale, except that the seller, as a service for which he is compensated, arranges for transportation and insurance.

Coal briquets: Anthracite, bituminous, and lignite briquets comprise the secondary solid fuels manufactured from coal by a process in which the coal is partly dried, warmed to expel excess moisture, and then compressed into briquets, usually without the use of a binding substance. In the reduction of briquets to coal equivalent, different conversion factors are applied according to their origin from hard coal, peat, brown coal, or lignite.

Coal: A readily combustible black or brownish-black rock whose composition, including inherent moisture, consists of more than 50 percent by weight and more than 70 percent by volume of carbonaceous material. It is formed from plant remains that have been compacted, hardened, chemically altered, and metamorphosed by heat and pressure over geologic time.

Coke (coal): A solid carbonaceous residue derived from low-ash, low-sulfur bituminous coal from which the volatile constituents are driven off by baking in an oven at temperatures as high as 2,000 degrees Fahrenheit so that the fixed carbon and residual ash are fused together. Coke is used as a fuel and as a reducing agent in smelting iron ore in a blast furnace. Coke from coal is grey, hard, and porous and has a heating value of 24.8 million Btu per ton.

Coke (petroleum): A residue high in carbon content and low in hydrogen that is the final product of thermal decomposition in the condensation process in cracking. This product is reported as marketable coke or catalyst coke. The conversion is 5 barrels (of 42 U.S. gallons each) per short ton. Coke from petroleum has a heating value of 6.024 million Btu per barrel.

Combined cycle: An electric generating technology in which electricity is produced from otherwise lost waste heat exiting from one or more gas (combustion) turbines. The exiting heat is routed to a conventional boiler or to a heat recovery steam generator for utilization by a steam turbine in the production of electricity. This process increases the efficiency of the electric generating unit.

Commercial Sector: Business establishments that are not engaged in transportation or in manufacturing or other types of industrial activity (agriculture, mining, or construction). Commercial establishments include hotels, motels, restaurants, wholesale businesses, retail

259

stores, laundries, and other service enterprises; religious and nonprofit organizations; health, social, and educational institutions;

Compressed natural gas (CNG): Natural gas which is comprised primarily of methane, compressed to a pressure at or above 2,400 pounds per square inch and stored in special high-pressure containers. It is used as a fuel for natural gas powered vehicles.

Condensate: A mixture consisting primarily of pentanes and heavier hydrocarbons which is recovered as a liquid from natural gas in lease or field separation facilities. Note: This category excludes natural gas liquids, such as butane and propane, which are recovered at natural gas processing plants or facilities.

Consumer Price Index (CPI): These prices are collected in 85 urban areas selected to represent all urban consumers about 80 percent of the total U.S. population. The service stations are selected initially and on a replacement basis, in such a way that they represent the purchasing habits of the CPI population. Service stations in the current sample include those providing all types of service (i.e., full, mini, and self service).

Cord of wood: A cord of wood measures 4 feet by 4 feet by 8 feet, or 128 cubic feet.

Crop residue: Organic residue remaining after the harvesting and processing of a crop.

Crude Oil: A mixture of hydrocarbons that exists in liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities. Crude oil may also include: 1. Small amounts of hydrocarbons that exist in the gaseous phase in natural underground reservoirs but are liquid at atmospheric pressure after being recovered from oil well (casing head) gas in lease separators and that subsequently are commingled with the crude stream without being separately measured. 2. Small amounts of non hydrocarbons produced with the oil, such as sulfur and other compounds. Some products and other materials are either mixed with the crude oil and cannot be separately measured or they are logically associated with crude oil for accounting purposes.

Cubic foot (cf), natural gas: The amount of natural gas contained at standard temperature and pressure (60 degrees Fahrenheit and 14.73 pounds standard per square inch) in a cube whose edges are one foot long.

Cull wood: Wood logs, chips, or wood products that are burned.

