STUDY ON FISCAL AND NON-FISCAL INCENTIVES TO … · THE REPUBLIC OF INDONESIA STUDY ON FISCAL AND...

MINISTRY OF FINANCE THE REPUBLIC OF INDONESIA

STUDY ON FISCAL AND NON-FISCAL INCENTIVES TO ACCELERATE PRIVATE

SECTOR GEOTHERMAL ENERGY DEVELOPMENT

IN THE REPUBLIC OF INDONESIA

FINAL REPORT

JULY 2009

JAPAN INTERNATIONAL COOPERATION AGENCY

WEST JAPAN ENGINEERING CONSULTANTS, INC.

Study on Fiscal and Non-fiscal Incentives to Accelerate Private Sector Geothermal Energy Development in the Republic of Indonesia Final Report

JICA West JEC i

Table of Contents

Table of Contents ･･･････････････････････････････････････････････････････････････i

List of Tables and Figures ･･･････････････････････････････････････････････････････iv

Acronyms and Abbreviations ･･･････････････････････････････････････････････････ xviii

Unit ･･･････････････････････････････････････････････････････････････････ xxiii

Exective Summary ･･･････････････････････････････････････････････････････････ ES-1

Chapter 1 Introduction･････････････････････････････････････････････････････････ 1-1

1.1 Background of the Study ･･････････････････････････････････････････････････ 1-1

1.2 Objective of the Study ････････････････････････････････････････････････････ 1-1

1.3 Contents of the Study ･････････････････････････････････････････････････････ 1-2

1.4 Target Area of the Study･･･････････････････････････････････････････････････ 1-2

1.5 Implementation System of the Study ･････････････････････････････････････････ 1-3

Chapter 2 Basic Philosophy and the Process of the Study ････････････････････････････ 2-1

2.1 Current Status of Energy Use and CO2 Emission in Indonesia ････････････････････ 2-1

2.2 Necessity of Government Intervention････････････････････････････････････････ 2-2

2.3 Significance of Geothermal Energy ･･････････････････････････････････････････ 2-5

2.4 Barriers of Geothermal Energy Development ･･････････････････････････････････ 2-7

2.5 Influence of Enormous Up-front Investment ･･･････････････････････････････････ 2-7

2.6 Influence of Development Risks ･･･････････････････････････････････････････ 2-10

2.7 Importance of the Role of Government ･･････････････････････････････････････ 2-12

2.8 Possible Various Policies ･････････････････････････････････････････････････ 2-13

2.9 Methodology of the Study ････････････････････････････････････････････････ 2-15

2.10 Assumptions of the Study････････････････････････････････････････････････ 2-20

Chapter 3 Present Status of Geothermal Power Development in Indonesia ･･････････････ 3-1

3.1 Geothermal Power Potential in Indonesia ･････････････････････････････････････ 3-1

3.2 Status of Recent Geothermal Development Policy ･･････････････････････････････ 3-6

3.3 Recent Geothermal IPP Activities ･･････････････････････････････････････････ 3-27

3.4 Recent Investment Environment for Geothermal Projects････････････････････････ 3-34

3.5 Evaluation of Recent Geothermal Incentives ･･････････････････････････････････ 3-37


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Chapter 4 Conditions for Attractive IPP Projects ･･･････････････････････････････････ 4-1

Chapter 5 Evaluation of a Coal-fired IPP Project (Benchmark Price) ･･････････････････ 5-1

5.1 Assumptions ････････････････････････････････････････････････････････････ 5-1

5.2 Risk Analysis ･･･････････････････････････････････････････････････････････ 5-4

5.3 Benchmark Price ････････････････････････････････････････････････････････ 5-8

Chapter 6 Evaluation of a Geothermal IPP Project･･････････････････････････････････ 6-1

6.1 Assumptions ････････････････････････････････････････････････････････････ 6-1

6.2 Risk Analysis ･･･････････････････････････････････････････････････････････ 6-6

6.3 Selling Price of Electricity from Geothermal IPP Project ････････････････････････ 6-15

Chapter 7 Benefits of Geothermal Power Development ･･････････････････････････････ 7-1

7.1 Power Demand and Supply Simulation ･･･････････････････････････････････････ 7-1

7.2 Fuel Saving Benefit (Reduction of PT PLN Generation Costs)･････････････････････ 7-7

7.3 Fuel Saving Benefit (Export Benefit)････････････････････････････････････････ 7-11

7.4 Tax Increase Benefit ･････････････････････････････････････････････････････ 7-12

7.5 Environmental Improvement Benefit････････････････････････････････････････ 7-13

7.6 Total Value of Benefits of Geothermal Power ････････････････････････････････ 7-14

7.7 Construction Effects of Geothermal Power Plants ･･････････････････････････････ 7-16

Chapter 8 Short-term Incentives to Promote Geothermal Development ････････････････ 8-1

8.1 Market Failure and Necessity of Government Intervention ････････････････････････ 8-1

8.2 Geothermal Energy Promotion Policy ････････････････････････････････････････ 8-3

8.3 The Feed-in Tariff (FIT) Scheme ････････････････････････････････････････････ 8-9

8.4 The RPS Scheme ･･･････････････････････････････････････････････････････ 8-20

8.5 Tax Incentives･･････････････････････････････････････････････････････････ 8-22

8.6 Fiscal Incentives (Government Expenditure)･･････････････････････････････････ 8-27

8.7 Financial Incentives ･････････････････････････････････････････････････････ 8-32

Chapter 9 Proposal of Short-term Incentives to Promote Geothermal

Development ･･･････････････････････････････････････････････････････ 9-1

9.1 Geothermal Development Process in Indonesia･････････････････････････････････ 9-1

9.2 Incentives for “Green Field” Development ･･･････････････････････････････････ 9-2


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9.3 Measures to Change “Green Field” to “Brown Field” ･･･････････････････････････ 9-6

9.4 Measures for Risk-free Participation ･････････････････････････････････････････ 9-7

Chapter 10 Evaluation of a Long-term Coal-fired IPP Project ･･･････････････････････ 10-1

10.1 Long-term Outlook for Coal Demand and Supply and Coal Prices････････････････ 10-1

10.2 Long-term Forecast of Coal-fired Power Plant Construction Cost ････････････････ 10-2

10.3 Long-term Forecast of Selling Price of Coal-Fired Power Plant ･･････････････････ 10-8

Chapter 11 Evaluation of a Long-term Geothermal IPP Project ･･･････････････････････11-1

11.1 Long-term Forecast of Geothermal Power Plant Construction Costs･･･････････････ 11-1

11.2 Long-term Forecast of Selling Price of Geothermal Power Plant ･････････････････ 11-5

Chapter 12 Long-term Incentives to Promote Geothermal Development ･･･････････････ 12-1

12.1 Clean Development Mechanism (CDM) ････････････････････････････････････ 12-1

12.2 Carbon Tax ･･････････････････････････････････････････････････････････ 12-12

12.3 Localization of Geothermal Technology ･･･････････････････････････････････ 12-30

Chapter 13 Cost and Benefit Analysis of Geothermal Development

Incentives ････････････････････････････････････････････････････････ 13-1

13.1 Long-term Geothermal Development Forecast ･･････････････････････････････ 13-1

13.2 Feed-in Tariff Incentives ････････････････････････････････････････････････ 13-3

13.3 Tax Reduction and Feed-in Tariff Combination Incentives ･･････････････････････ 13-8

13.4 Geothermal Development Promotion Survey (GDPS) and Feed-in

Tariff Combination Incentives ･･････････････････････････････････････････ 13-12

Chapter 14 Importance of Feed-in Tariff Incentives ･･･････････････････････････････ 14-1

Chapter 15 Aiming for Economic Growth through Geothermal

Development ~ A Way to Foster the Geothermal Industry in

Indonesia ~ ･･･････････････････････････････････････････････････････ 15-1

ANNEX-1 Geothermal Business Economic Evaluation Model･･････････････････ANNEX-1-1

ANNEX-2 Input Output Table of 47 Sectors (2005) ･････････････････････････ANNEX-2-1

ANNEX-3 Impact Analysis of passing through Feed-in Tariff to Consumers･･････ANNEX-3-1

ANNEX-4 Cost and Benefit Analysis of Geothermal Development Incentives


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(In the case of excluding the Fuel Export Value) ･･･････････････････ANNEX-4-1

List of References ･････････････････････････････････････････････････････････････ R-1


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List of Tables and Figures

＜List of Figures＞

Chapter 1

Fig. 1.5-1 Implementation system of the study･･････････････････････････････････ 1-3

Chapter 2

Fig. 2.1-1 CO2 emissions from energy use ･････････････････････････････････････ 2-1

Fig. 2.1-2 World CO2 emitters ･･････････････････････････････････････････････ 2-1

Fig. 2.1-3 CO2 emissions and economic growth･････････････････････････････････ 2-2

Fig. 2.1-4 Growth of energy origin CO2 intensity ･･･････････････････････････････ 2-2

Fig. 2.2-1 Energy subsidy an incomplete market ････････････････････････････････ 2-3

Fig. 2.2-2 Government intervention for REs ･･･････････････････････････････････ 2-3

Fig. 2.2-3 Without government intervention ･･･････････････････････････････････ 2-3

Fig. 2.2-4 Policy mix for renewable energy diffusion ････････････････････････････ 2-4

Fig. 2.2-5 Diffusion of renewable energy and government support ･･････････････････ 2-4

Fig. 2.3-1 CO2 emission through life cycle of various power sources ････････････････ 2-6

Fig. 2.3-2 CO2 credit amount per output (yearly)････････････････････････････････ 2-6

Fig. 2.3-3 CO2 credit amount per construction cost (total through operating

period) ･･･････････････････････････････････････････････････････ 2-6

Fig. 2.5-1 Makeup of the selling price of power･････････････････････････････････ 2-8

Fig. 2.5-2 Relationship between expected rate of return and the selling price of

power ･････････････････････････････････････････････････････････ 2-8

Fig. 2.5-3 Change in sources of power generation in six Central American

countries ･･･････････････････････････････････････････････････････ 2-9

Fig. 2.6-1 Distribution of production well depth of geothermal power plants in

Japan･････････････････････････････････････････････････････････ 2-10

Fig. 2.6-2 Distribution of productivity of geothermal power plants in Japan･･････････ 2-10

Fig. 2.6-3 Example of profitability fluctuation when various factors change ･････････ 2-11

Fig. 2.6-4 Necessity to reduce risks (fluctuation range) ･････････････････････････ 2-11

Fig. 2.7-1 The role of government in promoting geothermal energy

development ･･･････････････････････････････････････････････････ 2-12

Fig. 2.8-1 Various policy tools to promote renewable energy ･････････････････････ 2-14

Fig. 2.8-2 Mechanism through which each incentive policy works on the selling


JICA West JEC vi

price of power ･････････････････････････････････････････････････ 2-15

Fig. 2.9-1 Prospect of geothermal development output capacity ･･･････････････････ 2-16

Fig. 2.9-2 Study flow of short-term incentive options (Phase-I) ･･････････････････ 2-18

Fig. 2.9-3 Study flow of mid-term and long-term incentive options (Phase-II) ･･･････ 2-19

Chapter 3

Fig. 3.1-1 Major geothermal resources in Indonesia ･････････････････････････････ 3-5

Fig. 3.2-1 Geothermal development process pursuant to Law 27/2003 ･･････････････ 3-15