DCO: Diluted Crude Oil

Demand Factor: % 100 x cos x power connected ofkVA

peakload at kW∑

∑ϕ

cos ϕ = 0.8

DESDM: Departemen Energi dan Sumber Daya Mineral (Ministry of Energy and Mineral Resources)

DFO: Diesel Fuel Oil

Diesel fuel: A fuel composed of distillates obtained in petroleum refining operation or blends of such distillates with residual oil used in motor vehicles. The boiling point and specific gravity are higher for diesel fuels than for gasoline.

DPK: Dual Purpose Kerosene

DPPU: Depo Pengisian Bahan Bakar Pesawat Udara (Airplane Fuel Filling Depo)

Dry natural gas: Natural gas which remains after: 1) the liquefiable hydrocarbon portion has been removed from the gas stream (i.e., gas after lease, field, and/or plant separation); and 2) any volumes of nonhydrocarbon gases have been removed where they occur in sufficient quantity to render the gas unmarketable. Dry natural gas is also known as consumer-grade natural gas. The parameters for measurement are cubic feet at 60 degrees Fahrenheit and

260

14.73 pounds per square inch absolute.

Electricity Grid: A common term referring to an electricity transmission and distribution system.

Electricity: A form of energy characterized by the presence and motion of elementary charged particles generated by friction, induction, or chemical change.

Energy consumption: The use of energy as a source of heat or power or as a raw material input to a manufacturing process.

Energy End-Use Sectors: Major energy consuming sectors of the economy. The Commercial Sector includes commercial buildings and private companies. The Industrial Sector includes manufacturers and processors. The Residential Sector includes private homes. The Transportation Sector includes automobiles, trucks, rail, ships, and aircraft.

Energy Intensity: Energy consumption per GDP

Energy: The capacity for doing work as measured by the capability of doing work (potential energy) or the conversion of this capability to motion (kinetic energy). Energy has several forms, some of which are easily convertible and can be changed to another form useful for work. Most of the world's convertible energy comes from fossil fuels that are burned to produce heat that is then used as a transfer medium to mechanical or other means in order to accomplish tasks. Electrical energy is usually measured in kilowatthours, while heat energy is usually measured in British thermal units.

Ethanol (CH3-CH2OH): A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate (blended up to 10 percent concentration). Ethanol can also be used in high concentrations (E85) in vehicles designed for its use.

Expenditure: The incurrence of a liability to obtain an asset or service.

Flare: Gas disposed of by burning in flares usually at the production sites or at gas processing plants.

Fossil fuel: An energy source formed in the earths crust from decayed organic material. The common fossil fuels are petroleum, coal, and natural gas.

Free on board (f.o.b.): A sales transaction in which the seller makes the product available for pick up at a specified port or terminal at a specified price and the buyer pays for the subsequent transportation and insurance.

Fuel oil: A liquid petroleum product less volatile than gasoline, used as an energy source. Fuel oil includes distillate fuel oil (No. 1, No. 2, and No. 4), and residual fuel oil (No. 5 and No. 6).

Gallon: A volumetric measure equal to 4 quarts (231 cubic inches) used to measure fuel oil. One barrel equals 42 gallons.

Gas oil: European and Asian designation for No. 2 heating oil and No. 2 diesel fuel.

Gas turbine plant: A plant in which the prime mover is a gas turbine. A gas turbine consists typically of an axial-flow air compressor and one or more combustion chambers where liquid or gaseous fuel is burned and the hot gases are passed to the turbine and where the hot gases expand drive the generator and are then used to run the compressor.

Gas: A non-solid, non-liquid combustible energy source that includes natural gas, coke-oven gas, blast-furnace gas, and refinery gas.

Gasohol: A registered trademark of an agency of the state of Nebraska, for an automotive fuel containing a blend of 10 percent ethanol and 90 percent gasoline.

Gasoline: A refined petroleum product suitable for use as a fuel in internal combustion engines.

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Gas-Steam Power

Geothermal energy: Hot water or steam extracted from geothermal reservoirs in the earth's crust. Water or steam extracted from geothermal reservoirs can be used for geothermal heat pumps, water heating, or electricity generation.