Fig. 3.2-2 Electricity price development after renegotiation ･･････････････････････ 3-21

Fig. 3.4-1 Selling prices and geothermal activities･･････････････････････････････ 3-34

Chapter 4

Fig. 4-1 IPP project and its stakeholders ･････････････････････････････････････ 4-1

Chapter 5

Fig. 5.1-1 US Treasury bond yield and average return of foreign direct

investment in US ････････････････････････････････････････････････ 5-3

Fig. 5.2-1 Sensitivity analysis of Project IRR to risk factor changes ･････････････････ 5-5

Fig. 5.2-2 Sensitivity analysis of Equity IRR to risk factor changes ･････････････････ 5-5

Fig. 5.2-3 Probability of construction costs for Monte Carlo Method simulation ･･･････ 5-6

Fig. 5.2-4 Distribution of Project IRR in Monte Carlo Method simulation ････････････ 5-7

Fig. 5.3-1 Selling Price for coal-fired IPP project (Benchmark Price) ･･･････････････ 5-9

Chapter 6

Fig. 6.1-1 Geothermal development process for 60 MW plant･･････････････････････ 6-2

Fig. 6.1-2 Up-front investment amount estimation for 60 MW geothermal

power plant･････････････････････････････････････････････････････ 6-3

Fig. 6.2-1 Well depth variation in Indonesia････････････････････････････････････ 6-7

Fig. 6.2-2 Distribution of production well depth in Indonesia ･･････････････････････ 6-7

Fig. 6.2-3 Average steam production per well in Japan ･･･････････････････････････ 6-8

Fig. 6.2-4 Distribution of average steam production per well in Japan ･･･････････････ 6-8

Fig. 6.2-5 Distribution of steam/water ratio of wells in Japan ･･････････････････････ 6-9

Fig. 6.2-6 Analysis of Project IRR sensitivity to risk factor changes･････････････････ 6-9

Fig. 6.2-7 Analysis of Equity IRR sensitivity to risk factor changes ････････････････ 6-10


JICA West JEC vii

Fig. 6.2-8 Probability of risk factors for Monte Carlo Method simulation････････････ 6-11

Fig. 6.2-9 Distribution of Project IRR in Monte Carlo Method simulation ･･･････････ 6-12

Fig. 6.2-10 Risk countermeasures in geothermal energy development ･･･････････････ 6-14

Chapter 7

Fig. 7.1-1 Peak load forecast ･･･････････････････････････････････････････････ 7-2

Fig. 7.1-2 Assumed Load Duration Curve ･････････････････････････････････････ 7-2

Fig. 7.1-3 Power plant development plan (2007 – 2016) ~ Business as usual

scenario ~ ･･････････････････････････････････････････････････････ 7-4

Fig. 7.1-4 Geothermal Development Road Map 2004-2025 ･･･････････････････････ 7-5

Fig. 7.1-5 Forecast of geothermal energy development by “JICA Master Plan

Study” ････････････････････････････････････････････････････････ 7-5

Fig. 7.1-6 Power plant development plan (2007 – 2016) ~ Geothermal

acceleration scenario ~････････････････････････････････････････････ 7-6

Fig. 7.2-1 Energy generation by fuel types (2007 -2016) ~ Business as usual

scenario ~ ･･････････････････････････････････････････････････････ 7-8

Fig. 7.2-2 Energy generation by fuel types (2007 -2016)~ Geothermal


Fig. 7.2-3 Thermal power substitution effect of geothermal power (GWh) (2007

– 2016) ~ Difference between business as usual scenario and

geothermal acceleration scenario ~ ･･････････････････････････････････ 7-9

Fig. 7.2-4 Fuel reduction value (2007 -2016) ･････････････････････････････････ 7-10

Fig. 7.2-5 Fuel reduction premium of geothermal power (2007 -2016) ･････････････ 7-11

Fig. 7.3-1 Export value of fuel saved through use of geothermal power (2007 –

2016) ･･･････････････････････････････････････････････････････ 7-12

Fig. 7.4-1 Selling price composition comparison of geothermal and coal-fired

Power ~ For Benchmark oil price at 100 USD/barrel ~･･････････････････ 7-13

Fig. 7.5-1 Price of carbon dioxide emission credits ･････････････････････････････ 7-14

Fig. 7.6-1 Total value of benefits of geothermal power generation (2007 –

2016) ･･･････････････････････････････････････････････････････ 7-15

Fig. 7.6-2 Total value of benefits of geothermal power and its beneficiaries･･････････ 7-16

Fig. 7.7-1 Ripple effect of 60 MW geothermal power plant construction ････････････ 7-22

Fig. 7.7-2 Comparison of investment in power plant construction (per MW) ･･･････････ 7-29

Fig. 7.7-3 Effects on domestic economy of 60 MW power plant construction ･･･････････ 7-29


JICA West JEC viii

Fig. 7.7-4 Employment increase for 60MW power plant construction･････････････････ 7-29

Chapter 8

Fig. 8.1-1 WTI Spot Price variation ･･････････････････････････････････････････ 8-1

Fig. 8.1-2 Coal Price variation in Indonesia（5,800kcal/kg）･･････････････････････ 8-1

Fig. 8.1-3 Estimated selling prices of power by fuel sources ･･･････････････････････ 8-2

Fig. 8.1-4 Estimated selling prices of power taking into account for opportunity

costs ･･････････････････････････････････････････････････････････ 8-2

Fig. 8.1-5 Estimated selling price of power accounting for environment impact

costs ･･････････････････････････････････････････････････････････ 8-3

Fig. 8.2-1 Incentive cost and benefit･･････････････････････････････････････････ 8-4

Fig. 8.2-2 Composition of selling price ･･･････････････････････････････････････ 8-6

Fig. 8.2-3 Effect of fiscal incentives･･････････････････････････････････････････ 8-6

Fig. 8.2-4 Effect of tax incentives････････････････････････････････････････････ 8-7

Fig. 8.2-5 Effect of financial incentives ･･･････････････････････････････････････ 8-7

Fig. 8.3-1 Renewable energy development policies of 25 EU nations ･･･････････････ 8-10

Fig. 8.3-2 Price change patterns of 2-stage system ･････････････････････････････ 8-14

Fig. 8.3-3 Prices under 2-stage FIT price (at 25% tax rate) ･･････････････････････ 8-14

Fig. 8.3-4 Generation costs and FIT price change during operation period（at

25% tax）･････････････････････････････････････････････････････ 8-15

Fig. 8.3-5 Generation costs and FIT price change during operation period (at

5% tax for 15 years) ････････････････････････････････････････････ 8-16

Fig. 8.3-6 Generation costs and FIT price change during operation period (20

MW at 25% tax) ･･･････････････････････････････････････････････ 8-18

Fig. 8.3-7 Generation costs and FIT price change during operation period (20

MW at 5% tax for 15 years) ･･････････････････････････････････････ 8-19

Fig. 8.4-1 FIT and RPS･･･････････････････････････････････････････････････ 8-21

Fig. 8.5-1 Effect of accelerated depreciation ･･････････････････････････････････ 8-24

Fig. 8.5-2 Investment allowance effect (5% annual deduction) ････････････････････ 8-25

Fig. 8.5-3 Investment allowance effect (without annual restriction) ････････････････ 8-25

Fig. 8.5-4 Tax on geothermal and coal-fired IPP business（at 25% tax rate）････････ 8-26

Fig. 8.5-5 Effect of tax Incentives ･･････････････････････････････････････････ 8-26

Fig. 8.5-6 Tax on geothermal and coal-fired IPP business ････････････････････････ 8-27

Fig. 8.5-7 Effect and cost of tax incentives (at 5% tax rate for 15 years)･････････････ 8-27


JICA West JEC ix

Fig. 8.6-1 Effect of fiscal incentives in Denmark and Japan ･･････････････････････ 8-28

Fig. 8.6-2 Subsidy Effect (at 30% tax) ･･････････････････････････････････････ 8-29

Fig. 8.6-3 Subsidy Effect（at 5% tax rate for 15 years）････････････････････････ 8-29

Fig. 8.6-4 Effect of initial governmental survey････････････････････････････････ 8-30

Fig. 8.6-5 Effect of government survey ･･････････････････････････････････････ 8-31

Fig. 8.6-6 Effect and benefit of governmental survey ･･･････････････････････････ 8-31

Fig. 8.7-1 Effect of low-interest loans for construction ･･････････････････････････ 8-33

Fig. 8.7-2 Effect of low-interest loans for construction & confirmation ･････････････ 8-33

Fig. 8.7-3 Effect and benefit of low-interest loans ･･････････････････････････････ 8-34

Chapter 9

Fig. 9.1-1 Geothermal development process in Indonesia ･････････････････････････ 9-1

Fig. 9.2-1 Incentives to promote geothermal “Green Field” development･････････････ 9-5

Fig. 9.3-1 Measures to change “Green Field” to “Brown Field” ････････････････････ 9-7

Fig. 9.4-1 Public-Private Partnership in geothermal development in the

Philippines ･････････････････････････････････････････････････････ 9-8

Fig. 9.4-2 Measures for risk-free participation ･･････････････････････････････････ 9-9

Chapter 10

Fig. 10.1-1 Indonesian coal production and consumption ･････････････････････････ 10-2

Fig. 10.1-2 Indonesian domestic coal consumption by industry ････････････････････ 10-2

Fig. 10.2-1 Real-term unit construction cost of coal-fired power plants in Japan ･･････ 10-5

Fig. 10.2-2 Comparison of estimation and original data･･･････････････････････････ 10-7

Fig. 10.3-1 Long-term selling price of coal-fired power ･･････････････････････････ 10-9

Chapter 11

Fig. 11.1-1 Real-term unit construction cost of geothermal power plants in Japan

(2000 JPY) ････････････････････････････････････････････････････ 11-2

Fig. 11.1-2 Comparison of estimation and original data ･･････････････････････････ 11-2

Fig. 11.2-1 Days per well at Salak Geothermal PP ･･････････････････････････････ 11-6

Fig. 11.2-2 Improvement in geothermal steam turbine efficiency ･･････････････････ 11-6

Fig. 11.2-3 Learning effect in solar and wind power ････････････････････････････ 11-6

Fig. 11.2-4 Long-term selling price of geothermal power ･････････････････････････ 11-9


JICA West JEC x

Chapter 12

Fig. 12.1-1 Scheme of CDM････････････････････････････････････････････････ 12-1

Fig. 12.1-2 Procedure of CDM ･････････････････････････････････････････････ 12-2

Fig. 12.1-3 Indonesia DNA validation Process･･････････････････････････････････ 12-6

Fig. 12.1-4 CDM effect （2012-2016）･････････････････････････････････････ 12-7

Fig. 12.1-5 Long-term CDM effect (Weak Cost Reduction Case) ･･･････････････････ 12-8

Fig. 12.1-6 Long-term CDM effect (Strong Cost Reduction Case) ･･････････････････ 12-8

Fig. 12.2-1 Mechanism of environmental tax･･････････････････････････････････ 12-13

Fig. 12.2-2 Effect of carbon tax （2012-2016）･･･････････････････････････････ 12-22

Fig. 12.2-3 Long-term effect of carbon tax････････････････････････････････････ 12-23

Fig. 12.2-4 Carbon tax impact on prices for each industry････････････････････････ 12-27

Fig. 12.2-5 Carbon tax impact on prices for each industry (Tax revenue-neutral

case) ････････････････････････････････････････････････････････ 12-29

Fig. 12.3-1 National production ratio for each industry in Indonesia (2005）･････････ 12-30

Fig. 12.3-2 Long-term effect of technology localization (Weak cost reduction

case) ････････････････････････････････････････････････････････ 12-38

Fig. 12.3-3 Long-term effect of technology localization (Strong cost reduction

case) ････････････････････････････････････････････････････････ 12-38

Chapter 13

Fig. 13.1-1 Beneficiary projects of the Feed-in Tariff incentives ･･･････････････････ 13-2

Fig. 13.1-2 Beneficiary projects of the Tax Reduction and Feed-in Tariff

combination incentives ･････････････････････････････････････････ 13-2

Fig. 13.1-3 Beneficiary projects of the GDPS and Feed-in Tariff combination

incentives ････････････････････････････････････････････････････ 13-3

Fig. 13.2-1 Costs and benefits in the Feed-in Tariff incentives case ････････････････ 13-5

Fig. 13.2-2 Costs and benefits in the Feed-in Tariff incentives case ････････････････ 13-7

Fig. 13.2-3 Sensitivity analysis of the Feed-in Tariff incentives ････････････････････ 13-7

Fig. 13.3-1 Costs and benefits in the Tax Reduction and Feed-in Tariff

combination incentives case ･･････････････････････････････････････ 13-9

Fig. 13.3-2 Costs and benefits in the Tax Reduction and Feed-in Tariff

combination incentives case ･････････････････････････････････････ 13-11

Fig. 13.3-3 Sensitivity analysis of the Tax Reduction and Feed-in Tariff

combination incentives ･････････････････････････････････････････ 13-11


JICA West JEC xi

Fig. 13.4-1 Scheme of the GDPS Fund ･･････････････････････････････････････ 13-12

Fig. 13.4-2 Costs and benefits in the GDPS and Feed-in Tariff combination

incentives case ･･･････････････････････････････････････････････ 13-13

Fig. 13.4-3 Expenditure, income and year-end balance of the GDPS Fund ･･････････ 13-16

Fig. 13.4-4 Costs and benefits in the GDPS and Feed-in Tariff combination

incentives case ･･･････････････････････････････････････････････ 13-18

Fig. 13.4-5 Sensitivity analysis of the GDPS and FIT combination incentives ･･･････ 13-19

Chapter 14

Fig. 14.1-1 Geothermal development outlook in the JICA Master Plan Study ･････････ 14-4

Chapter 15

Fig. 15.1-1 Relation between number of volcanoes and geothermal potential･･････････ 15-3

Fig. 15.1-2 Employment creation by geothermal and coal-fired projects ･････････････ 15-3

Fig. 15.1-3 Production increase created by geothermal and coal-fired projects･････････ 15-3

Fig. 15.1-4 Green New Deal Policy of Indonesia ･･･････････････････････････････ 15-3

Fig. 15.1-5 Geothermal industry cluster ･･････････････････････････････････････ 15-5

Fig. 15.1-6 Prototype of binary processing type turbine/generator (1MW)

developed by BPPT ････････････････････････････････････････････ 15-7

Fig. 15.1-7 Hot water utilization in palm sugar (Lahendong geothermal power

plant) ･･･････････････････････････････････････････････････････ 15-7

ANNEX-1

Fig. A1-1 Basic configuration of Economic Evaluation Model of a geothermal

power project ････････････････････････････････････････････ANNEX-1-3

ANNEX-3

Fig. A3-1 Price change in each industry when electric price increases by 2.48% ･･ANNEX-3-4

ANNEX-4

Fig. A4.2-1 Costs and benefits in the Feed-in Tariff incentives case (in the case of

excluding Fuel Export Value) ･･･････････････････････････････ANNEX-4-2

Fig. A4.2-2 Costs and benefits in the Feed-in Tariff incentives case (in the case of



JICA West JEC xii

Fig. A4.2-3 Sensitivity analysis of the Feed-in Tariff incentives ･････････････ANNEX-4-5

Fig. A4.3-1 Costs and benefits in the Tax Reduction and Feed-in Tariff

combination incentives case (in the case of excluding Fuel Export

Value) ･････････････････････････････････････････････････ANNEX-4-6

Fig. A4.3-2 Costs and benefits in the Tax Reduction and Feed-in Tariff


Value) ･････････････････････････････････････････････････ANNEX-4-8

Fig. A4.3-3 Sensitivity analysis of the Tax Reduction and Feed-in Tariff

combination incentives ････････････････････････････････････ANNEX-4-8

Fig. A4.4-1 Costs and benefits in the GDPS and Feed-in Tariff combination

incentives case (in the case of excluding Fuel Export Value) ･･･････ANNEX-4-9

Fig. A4.4-2 Costs and benefits in the GDPS and Feed-in Tariff combination

incentives case (in the case of excluding Fuel Export Value) ･･････ANNEX-4-12

Fig. A4.4-3 Sensitivity analysis of the GDPS and FIT combination incentives ･ANNEX-4-12

＜List of Tables＞

Chapter 2

Table 2.10-1 Assumptions of this study ････････････････････････････････････････ 2-21

Table 2.10-2 Future fuel price forecast by IEA･･･････････････････････････････････ 2-21

Table 2.10-3 Future fuel price forecast in RUPTL 2009-2018 of PLN･････････････････ 2-22

Table 2.10-4 Future fuel prices used in this study･････････････････････････････････ 2-22

Chapter 3

Table 3.1-1 Indonesia Geothermal Potential ･････････････････････････････････････ 3-5

Table 3.1-2 Geothermal power plants in Indonesia and their development scheme ･･･････ 3-6

Table 3.2-1 Selling prices by power plant･･････････････････････････････････････ 3-19

Table 3.2-2 IPP’s Geothermal Electricity Prices : original versus negotiated･･･････････ 3-22

Table 3.2-3 IPP’s Non-Geothermal Electricity Prices : original versus negotiated･･･････ 3-22

Table 3.3-1 Status of Geothermal Development Contracts As of 1 January 2009 ･･･････ 3-33

Table 3.4-1 Tax rates comparison under new and old laws ････････････････････････ 3-36

Table 3.5-1 Results of the bidding for geothermal power development in 2008 ････････ 3-39

Table 3.5-2 The purchase price guideline for geothermal power plant ････････････････ 3-41


JICA West JEC xiii

Chapter 5

Table 5.1-1 Specifications of benchmark coal-fired IPP project･･････････････････････ 5-1

Table 5.1-2 Finance procurement conditions ････････････････････････････････････ 5-2

Table 5.2-1 Assumed variation of risk factors････････････････････････････････････ 5-4

Table 5.2-2 Risk factor evaluation in Monte Carlo Method simulation ････････････････ 5-6

Table 5.3-1 Conditions of Benchmark Price calculation････････････････････････････ 5-8

Table 5.3-2 Selling price for coal-fired IPP project (Benchmark Price) ･･･････････････ 5-9

Table 5.3-3 Income Statement of coal-fired IPP project ･･･････････････････････････ 5-10

Table 5.3-4 Cash Flow Statement of coal-fired IPP project ････････････････････････ 5-11

Chapter 6

Table 6.1-1 Specification of geothermal IPP project･･･････････････････････････････ 6-1

Table 6.1-2 Finance procurement condition ･････････････････････････････････････ 6-4

Table 6.1-3 WACC of geothermal IPP project ･･･････････････････････････････････ 6-5

Table 6.2-1 Assumed variation in risk factors････････････････････････････････････ 6-9

Table 6.2-2 Risk factor evaluation by Monte Carlo Method simulation･･･････････････ 6-10

Table 6.3-1 Assumptions for calculation of Geothermal Price ･･････････････････････ 6-15

Table 6.3-2 Income Statement of geothermal IPP project･･････････････････････････ 6-16

Table 6.3-3 Cash Flow Statement of geothermal IPP project ･･･････････････････････ 6-17

Chapter 7

Table 7.1-1 Power demand forecast (2007 – 2016) ･･･････････････････････････････ 7-1

Table 7.1-2 List of power plants in Indonesia by fuel type (2006) ･･･････････････････ 7-2

Table 7.1-3 Approximated capacity and unit numbers of present power plants for

WASP-IV simulation ･････････････････････････････････････････････ 7-2

Table 7.1-4 Specifications of existing and planned power plants for WASP-IV

simulation. ････････････････････････････････････････････････････ 7-3

Table 7.1-5 Specifications of new candidate power plants for WASP-IV

simulation. ････････････････････････････････････････････････････ 7-3

Table 7.1-6 Power plant development plan (2007 – 2016) ~ Business as usual

scenario ~ ･･････････････････････････････････････････････････････ 7-4

Table 7.1-7 Geothermal energy development in the geothermal acceleration

scenario ･･･････････････････････････････････････････････････････ 7-5

Table 7.1-8 Power plant development plan (2007 – 2016) ~ Geothermal


JICA West JEC xiv


Table 7.1-9 Effect of substitution of geothermal power for thermal power (MW)

(2007 – 2016) ~ Difference between business as usual scenario and


Table 7.2-1 Energy generation by fuel types (2007 -2016)~ Business as usual

scenario ~ ･･････････････････････････････････････････････････････ 7-8

Table 7.2-2 Energy generation by fuel types (2007 -2016)~ Geothermal


Table 7.2-3 Thermal power substitution effect of geothermal power (GWh) (2007

– 2016) ~ Difference between business as usual scenario and


Table 7.2-4 Thermal power fuel reduction effect of geothermal power (Volume)

(2007 -2016) ･･････････････････････････････････････････････････ 7-10

Table 7.2-5 Thermal power fuel reduction effect of geothermal power (2007

-2016) ~ For Benchmark oil price at 100 USD/barrel ~ ･････････････････ 7-10

Table 7.3-1 Export value of fuel saved through use of geothermal power (2007 –

2016) ~ For Benchmark oil price at 100 USD/barrel ~ ･･････････････････ 7-11

Table 7.4-1 Comparison of selling price composition between geothermal and

coal-fired Power ~ For Benchmark oil price at 100 USD/barrel ~ ･････････ 7-12

Table 7.5-1 CO2 Reduction through adoption of geothermal power (2007 -2016) ･･････ 7-14

Table 7.6-1 Total value of geothermal power (2007 – 20016) ~ CO2 credit at 20

USD/ton ~ ････････････････････････････････････････････････････ 7-15

Table 7.6-2 Total Value of benefits of geothermal power by beneficiaries ･････････････ 7-16

Table 7.7-1 Assumed allocations of domestic procurement for 60 MW

geothermal power plant construction････････････････････････････････ 7-20

Table 7.7-2 Construction effects of a geothermal power plant ･･････････････････････ 7-21

Table 7.7-3 Sectors with increasing production ･････････････････････････････････ 7-22

Table 7.7-4 Sectors with increasing employment ････････････････････････････････ 7-22

Table 7.7-5 Assumed allocations of domestic procurement for 600 MW

coal-fired power plant construction ････････････････････････････････ 7-25

Table 7.7-6 Construction effects of coal-fired power plant (60 MW equivalent) ･･･････ 7-26