Geothermal plant: A plant in which the prime mover is a steam turbine. The turbine is driven either by steam produced from hot water or by natural steam that derives its energy from heat found in rock.

Gigawatt (GW): One billion watts or one thousand megawatts.

Gigawatt-electric (GWe): One billion watts of electric capacity.

Gigawatthour (GWh): One billion watthours.

Gross Domestic Product (GDP): The total value of goods and services produced by labor and property located in Indonesia. As long as the labor and property are located in Indonesia, the supplier (that is, the workers and, for property, the owners) may be either Indonesian residents or residents of foreign countries.

Heavy gas oil: Petroleum distillates with an approximate boiling range from 651degrees Fahrenheit to 1000 degrees Fahrenheit.

HOMC: High Octane Motor Component

Household: A family, an individual, or a group of up to nine unrelated persons occupying the same housing unit. "Occupy" means that the housing unit is the person's usual or permanent place of residence.

HSD: High Speed Diesel Oil

HSFO: High sulfur fuel oil

Hydrocarbon: An organic chemical compound of hydrogen and carbon in the gaseous, liquid, or solid phase. The molecular structure of hydrocarbon compounds varies from the simplest (methane, a constituent of natural gas) to the very heavy and very complex. : The production of electricity from the kinetic energy of falling water.

Hydroelectric power: The use of flowing water to produce electrical energy.

ICP: Indonesian Crude Price

IDO: Intermediate Diesel Oil

IFO: industrial fuel oil

Indicated Resources, Coal: Coal for which estimates of the rank, quality, and quantity are based partly on sample analyses and measurements and partly on reasonable geologic projections. Indicated resources are computed partly from specified measurements and partly from projection of visible data for a reasonable distance on the basis of geologic evidence.

Industrial Sector: Manufacturing industries, which make up the largest part of the sector, along with mining, construction, agriculture, fisheries, and forestry. Establishments in this sector range from steel mills, to small farms, to companies assembling electronic components.

Installed Capacity: The total capacity of electrical generation devices in a power station or system.

JOB: Joint Operation Body; A form of cooperation between PERTAMINA with private companies for oil and gas exploration and exportation

Joule (J): The meter-kilogram-second unit of work or energy, equal to the work done by a force of one newton when its point of application moves through a distance of one meter in the

262

direction of the force; equivalent to 107 ergs and one watt-second.

Kerosene: A type of heating fuel derived by refining crude oil that has a boiling range at atmospheric pressure from 400 degrees to 550 degrees F.

Kilovolt-Ampere (kVa): A unit of apparent power, equal to 1,000 volt-amperes; the mathematical product of the volts and amperes in an electrical circuit.

Kilowatt (kW): One thousand watts.

Kilowatt-electric (kWe): One thousand watts of electric capacity.

Kilowatthour (kWh): A measure of electricity defined as a unit of work or energy, measured as 1 kilowatt (1,000 watts) of power expended for 1 hour. One kWh is equivalent to 3,412 Btu.

LAPAN: Lembaga Penerbangan dan Antariksa Nasional (National Space and Aeronautics Administration).

Light gas oils: Liquid petroleum distillates heavier than naphtha, with an approximate boiling range from 401 degrees to 650 degrees Fahrenheit.

Light oil: Lighter fuel oils distilled off during the refining process. Virtually all petroleum used in internal combustion and gas-turbine engines is light oil. Includes fuel oil numbers 1 and 2, kerosene, and jet fuel.

Lignite: The lowest rank of coal, often referred to as brown coal, used almost exclusively as fuel for steam-electric power generation. It is brownish-black and has a high inherent moisture content, sometimes as high as 45 percent The heat content of lignite ranges from 9 to 17 million Btu per ton on a moist, mineral-matter-free basis.

LIPI: Lembaga Ilmu Pengetahuan Indonesia (Institution of Sciences Indonesia).

Liquefied natural gas (LNG): Natural gas (primarily methane) that has been liquefied by reducing its temperature to -260 degrees Fahrenheit at atmospheric pressure.

Liquefied Natural Gas (LNG): Natural gas (primarily methane) that has been liquefied by reducing its temperature to -260° F at atmospheric pressure.