Table 7.7-7 Comparison of domestic procurement of geothermal and coal-fired

power plants ･･･････････････････････････････････････････････････ 7-27

Table 7.7-8 Comparison of construction effects of geothermal and coal-fired


JICA West JEC xv

power plants ･･･････････････････････････････････････････････････ 7-27

Table 7.7-9 Effects of coal-fired power plant construction (2012 – 2016)~

Business as usual scenario ~ ･･････････････････････････････････････ 7-28

Table 7.7-10 Effects of geothermal power plant construction (2012 – 2016)~

Geothermal acceleration scenario ~ ･････････････････････････････････ 7-28

Table 7.7-11 Deference of effects between two scenarios (2012 – 2016)~ Effects

of geothermal acceleration scenario ~ ･･･････････････････････････････ 7-28

Chapter 8

Table 8.2-1 Classification of Renewable Energy Promotion Policies･･････････････････ 8-8

Table 8.3-1 Feed-in Tariff prices for geothermal plant in Germany (January,

2009) ･･･････････････････････････････････････････････････････ 8-10

Table 8.3-2 FIT prices and purchase terms for 18 nations in EU ････････････････････ 8-12

Table 8.3-3 Price change patterns for 2-stage FIT price system ･････････････････････ 8-13

Table 8.3-4 Price calculation result for 2-stage FIT price system（at 25% tax rate）

･････････････････････････････････････････････････････････････ 8-13

Table 8.3-5 Fixed FIT price and 2-stage FIT prices (at 5% tax rate for 15 years) ･･････ 8-14

Table 8.3-6 Proposal of FIT prices ･･･････････････････････････････････････････ 8-15

Table 8.3-7 Specifications and selling prices for a 100MW coal-fired power plant ･･････ 8-17

Table 8.3-8 Specifications and selling prices for a 20 MW geothermal power

plant ･････････････････････････････････････････････････････････ 8-17

Table 8.3-9 Selling price for a 20 MW geothermal power plant･････････････････････ 8-18

Table 8.3-10 Proposal of FIT prices (20 MW or less capacity case) ･･････････････････ 8-18

Table 8.3-11 Influence of FIT scheme ･････････････････････････････････････････ 8-20

Table 8.3-12 Influence of FIT passed through to end-users ･････････････････････････ 8-20

Table 8.5-1 Tax exemption incentives for renewable energy ･･･････････････････････ 8-23

Table 8.5-2 Depreciation schedule（Law No.36/2008）･･････････････････････････ 8-24

Table 8.6-1 Scale and specification of initial governmental survey ･･････････････････ 8-30

Chapter 10

Table 10.2-1 Unit construction cost of coal-fired power plants in Japan ･･･････････････ 10-3

Table 10.2-2 Independent variables of estimation equation ････････････････････････ 10-5

Table 10.2-3 Results of estimation (Sample number: 55) ･･･････････････････････････ 10-6

Table 10.2-4 Forecast of unit construction cost of coal-fired plant in 2007 and


JICA West JEC xvi

2025 ･････････････････････････････････････････････････････････ 10-8

Table 10.3-1 Long-term selling price of coal-fired power ･･････････････････････････ 10-8

Chapter 11

Table 11.1-1 Unit construction cost of geothermal power plants in Japan ･･････････････ 11-1

Table 11.1-2 Independent variables of estimation equation ････････････････････････ 11-2

Table 11.1-3 Results of estimation （Sample number：17）･･･････････････････････ 11-3

Table 11.1-4 Forecast of unit construction cost of geothermal plant in 2007 and

2025 ･････････････････････････････････････････････････････････ 11-4

Table 11.2-1 Major technology improvements expected for flash-system

geothermal power plants ･････････････････････････････････････････ 11-7

Table 11.2-2 Forecast of future cost reduction ･･･････････････････････････････････ 11-8

Table 11.2-3 Long-term selling price (Weak cost reduction case) ････････････････････ 11-8

Table 11.2-4 Long-term selling price (Strong cost reduction case)････････････････････ 11-9

Table 11.2-5 Long-term selling price of geothermal power ･････････････････････････ 11-9

Chapter 12

Table 12.1-1 Status of Indonesia in Kyoto Protocol ･･･････････････････････････････ 12-4

Table 12.2-1 Energy taxation history of European countries ･･････････････････････ 12-16

Table 12.2-2 Energy tax tariff in Japan and European countries････････････････････ 12-187

Table 12.2-3 Energy tax rate per 1 ton of CO2 emission in Japan and European

countries ･････････････････････････････････････････････････････ 12-18

Table 12.2-4 Price elasticity of energy consumption in Japan ･･････････････････････ 12-19

Table 12.2-5 Environment-related tax revenues ･････････････････････････････････ 12-20

Table 12.2-6 Factors to consider in designing carbon tax･･････････････････････････ 12-21

Table 12.2-7 Carbon tax rate････････････････････････････････････････････････ 12-21

Table 12.2-8 Design of carbon tax and estimated tax revenue ･･････････････････････ 12-22

Table 12.2-9 Carbon tax impact on the value-added ratio and prices for each

industry･･････････････････････････････････････････････････････ 12-26

Table 12.2-10 Carbon tax impact on the value-added ratio and prices for each

industry (Tax revenue-neutral case) ････････････････････････････････ 12-28

Table 12.3-1 Local content in supplies to upstream oil and gas activity･･･････････････ 12-33

Table 12.3-2 Process of technology localization in the motorcycle industry in

Thailand and Indonesia ･････････････････････････････････････････ 12-35


JICA West JEC xvii

Table 12.3-3 Comparison of steam conditions of geothermal and coal plants ･･････････ 12-37

Chapter 13

Table 13.1-1 Geothermal development forecast ･････････････････････････････････ 13-1

Table 13.2-1 Benefits and beneficiaries in geothermal development ･････････････････ 13-4

Table 13.2-2 Costs and benefits in the Feed-in Tariff incentives case ･････････････････ 13-6

Table 13.2-3 Sensitivity analysis of the Feed-in Tariff incentives ････････････････････ 13-7

Table 13.3-1 Costs and benefits in the Tax Reduction and Feed-in Tariff

combination incentives case ････････････････････････････････････ 13-10

Table 13.3-2 Sensitivity analysis of the Tax Reduction and Feed-in Tariff

combination incentives ････････････････････････････････････････ 13-10

Table 13.4-1 Implementation plan of GDPS ･･･････････････････････････････････ 13-12

Table 13.4-2 Expenditures, income and cash flow of the GDPS Fund ･･･････････････ 13-16

Table 13.4-3 Costs and benefits in the Geothermal Development Promotion

Survey and Feed-in Tariff combination incentives case ･･･････････････ 13-17

Table 13.4-4 Sensitivity analysis of the GDPS and FIT combination incentives ････････ 13-19

Chapter 14

Table 14.1-1 Comparison between the First and Second Crash Programs ･･･････････････ 14-1

Table 14.1-2 Geothermal projects listed in the Second Crash program ･････････････････ 14-2

Table 14.1-3 Development outlook by developer in the Second Crash Program ･･････････ 14-3

Chapter 15

Table 15.1-1 Geothermal resources in the World ･････････････････････････････････ 15-3

Table 15.1-2 Geothermal industry development strategy ･･････････････････････････ 15-10

ANNEX-2

Table A2-1 Input Output Table of 47 Sectors (Domestic Table) ･･････････････ANNEX-2-1

Table A2-2 Input Coefficients (47 sectors) ･･････････････････････････････ANNEX-2-5

ANNEX-3

Table A3-1 Price change in each industry when electric price increases by 2.48% ･･ANNEX-3-3

ANNEX-4


JICA West JEC xviii

Table A4.2-1 Benefits and beneficiaries in geothermal development (in the case of


Table A4.2-2 Costs and benefits in the Feed-in Tariff incentives case (in the case of


Table A4.2-3 Sensitivity analysis of the Feed-in Tariff incentives ･･････････････ANNEX-4-5

Table A4.3-1 Costs and benefits in the Tax Reduction and Feed-in Tariff


Value) ･････････････････････････････････････････････････ANNEX-4-7

Table A4.3-2 Sensitivity analysis of the Tax Reduction and Feed-in Tariff

combination incentives ････････････････････････････････････ANNEX-4-8

Table A4.4-1 Costs and benefits in the Tax Reduction and Feed-in Tariff


Value) ････････････････････････････････････････････････ANNEX-4-10

Table A4.4-2 Sensitivity analysis of the GDPS and FIT combination incentives ･ANNEX-4-12


JICA West JEC xix

Acronyms and Abbreviations

AMOSEAS subsidiary company of CHEVRON TEXACO

BAU Business as Usual

BOT Build, Operate and Transfer

BPPT National Agency for Assessment and Application Technology

BUMD participation of regional government owned companies

CA Contract Area

CAPM Capital Asset Price Model

CC Corporate Company / Constitutional Court / Capacity Charge

CDM Clean Development Mechanism

CDO Curtailed Delivery Output

CERs Certified Emission Reductions

CG Central Government

CGPI Corporate Goods Price Index

CGR Center of Geological Resource

CICB Capital Investment Coordinating Board

CKD Complete Knock-Down

CO2 Carbon Dioxides

COP Conference of Parties

COW Contract of Works

CPI Consumer Price Index

CRIEPIR Central Research Institute of Electric Power Industry Review

DCIL Domestic Capital Investment Law

DDI Domestic Direct Investment

DFO Date of First Operation

DGEEU Directorate General of Electricity and Energy Utilization

DGGMR Directorate General of Geology and Mineral Resources

DGMCG Directorate General of Mineral, Coal and Geothermal

DGT Directorate General of Tax

DNA Designated National Authority

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

DOE Designated Operational Entity


JICA West JEC xx

DTO District Tax Office

DTT Double Tax Treaties

EB Executive Board

EIA Energy Information Agency (USA)

EL Electricity Law

EPC Engineering, Procurement and Construction

EqIRR Equity Internal Rate of Return

EqIRRc Equity Internal Rate of Return Criteria

ESC Energy Sales Contract

FBL Financial Balance Law

FCIL Foreign Capital Investment Law

FDI Foreign Direct Investment

FEED Front-end Engineering and Design

FF Fixed Fees

FIL Foreign Investment Law

FIRR Financial Internal Rate of Return

FIT Feed-in Tariff

FOM Fixed O&M Fee

FPL Florida Power & Light

FSA Fuel Supply Agreement

GBP Geothermal Business Permit

GC Generation Component

GDP Gross Domestic Production

GDPS Geothermal Development Promotion Survey

GHG Green-house Gas

GL Geothermal Law

GOI Government of Indonesia

GR Government Regulation

GRC Generation and Resource Components

GSS Geothermal Sector Survey

GWA Geothermal Work Area

HCE Himpurna California Energy Limited

HPP/BPP Harga/Biaya Pokok Produksi (Basic Production Price/Cost)


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HRSG Heat Recovery Steam Generator

IEA International Energy Agency

IMEMR Indonesian Ministry of Energy and Mineral Resources

IOCs International Oil Companies

IPP Independent Power Producer

ITL Income Tax Law

IUP Geothermal Energy Business Permit

JAMALI Java, Madura and Bali

JBIC Japan Bank for International Cooperation

JICA Japan International Cooperation Agency

JOC Joint Operation Contract

KBC Karaha Bodas Company LLC

KfW Deutche Wiederbau Bank

KNMPB Komite Nasional Mekanisme Pembangunan Bersih (National Commission

for CDM)

LCOE Levelized Cost of Electricity

LNG Liquefied Natural Gas

MEMR Minister of Energy and Mineral Resources

MEMRD Minister of Energy and Mineral Resources Decree

METI Ministry of Economy, Trade and Industry (Japan)

MITI Ministry of International Trade and Industry (Japan)

MME Ministry of Mine and Energy

MOE Ministry of Environment (Japan)

MOF Minister of Finance

MOFD Ministry of Finance Decree

MOU Minutes of Understanding

NEDO New Energy and Industrial Technology Development Organization (Japan)

NEF New Energy Foundation (Japan)

NEO Net Electrical Output

NGO Non-Governmental Organization

NOI Net Operating Income

NOｘ Nitrogen Oxides

NPV Net Present Value


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O&M Operation and Maintenance

OECD Organization for Economic Cooperation and Development

OLS Ordinary Least Square

OPIC Overseas Private Investment Corporation

OPTRES Optimization of Renewable Energy Support Schemes

PD Presidential Decrees

PDD Project Design Document

Perpres Presidential Regulation

PF Production Fees

PG Provincial Government

PGE Pertamina Geothermal Energy

PMDN Penanaman Model Dalam Negeri

PNOC-EDC Philippine National Oil Company - Energy Development Corporation

PP Power Plant

PPA Power Purchase Agreement

PPD Power Private Decree

PPP Purchase Power Parity / Public Private Partnership

PQ Prequalification

PR Presidential Regulation

PrIRR Project Internal Rate of Return

PrIRRc Project Internal Rate of Return Criteria

PSC Production Sharing Contract

PSRP Power Sector Restructuring Policy

PT PLN PT Perusahaan Listrik Negara (National Electric Company)

PV Present Value / Photo Voltaic

QCD Quality, Cost and Delivery

R&D Research and Development

RAL Regional Autonomy Law

RC Resource Component

RE Renewable Energy

RG Regional Government

RMc Commercial Risk Margin

RMr Resource Risk Margin


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RMt Technical Risk Margin

RPS Renewable Energy Portfolio Standard

RUKD General Plan for Regional Electricity

RUKN General Plan for National Electricity

RUPTL Power Development Program of PT PLN

SME Small and Medium size Enterprise

SOP Share of Proceeds

SOｘ Sulfur Dioxides

T/D Transmission/Distribution

TAL Tax Administration Law

TDL Tarif Dasar Listrik (Basic Electricity Price)

TGC Tradable Green Certificate

TI Taxable Income

TOE Ton of Oil Equivalent

TOP Take-or-Pay

UCRF Uniform Capital Recovery Factor

UNCITRAL The United Nations Commission on International Trade Law

UNFCCC United Nations Framework Convention on Climate Change

URC Unit Rated Capacity

VAT Value Added Tax

VE Value Engineering

VOM Variable O&M Fee

WACC Weighted Average of Capital Cost

WASP Wien Automatic System Planning

WB World Bank

WKP Wilayah Kerja Pertambangan (Mining Work Area)

WTO World Trade Organization


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Unit Prefixes

k : kilo- =103 M : mega- =106

G : giga- =109

T : tera- =1012

Units of Length km : kilometer

Units of Area km2 : square kilometer ha : hectare

Units of Volume m3 : cubic meter l : liter kl : kiloliter barrel : barrel (1 barrel = 0.159 kl) SCF : standard cubic feet (1 SCF = 0.0283 kl)

Units of Mass kg : kilogram t : ton (metric)

Units of Energy kWh : kilowatt-hour MWh : megawatt-hour GWh : gigawatt-hour MMBTU : million British thermal unit (1 MMBTU = 0.252*106 kcal) TOE : ton of oil equivalent (1*107 kcal) KTOE : kilo ton of oil equivalent (1*1010 kcal)

Units of Temperature ℃ : degree Celsius

Units of Electricity kW : kilowatt MW : megawatt kV : kilovolt kVA : kilovolt-ampere

Units of Currency IDR (Rp) : Indonesian Rupiah USD ($) : US Dollar JPY (¥) : Japanese Yen

EXECTIVE SUMMARY


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EXECTIVE SUMMARY

Energy consumption in Indonesia has increased rapidly with the high economic growth rate of recent years. Indonesia’s CO2 emissions from energy use have increased rapidly and have made the country the 15th largest CO2 emitter in the world. Energy diversification is one of the main ways to reduce the dependency on fossil fuel and to mitigate CO2 emissions. Indonesia has a variety and large scale of natural energy resources – not only oil, gas and coal but also geothermal energy and other renewable energy like hydro, bio, and wind. Among these sources of renewable energy, Indonesia has the largest geothermal energy potential in the world – approximately 27.0 GW. It is strongly expected for Indonesia to make use of these affluent geothermal resources to reduce CO2 emissions. The geothermal generation capacity has reached 1,196MW in Indonesia. Although Indonesia is the fourth largest producer of geothermal power in the world, it is far from exploiting this huge potential of geothermal energy as well as possible.

The barriers which hinder smooth development of geothermal energy are the

development risks of underground resources and the burden of enormous up-front investment. Therefore, the purchase price of geothermal energy should include a reward for challenging these barriers. Consequently, although it is lower than the price of diesel or heavy-oil power plant energy, the price of geothermal energy becomes higher than that of coal-fired plant energy. However, PT PLN, a buyer of geothermal energy, has a mission to supply inexpensive power to consumers and this mission makes it reluctant to increase the purchase price it pays for geothermal energy. The unattractive purchase price of PT PLN causes private IPP companies hesitation in investing geothermal projects in Indonesia.

Solutions to this problem are not be obtained if the problem is left only in the hands of

the private IPP company and PT PLN, and no more geothermal development can be expected. However, it is necessary to pay attention to the fact that government can be a key player in realizing the benefits of geothermal development by private IPP. When geothermal energy is exploited, the society is likely to obtain several benefits. It is one of the important missions of the government to realize these geothermal benefits and endow the society with them.

In this Study, the oil price is assumed to be 100 USD/barrel, and coal 90 USD/ton

(5,300 kcal/kg), referring to the latest forecasts of the International Energy Agency (IEA) and the Electric Power Development Plan (RUPTL 2009-2018) of PT PLN. Theses prices are assumed to stay this level until 2025 to simplify the analysis.

As a benchmark, the selling price of a 600 MW coal-fired IPP project is calculated.

Based on a requirement of 11.2% Project IRR and 12.0% Equity IRR, it is calculated as 8.2 USD Cents/KWh. Similarly the selling price of a 60 MW geothermal IPP project is calculated.


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Based on a requirement of 17.1% Project IRR and 17.0% Equity IRR, it is calculated as 11.9 USD Cents/KWh. There is a 3.7 USD Cents/kWh difference between this price and the price for the benchmark coal-fired IPP project. The objective of the policy is to bridge this price gap by fiscal and non-fiscal incentives.

Geothermal energy has several values. These values are calculated as follows: (i)

energy value (a benchmark price) at 8.2 USD Cents/kWh, (ii) fuel cost reduction value at 0.3 USD Cents/kWh, (iii) saved fuel export value at 5.7 USD Cents/kWh, (iv) increased tax revenue value at 1.6 USD Cents/kWh and (v) carbon dioxide reduction value at 1.9 USD Cents/kWh. The total value is 17.7 USD Cents/kWh. These values can be divided by beneficiaries. PT PLN receives 8.2 USD Cents/kWh as (i) energy value. The government receives 3.8 USD Cents/kWh of which the breakdown is: (ii) fuel cost reduction value as subsidy reduction to PT PLN, (iii) 32.5% (tax rate) of saved fuel export value, and (iv) increased tax revenue value. The society receives 5.8 USD Cents/kWh as the remaining of (iii) saved fuel export value and (v) carbon dioxide reduction value. These benefits show that geothermal energy can bring remarkable benefits to PT PLN, the government and the society, if it is well exploited. In addition to these values in operation stage, geothermal energy brings about other benefits in construction stage. Geothermal power plant construction relies heavily on the procurement of work and services from the vicinity of the construction site. That stimulates the domestic economy. These ripple effects are calculated that a 60 MW geothermal plant construction will have a significant job-creating effect as large as 10,060 opportunities.

Based on these discussions, the following incentives are considered appropriate for Indonesia:

(A) Incentives for Green Field development (a-1) Feed-in Tariff incentives of 11.9 USD Cents/kWh, or

(a-2) Tax Reduction of 5% corporate income tax rate for 15 years and Feed-in Tariff of 10.9 USD Cents/kWh.

(B) Measures to change Green Field to Brown Field (b) Geothermal Development Promotion Survey (GDPS) in initial stage carried out by the

government (C) Measures for risk free participation (c) Public-Private Partnership (PPP) development

The cost and benefit analysis of these incentives indicates that all these incentives

bring significant benefits both to the government and the society.

Currently the Indonesia government is planning to start the Second Crash Program. The program aims at a 4,616 MW geothermal development during 2010-2014. This is an ambitious target and the government needs to make utmost efforts to attain the target. For the implementation of the


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Second Crash Program, the most important and urgent policies are the pricing incentives. The Feed-in Tariff incentives can be said to be the easiest, the most important and the most urgent incentives to adopt under the current situation.

Indonesia, with 150 volcanoes and more than 27,000 MW of geothermal resource

potential, is the world’s richest country in geothermal resources. This is a good time for Indonesia to adopt a Green New Deal strategy focused on the development of geothermal energy, when many countries are beginning to identify the type of renewable energy development in which they can achieve a comparative advantage. When the geothermal industry is well developed and serves a large domestic market, the localization of technology will start, triggering the next round of cost reductions and leading to the further expansion of the domestic market. Investment in geothermal projects has a far larger effect in stimulating the national economy and creating more new employment than coal-fired projects. Therefore, the encouragement of investment in geothermal energy raises the likelihood of economic growth and employment expansion. This can be called the Green New Deal policy of Indonesia. For this purpose, the first step should be to implement the incentives to accelerate geothermal energy development proposed in this Study, and to continue the incentives for a certain period to convince everyone inside and outside of Indonesia of the golden future that lies ahead for Indonesia geothermal development.

CHAPTER 1

INTRODUCTION


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CHAPTER 1 INTRODUCTION 1.1 Background of the Study

In September 2008, the Japan Bank for International Cooperation (JBIC) granted a “Climate Change Control Program Loan” to the Indonesian government, thereby inaugurating the financial mechanism of the “Cool Earth Partnership” program. This program loan is subject to conditions on the Indonesian government which have been agreed in advance between the Indonesian government and the Japanese government and constitute a policy matrix to promote steady implementation of climate change control measures in Indonesia.

Indonesia is said to have the largest geothermal potential in the world. According to the Indonesian Ministry of Energy and Mineral Resources, there are more than 250 prospective geothermal fields in Indonesia, and potential power generation is estimated to be 27,000 MW or more. However, the development of geothermal resources lags behind other energy resource development, and the current geothermal power generation capacity is around 1,000MW only. On the other hand, as expansion of oil subsidies due to soaring global oil prices is placing an increasing pressure on Indonesian government finances, the Indonesian government is facing an urgent necessity to develop oil-alternative energy sources. Further, since geothermal generation rarely has output fluctuations caused by seasonal or weather conditions, it supplies stable electric power and, therefore, can reduce CO2 emissions a great deal by replacing fossil-fuel-burning thermal power generation. For these reasons, the Indonesian government is keenly interested in promoting geothermal energy in order to address climate change issues and to diversify energy sources to reduce over-dependency on oil-based energy. The determination of the Indonesian government on this issue has led the Ministry of Finance to carry out a “Study of Financial and Non-Financial Incentives in the Energy Field (2008)” and “Preparation of Blueprint toward the Innovation of Economic Incentives for Reduction of Greenhouse Gases (2009)”, both of which are incorporated in the policy matrix of the “Climate Change Control Program Loan.”