Load (electric): The amount of electric power delivered or required at any specific point or points on a system. The requirement originates at the energy-consuming equipment of the consumers.

Load Factor: 100% x hour 8,70 x peakload at kW

production electric total annual of kWh

∑

∑

kWh of total electric production is the sum of kWh produced by PLN and kWh purchased from outside party.

Peak load is the highest load achieved within the calendar year.

Load factor: The ratio of the average load to peak load during a specified time interval.

LPG: Liquefied petroleum gases such as propane and butane produced at refineries or natural gas processing plants, including plants that fractionate raw natural gas plant liquids.

LSDE: Lembaga Sumber Daya Energi (Center for Research on Energy Resources)

LSWR: Low sulfur waxy residual fuel oil

Macroeconomics: a sub-field of economics that examines the behavior of the economy as a whole, once all of the individual economic decisions of companies and industries have been summed. Economy-wide phenomena considered by macroeconomics include Gross Domestic Product (GDP) and how it is affected by changes in unemployment, national income, rate of

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growth, and price levels.

Measured Resources, Coal: Coal resources for which estimates of the rank, quality, and quantity have been computed, within a margin of error of less than 20 percent, from sample analyses and measurements from closely spaced and geologically well known sample sites. Measured resources are computed from dimensions revealed in outcrops, trenches, mine workings, and drill holes. The points of observation and measurement are so closely spaced and the thickness and extent of coals are so well defined that the tonnage is judged to be accurate within 20 percent.

Megavoltamperes (MVA): Millions of voltamperes, which are a measure of apparent power.

Megawatt (MW): One million watts of electricity.

Megawatt electric (MWe): One million watts of electric capacity.

Methane: A colorless, flammable, odorless hydrocarbon gas (CH4) which is the major component of natural gas. It is also an important source of hydrogen in various industrial processes. Methane is a greenhouse gas.

Methanol (CH3OH; Methyl alcohol or wood alcohol): A clear, colorless, very mobile liquid that is flammable and poisonous; used as a fuel and fuel additive, and to produce chemicals.

MFA: Mega Volt Ampere

MFO: Marine Fuel Oil

Middle Distillate

Naphtha: A generic term applied to a petroleum fraction with an approximate boiling range between 122 degrees Fahrenheit and 400 degrees Fahrenheit.

Natural Gas Liquids (NGL): Those hydrocarbons in natural gas that are separated as liquids from the gas. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane, and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).

Natural Gas: A hydrocarbon gas obtained from underground sources, often in association with petroleum and coal deposits. It generally contains a high percentage of methane, varying amounts of ethane, and inert gases; used as a heating fuel.

Net (Lower) Heating Value (NHV): The potential energy available in a fuel as received, taking into account the energy loss in evaporating and superheating the water in the fuel. Equal to the higher heating value minus 1050W where W is the weight of the water formed from the hydrogen in the fuel, and 1050 is the latent heat of vaporization of water, in Btu, at 77 degrees Fahrenheit.

Nuclear electric power (nuclear power): Electricity generated by the use of the thermal energy released from the fission of nuclear fuel in a reactor.

Ocean energy systems: Energy conversion technologies that harness the energy in tides, waves, and thermal gradients in the oceans.

Ocean thermal energy conversion (OTEC): The process or technologies for producing energy by harnessing the temperature differences (thermal gradients) between ocean surface waters and that of ocean depths. Warm surface water is pumped through an evaporator containing a working fluid in a closed Rankine-cycle system. The vaporized fluid drives a turbine/generator.

OECD (Organization for Economic Cooperation and Development): Current members are Australia, Austria, Belgium, Canada, Czech Republic, Denmark and its territories (Faroe Islands and Greenland), Finland, France, Germany, Greece, Greenland, Hungary, Iceland, Ireland, Italy, Japan, Luxembourg, Mexico, the Netherlands, New Zealand, Norway, Poland, Portugal, South Korea, Spain, Sweden, Switzerland, Turkey, United Kingdom, and United States and its territories (Guam, Puerto Rico, and Virgin Islands).