The objective of the present study is to further the implementation of this “Study of

Fiscal and Non-Fiscal Incentives in the Energy Field” through cooperation between the Indonesian Ministry of Finance and the Japanese side.

1.2 Objective of the Study

This study intends to clarify the mid- and long-term fiscal and non-fiscal incentives promoting private sector-led geothermal energy development through cooperation between the Indonesian Ministry of Finance and the Japanese side in accordance with the policy matrix provisions mentioned above.


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1.3 Contents of the Study

Section 5.6, “Financial Incentives”, of the “Background and Policy Issue Note of the Climate Change Control Program Loan (2008)” reads as follows; “To reduce budgetary burdens because of large energy subsidies by diversifying energy sources, the Ministry of Finance will develop a fiscal incentives framework for GHG emissions to promote private-led investment. In 2008, the Ministry will conduct a study to promote medium- and long- term fiscal incentives, such as tax and non-tax measures, to design an appropriate energy price system for energy diversification and conservation. In 2009, it will prepare a fiscal incentive blue print as a basis of tax and non-tax reforms for energy diversification and GHG emissions reduction.

It is expected that the study will consider necessary fiscal incentives from the perspective of potential investors. Investors are reluctant to invest in geothermal/ renewable energy sectors today, because the possible selling price they seek when using those power sources is higher than those of traditional power sources (e.g. coal and natural gas) and they do not see investing in geothermal/renewable energy sectors attractive. So it would be useful to consider fiscal measures which fill the gap of selling prices of geothermal/renewable energy and traditional power sources (coal and diesel). By carefully examining power generation costs and possible selling prices when using each power source, it is hoped that the study will propose practical policy options based on the reality of Indonesia.”

This study aims to materialize the objectives represented in this description and deals with the following items.

(1) Current situation of geothermal energy development (2) Conditions of the power generation business (3) Economic evaluation of coal-fired power generation business (benchmark) (4) Economic evaluation of geothermal power generation business (5) Benefits of geothermal power generation (6) Short-term incentives to promote geothermal energy development (7) Proposals for short-term incentives (8) Long-term incentives to promote geothermal energy development (9) Cost and benefit analysis of incentives

1.4 Target Area of the Study

The target study area is the whole of Indonesia.


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Ministry of Finance, Indonesia

JICA(Former JBIC）

West JEC

PEN Consulting Co.

MOU for Study

JICA Study Team

Fiscal Policy Office

Joint Study

1.5 Implementation System of the Study

This study is done as a joint study between Fiscal Policy Office of the Ministry of Finance of Indonesia and the Japan International Cooperation Agency.

Fig.1.5-1 Implementation system of the study

CHAPTER 2

BASIC PHILOSOPHY AND THE

PROCESS OF THE STUDY


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0

1,000

2,000

3,000

4,000

5,000

6,000

United State

s of AmericC

hina

Russian Federa

tionJapanIndia

Germany

Canada

United Kingdom Ital

y

Korea (S

outh) IranFran

ceMexico

Australia

Indonesia

GHG Emission from Energy Use (2004)

0.00

50.00

100.00

150.00

200.00

250.00

300.00

350.00

400.00

1980

1981

1982

1983

1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

Oil

Natural gas

Coal

CO2 emission from Energy Source (1980-2004)

Source: EIA, 2007

MtCO2

CHAPTER 2 BASIC PHILOSOPHY AND THE PROCESS OF THE STUDY

2.1 Current Status of Energy Use and CO2 Emission in Indonesia

Energy consumption in Indonesia has increased rapidly with the high economic

growth rate of recent years. In 2004, the energy consumption amounted to 174.0 million TOE (tons of oil equivalent), which was nearly double the 97.1 million TOE consumption of 1990. The share of fossil fuels such as oil and coal reached around 93% of primary energy consumption in 2004, which shows that Indonesia has been highly dependent on fossil fuels, especially on oil. In addition, the country’s energy elasticity and energy intensity remain higher than those of neighboring countries. Thus, dependency on fossil fuel as well as Greenhouse Gas (GHG) emissions could significantly increase, if there is no effective intervention to promote both energy conservation and energy diversification towards renewable forms of energy.

Indonesia’s CO2 emissions from energy use have increased rapidly and reached 362.2 million tons in 2004. (Fig.2.1-1) This emission level made the country the 15th largest CO2 emitter in the world. (Fig.2.1-2) Fig. 2.1-3 shows the CO2 emission growth rate and economic growth rate on a Purchase Power Parity (PPP) basis in Indonesia. While the growth rate of CO2 emissions kept pace with economic growth until 1997, after the Economic Crisis of 1997 this trend suddenly changed, and a large deviation between these two growths is observed. This means that the efficiency of energy use has worsened and emissions of CO2 have been increasing. Indonesia is now the front runner in carbon intensity growth, far outpacing neighboring countries like Thailand, Malaysia, and even India.(Fig. 2.1-4)

Fig.-2.1-1 CO2 emissions from energy use Fig.-2.1-2 World GHG emitters


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0%

20%

40%

60%

80%

100%

120%

140%

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Population

PPP

PPP/Person

National CO2Emissions (excludesland use change)Per Capita CO2Emissions (excludesland use change)

CO2 Emission Growth and Economic Growth Rate (1990-2004)

Source: World Resource Institute (2008)

Fig. 2.1-3 CO2 emissions and economic growth Fig.2.1-4 Growth of energy origin CO2 intensity

While other countries which were also hit by Economic Crisis in 1997 have improved energy use efficiency and have reduced fossil fuel dependency through energy diversification, Indonesia lags behind in improving energy use efficiency and energy diversification. According to the “National Action Plan Addressing Climate Change” (2007), the CO2 emissions from the energy sector are estimated to reach 1,200 million tons in 2025 if the country continues this emissions trend.

Energy diversification is one of the main ways to reduce the dependency on fossil fuel and to mitigate CO2 emissions. According to the National Action Plan, the promotion of energy diversification through utilization of renewable energy and the implementation of energy conservation will contribute to the reduction of CO2 emissions by 17% compared with the Business as Usual (BAU) case in 2025. Indonesia has a variety and large scale of natural energy resources – not only oil, gas and coal but also geothermal energy and other renewable energy like hydro, bio, and wind. Among these sources of renewable energy, Indonesia has the largest geothermal energy potential in the world – approximately 27.0 GW. However, the share of renewable energy was less than 2% (geothermal 1.4%) over production in 2003 because of the various issues which remain to be solved in order to accelerate private investment-led renewable energy development. 2.2 Necessity of Government Intervention

There are several issues which hinder energy diversification towards renewable energy

in Indonesia. The first is governmental subsidies to conventional energy such as oil and electricity. These subsidies distort the energy market and lower the conventional energy price level, increasing energy consumption. Fig-2.2-1 describes this mechanism. The MCF line

Growth of Carbon Intensity from Energy Use (1990-2004)

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

ASEANIndonesiaThailandMalaysiaPhilippinesIndia

Source: World Resource Institute (2008)


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E1

E2:Backstop price

P

Q

MCR 1

MCF1

MB

represents the supply curve of fossil fuel energy production (Marginal Cost of fossil fuel energy production). The MB line is the demand curve (Marginal Benefit). If the market is complete and competitive, the optimal allocation of energy services is at E*, the intersection of MCF and MB. However, because of market distortions by energy subsidies, MCF and MB become flatter and less responsive to price changes, giving MCF1 and MB1 respectively. Thus, the equilibrium allocation point moves to E1, where the price is lower, but the quantity greater.

The second issue is that many sources of renewable energy are still in the introductory stage, the learning effect and economies of mass production have yet to bring down supply prices. Therefore, the prices of renewable energy are higher than those of conventional energy, and a certain governmental support is necessary to make them competitive with conventional energy in the market. With government support, the supply curve (marginal cost curve) of renewable energy (MCR1) moves towards MCR2 which meets the market price of E1. (Fig. 2.2-2)

Fig.2.2-2 Government intervention for REs Fig.2.2-3 Without government intervention

Without government support, introduction of renewable energy within the short-term will fail to be realized. The introduction of renewable energy will have to wait for the conventional energy price to increase to the backstop price E2 in Fig.-2.2-3, and this is likely to take a long time. In addition, the energy price rises and the consumers have to pay the price.

Therefore, the government’s commitment to realizing the optimal allocation of energy resources requires it (i) to reduce subsidies on the conventional energy (to move MCF1 towards MCF2), (ii) to encourage energy conservation on the demand side (to move the MB curve

P

Q

E1

Government Intervention

MCF1

MCR 1

MCR 2

MB1

MCF

MCF 1

Subsidy

MB

Q

P

E*

E1 MB 1

Fig.2.2-1 Energy subsidy and incomplete market


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MCF2MB1

MB

MCF1MCR 1

MCR 2

③RES-E Incentive

①Subsidy cut effect

②Energy Conservation

P

Q

E1

E3

towards MB1), and (iii) to support the diffusion of renewable energy in the market (to move MCR1 towards MCR2). These measures will generate a new equilibrium point, E3, which will approach the optimal resource allocation point E*. (Fig.-2.2-4)

Fig.2.2-4 Policy mix for renewable energy diffusion

As previously mentioned, many sources of renewable energy remain in the initial stage of exploitation, where neither the learning curve nor the mass production effect has yet had a chance to reduce their supply price. However, these effects gradually contribute to a reduction in the supply price, if the introduction of renewable energy proceeds with the support of the government. As a result, if the supply price is decreased enough, the emergence of a situation in which renewable energy prices are lower than conventional energy supply prices can be expected. Once this is the situation, the diffusion of renewable energy will proceed automatically even without governmental support for it. It is expected that the government support to renewable energy will continue until such a situation arises.

Indonesia has a great geothermal energy potential, but its exploitation lags behind expectations. Taking geothermal energy as an example, this Study considers what kind of and what extent of governmental support is necessary to promote renewable energy in Indonesia, based on the above- mentioned philosophy.

Fig.2.2-5 Diffusion of renewable energy and government support

(Source) Lund (2007), “Effectiveness of policy measures

in transforming the energy system”, Energy Policy


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2.3 Significance of Geothermal Energy < Value as energy of high supply reliability > Geothermal power generation has little output fluctuation caused by seasonal or weather conditions. Therefore it can be used around the clock throughout the year. Because of this, geothermal power generation boasts of a remarkably high capacity utilization rate, or plant factor, unlike other renewable energy sources. Therefore, geothermal power generation is characterized by its stable supply of large amounts of energy, and is a reliable power supply facility for base load demands. < Value as domestically produced energy > Geothermal energy is purely domestically produced energy. For countries which do not domestically possess fossil fuel energy resources, geothermal energy development will reduce the amount of fossil fuel importation, and for countries which export fossil fuels to other countries, geothermal energy development will reduce domestic fossil fuel consumption and will increase foreign exchange-earning fossil fuel exports. If a 55 MW geothermal power plant is built, the effect is equivalent to development of an oil field having an annual oil production of approximately 500,000 barrels, and there is no fear of depletion, since geothermal energy is renewable. 500,000 barrels of oil annually has a value equivalent to approximately USD 50 million at current oil prices, and the amount of oil saved by geothermal power plant operation for a period of 30 years is estimated to be 15 million barrels, with a value of approximately USD 1,500 million.1

< Value as stable energy > Although geothermal energy requires large amounts of up-front capital investment during the development stage, there are no fuel costs during the operating stage. Therefore, the generation cost of a geothermal plant is not affected by increases in global oil prices or the fluctuations of the exchange rate of a country’s own currency once the plant starts operation. This virtue of geothermal energy is drawing great attention at present, when global oil prices are soaring. Further, there are some developing countries whose currency values drop and oil importation prices rise, but even in such countries, geothermal power generation can also supply energy at a stable price. < Value as environmentally friendly energy > Since geothermal power plant uses steam and hot water generated naturally underground, it is a power generation system which does not have a combustion process. Therefore, air-polluting substances such as sulfur oxide, nitrogen oxide and dust are not emitted, and this energy generation is an environmentally-friendly energy source from the local

1 Crude oil price is assumed to be 100 USD/barrel.


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0 200 400 600 800 1000

Coal Thermal PP

Oil Thermal PP

LNG Single Cycle PP

LNG Combined Cycle PP

Nuclear

Hydropower

Geothemral

Solar

Windpower

CO2 Emission in Life-cycle (g-CO2/kWh)

by Fuel by Plant

CO2 Credit per Capacity (annual)

5.35.8

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1.0

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(Dairy)

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Wind Power PV

ton-

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-yr

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illion

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perspective. From the global environmental perspective, as shown in Fig.2.3-1, a geothermal power plant also emits a very small amount of carbon dioxide compared with other power sources. For this reason, there are great expectations that geothermal energy will be developed as an effective climate change control measure (Fig.2.3-2, Fig.2.3-3).

Fig.2.3-1 CO2 emissions through life cycle of various power sources (Source: Central Research Institute of Electric Power Industry Review No.45 2001 Nov)

Fig.2.3-2 CO2 credit amount per output (yearly) Fig.2.3-3 CO2 credit amount per construction cost (total through operating period)

(Source: made by Study Team) (Source: made by Study Team)

< Value as energy which can contribute to the local society > Hot water produced in a geothermal power plant can be effectively utilized as a heat source for horticulture, aqua-farming or local industry. For instance, Iceland widely uses hot


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water from geothermal power plants as a source of the district heating in major cities, and even Kenya, a country in a tropical area, utilizes hot water as a heat source to control humidity in flower cultivation greenhouses. Through these direct uses, geothermal energy effectively combines energy development and regional development. 2.4 Barriers to Geothermal Energy Development

Although geothermal energy has the above-described virtues, it is true that geothermal development is progressing more slowly than expected even in Indonesia, which is blessed with a lot of geothermal resources. Why has development of geothermal energy not progressed as expected? There are two big barriers which hinder smooth development of geothermal energy: the “development risks of underground resources” and the “burden of enormous up-front investment.” How these barriers prevent private IPP (Independent Power Producer) companies from entering this market will be described in the following sections. For convenience of explanation, the barrier constituted by the “burdens of the enormous up-front investment” will be described first. 2.5 Influence of Enormous Up-front Investment

When private companies carry out the power generation business as an IPP, they do not sell power at the cost of power generation. The companies sell power at a price which allows them to secure both a return which recovers their investment and the income tax on the business (Fig.2.5-1) 2. In this case, the return on investment depends on how much the respective IPP companies require as the expected rate of return. In other words, the selling price of power is a function of the company’s expected rate of return, the selling price of power rises as IPP companies require higher returns, and thus the function is represented by an upward-sloping curve. For geothermal power generation, development lead time from the initial survey to the start of operation is long, and the up-front investment required is extremely large in comparison to thermal power generation. For this reason, the selling price of geothermal power generation is represented by a steep upward-sloping curve relative to the expected rate of return (red bar graph in Fig.2.5-2) 3. On the other hand, the selling price of thermally generated power, which has a small amount of up-front investment and a short development lead time, is represented by a gently sloping curve (blue bar graph in Fig.2.5-2. (The graph represents an example of natural gas combined power generation.).

2 The depreciation cost portion of the power generation cost is also added to the return on investment. 3 The vertical axis in Fig.2.5-2 represents the selling price of electric power, and the horizontal axis represents the interest rate when construction costs are procured by financing. The interest rate of finance can be thought of as a cost of project funding, and, therefore, can be read as the expected rate of return of companies in IPP investment business cases.


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Fig.2.5-1 Makeup of the selling price of power Fig.2.5-2 Relationship between expected rate of return and the selling price of power

(Source: “Geothermal Sector Survey in Peru” (JBIC))

Comparison of the two bar graphs shows that:

(i) The selling price of geothermally generated power and thermally generated power are approximately the same at the expected rate of return of about 10%-12%.

(ii) The selling price of geothermally generated power exceeds that of thermally generated power in an area where the expected rate of return is larger than 15%.

(iii) The selling price of geothermally generated power falls below that of thermally generated power in an area where the expected rate of return is smaller than 10%.

In general, the expected rate of return of a government-run power company is often about 12%4. On the other hand, the expected rate of return for private IPP companies is 15% or more. Therefore, Fig.2.5-2 can be interpreted as follows.

(i) For companies which consider their expected rate of return to be about 12% (for example, a government-run power company), both geothermal power generation and thermal power generation have the same economic value.

(ii) Companies which require an expected rate of return of 15% or more (i.e. private IPP companies), consider geothermal power generation to be a high cost power source, and thermal power generation to be a low cost source. Therefore, if the other conditions are the same, private companies will move toward low cost thermal power generation and will avoid geothermal power generation.

Because of consideration (ii), if the power generation business is entrusted to private IPPs and government takes no measures, a shift to thermal power generation will occur. Fig.2.5-3 shows the composition of power sources in the mid-90s and mid-2000s of Central

4 This refers to cases of PLN and many overseas state-run electric power companies.

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American countries. Five countries – with the exception of Costa Rica - adopted policies of entrusting the power generation business to private IPPs. As a result, the share of thermal power increased. On the other hand, Costa Rica alone maintained a government-run power company system. As a result, power sources have been diversified only in Costa Rica (Fig.2.5-3, bottom center).

Fig.2.5-3 Change in sources of power generation in six Central American countries

(Source: “Geothermal Development Master Plan Study in Indonesia” (JICA))

Further, the fact that geothermal power generation is cheaper than thermal power generation in an area where the expected rate of return is lower than 10% (Cf. Fig.2.5-2) means the following.

(iii) If low-cost funds can be politically provided for construction costs of geothermal power plants (for example, low interest rate loan policies provided to IPP companies by a government-run bank, or financial assistance to government-run power companies by Yen loans), less expensive power sources than thermal power generation can be realized.

As described above, it was found that power sources which require large amounts of up-front investment for development (and this is not limited to geothermal power generation, but applies to many sources of renewable energy) cannot be expected to progress using high cost money like that of private companies. On the other hand, this means that if funding costs can be reduced through policy intervention, inexpensive power sources can be created.


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2.6 Influence of Development Risks

Because geothermal development depends on exploration of underground resources, development involves various risks. For example, development difficulties due to the geographical characteristics of the explored field easily lead to cost overruns in development. Other cost overruns may occur, depending on the success rate of exploration wells, the depth of the reservoir, the steam productivity of the reservoir, the chemical characteristics of the geothermal fluid, the amount of non-condensable gas in the steam, and so on. Additionally, even in the operating stage, performance may be reduced due to a decline in steam production and increase in the numbers of necessary make-up wells and so on. The factors determining these cost overruns cannot be predicted during the desk planning stage, and can only be found as a result of actual development. For example, Fig.2.6-1 shows the distribution of production well depths for geothermal power plants in Japan, and Fig.2.6-2 shows the distribution of average steam production volume per single production well. The depth of production wells and the average production capacity are critical values in the design of a geothermal power plant, and business profitability depends largely on these values. Both Fig.2.6-1 and Fig.2.6-2 show that these numbers are never the same for different geothermal power plant sites. Design of a geothermal power plant involves many unknown factors in addition to these values on which profitability largely depends, and the fate of a geothermal generation project depends on these factors, which become clear only after actual development is completed.

Fig.2.6-1 Distribution of production well depth of geothermal power plants in Japan

Fig.2.6-2 Distribution of productivity of geothermal power plants in Japan

(Source: ”Geothermal Development Master Plan Study in Indonesia” (JICA))

Fig.2.6-3 shows a result of one example of a Monte Carlo simulation when these various factors are changed in a model geothermal power plant to calculate the profitability of

Average Power per One Well

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investment. The figure shows that if each risk factor yields a better result than expected, profitability turns out better than expected, but conversely, if each risk factor has a worse result than expected, the expected profitability cannot be obtained. The example shows that such cases often occur.

In business management theory, risk is not a level of profitability itself, but is considered to be a fluctuating range of profitability for various potential situations. Fig.2.6-3 shows precisely that risk in the geothermal generation business is very large and, in this example, the risk (fluctuating range) ranges approximately ±4%. There is a clear difference here from the coal-fired power generation business. For coal-fired power generation, the largest risk factor is a rise in coal prices in the future. However, in the Indonesian coal-fired IPP business, even if coal prices rise during the operating period, the IPP company does not bear the rise in cost, and is allowed to add on this price rise to the selling price of power through a system called “Pass through.” Given this system, there is almost no risk involved in the coal-fired power generation business, and an IPP company can always obtain almost the same profitability as that expected in the early business planning stage. In contrast to this, uncertainty in a geothermal development project is remarkably larger. This inhibits private companies from entering geothermal development projects. Therefore, in order to promote the entry of private companies, the expected rate of return should be set high enough to cover these risks (risk premium), or some other special measures should be taken to reduce these risks (for example, implementation of underground exploration by a governmental body which can bear the risks (Fig.2.6-4). Fig.2.6-3 Example of profitability fluctuation when various factors change

Fig.2.6-4 Necessity to reduce risks (fluctuation range)

(Source: ”Geothermal Development Master Plan Study in Indonesia” (JICA))

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IPP (GEO)

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2.7 Importance of the Role of Government

As described above, geothermal development faces the two big barriers of “development risks” and “huge amounts of up-front investment cost,” which make private IPPs hesitate to participate in the geothermal power generation business. One possible measure to overcome these barriers is for PT PLN to purchase power from geothermal IPP companies at a sufficiently attractive price. However, PT PLN also has a mission to supply inexpensive power, which makes it reluctant to increase the price it pays for power. PT PLN considers power from geothermal power generation and power from coal-fired power generation to be the same power in terms of satisfying the base power demand, and offers just the same price for geothermal generation as for coal-fired generation, based on the concept of “no special treatment for geothermal energy.” Solutions to this problem are not be obtained if the problem is left only in the hands of the private IPP company and PT PLN, which is the sole electricity purchasing company, and no more geothermal development can be expected. However, it is necessary to pay attention to the fact that government can be a key player in realizing the benefits of geothermal development by private IPP. When a geothermal power plant starts operation, the society is likely to obtain several benefits (Fig.2.7-1). One of the benefits is that local fossil fuels which might be consumed in thermal power plants will be saved by geothermal power generation and can be exported to other countries. A certain portion of this export income can be diverted through taxation to the government coffers and can contribute to the government’s financial balance sheet.