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Oil reservoir: An underground pool of liquid consisting of hydrocarbons, sulfur, oxygen, and nitrogen trapped within a geological formation and protected from evaporation by the overlying mineral strata.

Oil: A mixture of hydrocarbons usually existing in the liquid state in natural underground pools or reservoirs. Gas is often found in association with oil.

OPEC (Organization of Petroleum Exporting Countries): Countries that have organized for the purpose of negotiating with oil companies on matters of oil production, prices, and future concession rights. Current members are Algeria, Indonesia, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, United Arab Emirates, and Venezuela.

P3B: Penyaluran dan Pusat Pengatur Beban Jawa Bali (Electricity Load Distribution Center Java-Bali)

Panel (Solar): A term generally applied to individual solar collectors, and typically to solar photovoltaic collectors or modules.

Paraffin (wax): The wax removed from paraffin distillates by chilling and pressing. When separating from solutions, it is a colorless, more or less translucent, crystalline mass, without odor and taste, slightly greasy to touch, and consisting of a mixture of solid hydrocarbons in which the paraffin series predominates

Peak load: The maximum load during a specified period of time.

Peat: Peat consists of partially decomposed plant debris. It is considered an early stage in the development of coal. Peat is distinguished from lignite by the presence of free cellulose and a high moisture content (exceeding 70 percent). The heat content of air-dried peat (about 50 percent moisture) is about 9 million Btu per ton.

Perpres: Peraturan Presiden (Presidential Regulation).

Pertamax: High octane gasoline brand produced by Pertamina.

PERTAMINA: Perusahaan Pertambangan Minyak dan Gas Nasional (Oil and Gas State-Owned Company)

Petroleum refinery: An installation that manufactures finished petroleum products from crude oil, unfinished oils, natural gas liquids, other hydrocarbons, and alcohol.

Petroleum: A broadly defined class of liquid hydrocarbon mixtures. Included are crude oil, lease condensate, unfinished oils, refined products obtained from the processing of crude oil, and natural gas plant liquids. Note: Volumes of finished petroleum products include nonhydrocarbon compounds, such as additives and detergents, after they have been blended into the products.

PGN: Perusahaan Umum Gas Negara (State Owned Gas Transmission and Distribution Company)

Photovoltaic and solar thermal energy (as used at electric utilities): Energy radiated by the sun as electromagnetic waves (electromagnetic radiation) that is converted at electric utilities into electricity by means of solar (photovoltaic) cells or concentrating (focusing) collectors.

Photovoltaic cell (PVC): An electronic device consisting of layers of semiconductor materials fabricated to form a junction (adjacent layers of materials with different electronic characteristics) and electrical contacts and being capable of converting incident light directly into electricity (direct current).

Pipeline (natural gas): A continuous pipe conduit, complete with such equipment as valves, compressor stations, communications systems, and meters for transporting natural and/or supplemental gas from one point to another, usually from a point in or beyond the producing field or processing plant to another pipeline or to points of utilization. Also refers to a company operating such facilities.

Pipeline, distribution: A pipeline that conveys gas from a transmission pipeline to its ultimate

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consumer.

Pipeline, transmission: A pipeline that conveys gas from a region where it is produced to a region where it is to be distributed.

PJB: Pembangkitan Jawa-Bali (electricity producer that supplies electricity needs of the people in East Java and Bali)

PLTMG: Pembangkit Listrik Tenaga Micro Gas (Gas Micro scale Power Plant)

PLN: Perusahaan Listrik Negara (State-Owned Electricity Company)

Power (electrical): An electric measurement unit of power called a voltampere is equal to the product of 1 volt and 1 ampere. This is equivalent to 1 watt for a direct current system, and a unit of apparent power is separated into real and reactive power. Real power is the work-producing part of apparent power that measures the rate of supply of energy and is denoted as kilowatts (kW). Reactive power is the portion of apparent power that does no work and is referred to as kilovars; this type of power must be supplied to most types of magnetic equipment, such as motors, and is supplied by generator or by electrostatic equipment. Energy is denoted by the product of real power and the length of time utilized; this product is expressed as kilowathours.

Power loss: The difference between electricity input and output as a result of an energy transfer between two points.

Premium gasoline: Gasoline having an antiknock index (R+M/2) greater than 90. Includes both leaded premium gasoline as well as unleaded premium gasoline.

Primary energy consumption: Primary energy consumption is the amount of site consumption, plus losses that occur in the generation, transmission, and distribution of energy.

Primary energy: All energy consumed by end users, excluding electricity but including the energy consumed at electric utilities to generate electricity. (In estimating energy expenditures, there are no fuel-associated expenditures for hydroelectric power, geothermal energy, solar energy, or wind energy, and the quantifiable expenditures for process fuel and intermediate products are excluded.)

Probable (indicated) reserves, coal: Reserves or resources for which tonnage and grade are computed partly from specific measurements, samples, or production data and partly from projection for a reasonable distance on the basis of geological evidence. The sites available are too widely or otherwise inappropriately spaced to permit the mineral bodies to be outlined completely or the grade established throughout.

Probable energy reserves: Estimated quantities of energy sources that, on the basis of geologic evidence that supports projections from proved reserves, can reasonably be expected to exist and be recoverable under existing economic and operating conditions. Site information is insufficient to establish with confidence the location, quality, and grades of the energy source.

Production Sharing Contract: A form of cooperation between Pertamina and private companies in accordance with Law No 44 Prp of 1960 jo Law No 8 of 1971.

Propane (C3H8): A normally gaseous straight-chain hydrocarbon. It is a colorless paraffinic gas that boils at a temperature of -43.67 degrees Fahrenheit. It is extracted from natural gas or refinery gas streams. It includes all products designated in ASTM Specification D1835 and Gas Processors Association Specifications for commercial propane and HD-5 propane.

Proved (measured) reserves, coal: Reserves or resources for which tonnage is computed from dimensions revealed in outcrops, trenches, workings, and drill holes and for which the grade is computed from the results of detailed sampling. The sites for inspection, sampling, and measurement are spaced so closely and the geologic character is so well defined that size, shape, and mineral content are well established. The computed tonnage and grade are judged to be accurate within limits that are stated, and no such limit is judged to be different from the computed tonnage or grade by more than 20 percent.

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Proved energy reserves: Estimated quantities of energy sources that analysis of geologic and engineering data demonstrates with reasonable certainty are recoverable under existing economic and operating conditions. The location, quantity, and grade of the energy source are usually considered to be well established in such reserves.

Quad: One quadrillion Btu. (1,000,000,000,000,000 Btu)

Refinery fuel: Crude oil and petroleum products consumed at the refinery for all purposes.

Refinery gas: Noncondensate gas collected in petroleum refineries.

Refinery: An installation that manufactures finished petroleum products from crude oil, unfinished oils, natural gas liquids, other hydrocarbons, and oxygenates.

Renewable energy resources: Energy resources that are naturally replenishing but flow-limited. They are virtually inexhaustible in duration but limited in the amount of energy that is available per unit of time. Renewable energy resources include: biomass, hydro, geothermal, solar, wind, ocean thermal, wave action, and tidal action.

Reserve: That portion of the demonstrated reserve base that is estimated to be recoverable at the time of determination. The reserve is derived by applying a recovery factor to that component of the identified coal resource designated as the demonstrated reserve base.

Reservoir: A porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.

Residual fuel oil: A general classification for the heavier oils, known as No. 5 and No. 6 fuel oils, that remain after the distillate fuel oils and lighter hydrocarbons are distilled away in refinery operations. It conforms to ASTM Specifications D 396 and D 975 and Federal Specification VV-F-815C. No. 5, a residual fuel oil of medium viscosity, is also known as Navy Special and is defined in Military Specification MIL-F-859E, including Amendment 2 (NATO Symbol F-770). It is used in steam-powered vessels in government service and inshore powerplants. No. 6 fuel oil includes Bunker C fuel oil and is used for the production of electric power, space heating, vessel bunkering, and various industrial purposes.

Resources (Coal) : Naturally occurring concentrations or deposits of coal in the Earth's crust, in such forms and amounts that economic extraction is currently or potentially feasible.

SLC: Sumatran Light Crude

Solar energy: The radiant energy of the sun, which can be converted into other forms of energy, such as heat or electricity.

Speculative resources (coal): Undiscovered coal in beds that may occur either in known types of deposits in a favorable geologic setting where no discoveries have been made, or in deposits that remain to be recognized. Exploration that confirms their existence and better defines their quantity and quality would permit their reclassification as identified resources.

Steam: Water in vapor form; used as the working fluid in steam turbines and heating systems.

Subsidy: Financial assistance granted by the Government to firms and individuals.

TAC: Technical Assistance Contract; A from of cooperation between PERTAMINA and private companies for oil and gas exploration and exploitation.

Therm: One hundred thousand (100,000) Btu.

UPPDN: Unit Perbekalan dan Pemasaran Dalam Negeri

Volt (V): The volt is the International System of Units (SI) measure of electric potential or electromotive force. A potential of one volt appears across a resistance of one ohm when a

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current of one ampere flows through that resistance. Reduced to SI base units, 1 V = 1 kg times m2 times s-3 times A-1 (kilogram meter squared per second cubed per ampere).

Voltage: The difference in electrical potential between any two conductors or between a conductor and ground. It is a measure of the electric energy per electron that electrons can acquire and/or give up as they move between the two conductors.

Wax: A solid or semi-solid material consisting of a mixture of hydrocarbons obtained or derived from petroleum fractions, or through a Fischer-Tropsch type process, in which the straight- chained paraffin series predominates. This includes all marketable wax, whether crude or refined, with a congealing point (ASTM D 938) between 100 and 200 degrees Fahrenheit and a maximum oil content (ASTM D 3235) of 50 weight percent.

Wind energy: Kinetic energy present in wind motion that can be converted to mechanical energy for driving pumps, mills, and electric power generators

Wind Power Plant: A group of wind turbines interconnected to a common power provider system through a system of transformers, distribution lines, and (usually) one substation. Operation, control, and maintenance functions are often centralized through a network of computerized monitoring systems, supplemented by visual inspection. This is a term commonly used in the United States. In Europe, it is called a generating station.

Wood energy: Wood and wood products used as fuel, including round wood (cord wood), limb wood, wood chips, bark, sawdust, forest residues, charcoal, pulp waste, and spent pulping liquor.

WTI: West Texas Intermediate

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Profile of Editors

Widodo Wahyu Purwanto, born in Sidoarjo, November 11th 1960, received his doctorate degree in chemical engineering (1992) from Ecole Nationale Supérieure d’Ingénieurs de Génie Chimique (ENSIGC), l’Institut Nationale Polytechnique de Toulouse (INPT), France. He is an active member of the American Institute of Chemical Engineers (AIChe), the current director of Center for Energy Studies University of Indonesia and head of Sustainable Energy Research Group at the Department of Chemical Engineering University of Indonesia. Clean Energy Technology and Chemical Reaction Engineering are his preferred research domains. He regularly gives lectures to undergraduate as well as graduate students of Chemical Engineering University of Indonesia and to professionals in the oil and gas business on certain occasions.

Yulianto Sulistyo Nugroho, was born in Jakarta, July 28 1968. He got his Ph.D degree from Department of Fuel and Energy, The University of Leeds, UK. Combustion engineering and Energy Study are his expertise. His research work in Coal Combustion especially spontaneous combustion of coal have been published by FUEL International Journal, International Conference on Coal Science, Proceeding of Combustion Institute, and Coal Tech. He is a Lecturer in Mechanical Engineering Department FTUI; active Instructor in professional trainings for Industrial Safety and Fire Protection Systems; and also member of Indonesian Coal Society (ICS) and Combustion Institute. He is an acting Vice Director of Center for Energy Studies in University of Indonesia.

Rinaldy Dalimi, was born in Pekanbaru on April 24 1956, with the latest education in Virginia Polytechnic Institute and State University, Virginia Tech (USA), Electrical Engineering Department (with Doctoral Certificate, Ph.D). His expertise is Power System Engineering, and he is a lecturer of Undergraduate and Postgraduate Program of Electrical Engineering, Faculty of Engineering Universitas Indonesia (FTUI). He is The Dean of Faculty of Engineering University of Indonesia, and an expert staff of Center for Energy Studies University of Indonesia

A Harsono Soepardjo, was born in Solo on July 7, 1951, latest education in University of Montpellier II France with Doctoral Degree. Beside lecturer of Undergraduate and Postgraduate Program of Material Science Program and Physics of Mathematic and Natural Science (FMIPA-UI), he is an expert staff in Center for Energy Studies of University of Indonesia, Chief of Center for Marine Studies and Chief of Post Graduate for Marine Sciences Faculty of Mathematics and Natural Science University of Indonesia. Since 2001 till now, he is a Director of International Ocean Institute Affiliation Indonesia

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Abdul Wahid was born in Tegal, July 1 1967, latest education in Postgraduate Department of Chemical Engineering University of Indonesia. Research conducted in Process System Engineering such as Evaluation on the Impact of Department of Mining and Energy toward the National Economy, Optimization of LNG Refinery Capacity: a System Dynamic Approach. Now, he is a lecture of Undergraduate Program in Department of Chemical Engineering Faculty of Engineering UI and Head of Chemical Process System Laboratory.

Dijan Supramono was born in Malang, December 8, 1958.. He was awarded MSc degree in Process Integration in 1991 from Department of Chemical Engineering, University of Manchester Institute of Science and Technology (UMIST), England. His research interest is fluid mechanics and coal combustion. He is a lecturer at Department of Chemical Engineering, University of Indonesia.

Dinna Herminna, was born in Jakarta, January 26 1983, latest education in Undergraduate Program from Chemical Engineering Study Program Department of Gas and Petrochemical Engineering Faculty of Engineering University of Indonesia. She responsible for Sponsorship, Compiling and Managing Data for this book.

Teguh Ahmad Adilina, was born in Jakarta, Desember 8 1983, latest education in Undergraduate Program from Chemical Engineering Study Program Department of Gas and Petrochemical Engineering Faculty of Engineering University of Indonesia. He responsible for Managing the Energy Model (INOSYD).

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SPONSORS

PT. Pacific Oil & Gas Indonesia Jl. M.H. Thamrin No. 31 Jakarta 10230, Indonesia Telp. (62 21) 3149189 Fax. (62 21) 3149188 Email : [email protected] Homepage : www.po-and-g.com Premier Oil Indonesia Jakarta Stock Exchange Building, Tower 1, 10 Floor Jl. Jend. Sudirman Kav. 52-53 Jakarta 12190 Homepage : www.premier-oil.com Star Energy Wisma Mulia 50th Floor Jl. Jend. Gatot Subroto No. 42 Jakarta 12710 - Indonesia Telp. (62-21) 52906060 Fax. (62-21) 52906050 PT. Bakrie & Brothers, Tbk Wisma Bakrie II Jl. H.R. Rasuna Said Kav B-2, 16th - 17th floor Jakarta 12920 - Indonesia P.O.Box 660 JKTM Telp. (62 21) 936 33 333, 99 999 Fax. (62-21) 520 0361 Homepage : www.bakrie-brothers.com PT. Pendawa Consultama Sejati Gedung Graha Seti Jl. KH. Abdullah Syafei, Kav. A, No. 19 Gudang Peluru, Tebet, Jakarta Selatan 12830 PO BOX 1789, Jakarta 12017-Indonesia Telp. (62-21) 837 00235 Fax. (62-21) 837 00786 Homepage : www.pendawa.co.id

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Wisma Mulia 50th Floor Jl. Jend. Gatot Subroto No. 42

Jakarta 12710 - Indonesia Phone : 62-21-52906060

Fax : 62-21-52906050

2006 indonesia energy outlook & statistic

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