Fig.2.7-1 The role of government in promoting geothermal energy development


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The benefits of geothermal power generation are not limited to the export of saved fossil fuels. As geothermal power generation is cheaper than that involving diesel plants or oil-fired plants, there is a possibility that the total fuel cost of PT. PLN will decrease through geothermal power generation. If this is the case, the government can reduce the subsidy it pays to PT PLN to make up for its financial deficit. In addition, as a geothermal power plant requires a greater amount of civil engineering work than a coal-fired power plant, the construction expenditure will also produce a great ripple effect within the domestic economy. Furthermore, the environmental value of geothermal plants will also be enormous because of their large CO2 reduction effect. Part of these social effects will return to the government. It is the mission of the government to realize these geothermal benefits and endow the society with them. Some portion of these benefits will return to the government through tax collection. The “Geothermal Development Master Plan Study in Indonesia (JICA) (JICA Master Plan Study)” reports that the selling price of geothermally generated power can be reduced if the government implements various fiscal incentives. In such a case, the government bears the fiscal incentive cost, and these fiscal incentives contribute to reducing the selling price of the geothermal power. As a result, PT PLN can lower the purchase cost. Therefore the question to be addressed here is what kind and what extent of fiscal incentive is necessary to attract private IPP companies to invest in the geothermal power generation business. This is the main theme of this study. 2.8 Various Possible Policies

Government disposes of various policy tools to promote renewable energy. One of

them is a so-called “compulsory type policy” which unilaterally imposes the cost of the promotion of renewable energy on power companies. Another is a so-called “incentive type policy” in which the government bears this cost. Finally, there is a “restriction type policy” which suppresses the use of fossil fuels. Typical compulsory type policies are the “fixed buying price system” and the “renewable energy quota system”. As an example of the former system, the “Feed-in Tariff” implemented in Germany is well-known. “RPS (Renewable Portfolio Standard)”, an example of the latter, is also well-known and has been adopted in Japan and other countries. In an incentive type policy, there are three types of incentives; tax incentives, fiscal incentives, and financial incentives. Examples of tax incentives are the Production Tax Credit system implemented in the USA, and the “renewable energy preferential tax system” adopted in many countries. As examples of fiscal incentives, there are the Geothermal Development Promotion Survey program which has been implemented in Japan and the “installation cost grant program for photovoltaic panels”, which was also implemented in Japan. As an example of financial


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CompulsoryType

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PURPA Act （USA）

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Cost payer：Electric Power Company

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incentives, there are “low-interest rate loan programs” with respect to construction costs for renewable energy projects which have been implemented in some countries. An example of a “restriction type policy” is a “carbon tax system” (Fig.2.8-1). These various policies are all applicable to the promotion of geothermal power generation by private IPP companies.

Fig.2.8-1 Various policy tools to promote renewable energy

The mechanism through which these incentives achieve effects is shown in Fig.2.8-2. The tax incentives have the effect of decreasing cash outflows of tax in the cash flow of a private geothermal IPP company. As a result, the selling price of power can be expected to be lower. The fiscal incentives such as a subsidy for the initial survey or a subsidy for the construction cost have the effect of decreasing the initial investment amount itself. The reduction of initial investment leads to a reduction of the capital cost, which then leads to a reduction of the selling price of power. The financial incentives provide for low interest rate loans. Therefore, they reduce the expected rate of return for the investment and the cash outflows of interest. As a result, the selling price of power can be reduced.

On the other hand, however, all of these incentives entail incentive costs. For example, tax incentives cost the government the partial loss of the tax income which would have been obtained without the incentive. Fiscal incentives require direct fiscal expenditures. Financial incentives require the government to bear the difference in interest rates between the market rate and the preferential rate, which can be considered to be the cost of the financial incentive. By considering these effects and the costs of each incentive, this study considers the most effective incentives to promote the private geothermal IPP business in Indonesia.


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OthersO&M Cost


Tax incentives

Finance incentives

Fiscal incentives

Finance incentives

Fig.2.8-2 Mechanism through which each incentive policy works on the selling price of power

2.9 Methodology of the Study < Study of short-term incentive options (Phase-I) > In this study, “short-term” is defined as the period up to 2016. This time range is set in consideration of the fact that geothermal development requires a long lead time in exploration, development and construction. In particular, the main target in this study is the IPP investment business of a private company. According to the Indonesian geothermal law, any private company which plans to participate in geothermal development activities should obtain the right to development through the bidding process which is carried out by the Ministry of Energy and Mineral Resources for each designated geothermal development area (Work Area). At present, the establishment of the geothermal development areas and the bidding for them only started in 2008, and only a little work has been completed so far. Accordingly, even if these development procedures improve in the future, it is thought that much time will be required. In addition, the geothermal development areas which were established in this manner have rarely been surveyed up to now, and are so-called “Green Fields.” In order to develop such “Green Field” areas, long lead times as described above are required. According to the JICA Master Plan Study, the amount of power developable by 2016 is presumed to be approximately 3,300 MW under the shortest lead time scenario (the development target by 2016 is set at 4,600 MW by the “Geothermal Development Road Map” of the Ministry of Energy and Mineral Resources)(Fig.2.9-1). Therefore, in this study, the range of “short-term” is considered to be the period up to 2016. As for the study method, the Study Team uses a profitability simulation program developed by West JEC for the simulation of various power generation businesses. After adding the necessary modifications to this program, the profitability simulation of benchmark coal–fired power generation and of the geothermal power generation are carried out (that is, the calculation of the profit and loss statement and the cash flow statement are carried out.) Through these profitability simulations, the selling price of power is calculated as the price at which the


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Fastest Case

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obtained profitability exceeds the Financial Internal Rate of Return (FIRR) required by investors.

Fig.2.9-1 Prospect of geothermal development output capacity (Source: “Geothermal Development Master Plan Study in Indonesia” (JICA))

In order to study the necessary incentives, various incentive parameters are input into the above-mentioned profitability simulation program to calculate the selling price. Each incentive will reduce the selling price of power, and thus the effect of the incentive is simulated. At the same time, the cost of each incentive is also calculated. Through these calculations, the Study Team tries to determine the incentives which are necessary to attract private companies to participate in geothermal development in the short–term range. The study is carried out on the following items according to the above principles. (1.1) Study of PT PLN purchase price in benchmark case (1.2) Study of model investment case for geothermal power generation business (1.3) Study of geothermal power generation effects (1.4) Study of promotion incentives (1.5) Study of impact of promotion incentives (1.6) Proposal of promotion incentives The flow of the study of short-term incentive options is as shown in Fig.2.9-2. < Study of mid-term and long-term incentive options (Phase-II) >

In this study “mid-term” and “long-term” are defined as 2017-2025. In the study of mid-term and long-term incentives, the goal is to achieve an energy mix in 2025 set up by the


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Indonesian government. More specifically, the goal is to achieve 9,500 MW of geothermal power generation.5 As for the study method, the same profitability simulation program used in the Phase-I study is used. Similarly to the Phase-I study, incentives to achieve the desired energy mix in 2025 are studied and their impact is also evaluated. Differences between the short-term case and the mid-term and long-term cases arise from factors such as the effects of technical innovation on construction costs, on improvement of power generation efficiency, and on the improvement of technical risk control. On the other hand, negative effects are also found in the factors relating to a rise in coal prices, and an increase in the marginal development cost of geothermal resources, etc. The power generation profitability simulations take these factors into account, In the study of incentives, the range of policies is to be expanded to include the restrictive type policies such as adoption of a carbon tax system. The mid-term and long-term incentive options which are financially neutral are studied based on these considerations.

5 According to the “Geothermal Development Road Map” of the Ministry of Energy and Mineral Resources, and the “Geothermal

Development Master Plan Study in Indonesia (JICA)”.


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Benchmark

Phase - I Study of short-term incentives

＜Requirement of TOR＞ To study short-term incentives to promote geothermal development by private companies.＜Requirement methodology＞ To study necessary incentives by comparing profitability of geothermal power generation business by private company with profitabilityof benchmark coal-fired power generation business.

＜Basic study policy＞Short term： Up to 2016 by considering geothermal development lead time.Method： By simulating profitability of a model investment case.Incentives：To study necessary incentives first, and to evaluate its cost andimpact next.

80% buyout policyCoal power plant

Calculation of selling price in benchmark case

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Evaluation of benefits and costs of Gov't and PLN

Proposal of incentives

Incentives 1（Ex.）　Feed in tariff (FIT)

Incentives 2（Ex.）　Tax incentives + FIT

Incentives 3（Ex.）　Fiscal incentives + FIT

Incentives 4（Ex.）　Financial incentives + FIT

Fig.2.9-2 Study flow of short-term incentive options (Phase-I)


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＜Requirement of TOR＞ To study mid- and long-term incentives which is neutral in government fiscal income and expenditure balance and enables to attain energymix target in 2025.＜Requirement of method＞To study necessary mid- and long-term incentives based on a long-term cost simulation of coal-fired plant and geothermal plant.

Long term benchmark

Phase - II Study of mid- and long-term incentives

＜Basic study policy＞Long-term：Up to 2025 and to attain energy mix.Method：By modifying short term model.Incentives： To study necessary incentives to attain both energy mix of 2025 and fiscally neutralposition.

Coal power plant

Calculation of long-term benchmark selling price

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GapPurchase price of

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Study of incentives To study necessary incentives to bridge the price gap

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Impact eveluation To eveluate impact of incentives

Study of PLN cost Study of government cost

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Evaluation of geothermal energy value To calculate benefits of geothermal energy development

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GovernmentPLN

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Proposal of promotion incentives To propose appropriate and fiscally neutral incentives to promote geothermal development by privatecompanies.

Evaluation of benefits and costs of Gov't and PLN

Proposal of incentives

Cost reduction by technologyinnovation,

Fuel price increase, etc

Cost reduction by technologyinnovation

Marginal development costincrease　etc.

Carbon tax

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Effect

Cost

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Incentives 2 （Ex.）　Utilization of CDM scheme

Incentives 3 （Ex.）　Carbon tax etc.

Fig.2.9-3 Study flow of mid-term and long-term incentive options (Phase-II)


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The following items are studied according to the above principles. (2.1) Study of PT PLN purchase price in mid-term and long-term benchmark case (2.2) Study of model investment case of mid-term and long-term geothermal power generation businesses (2.3) Study of mid-term and long-term geothermal development effects (2.4) Study of mid-term and long-term promotion incentives (2.5) Study of impact of mid-term and long-term incentives (2.6) Proposal of mid-term and long-term incentives Study flow of mid-term and long-term incentive options is as shown in Fig.2.9-3. (Underlined parts constitute the main differences from Phase-I.) 2.10 Assumptions of the Study

The following assumptions concerning the economic environment and energy prices

are used in this study. < Exchange rate >

Exchange rates are; 1 USD = 10,000 IDR = 100 JPY. < Interest rate >

The foreign currency interest rate is assumed to be 6.5% based on the “Arrangement on Officially Supported Export Credits” of OECD. This interest rate includes a country risk of about 2%. The local currency interest rate is assumed to be 13.0% based on recent interest rates in Indonesia. < Inflation >

Consumer Price Index (CPI) of Indonesia has been between 6% and 12% in recent years. The prices in this study, however, are treated as invariant and are the prices current in 2009. < Price of fuel >

The International Energy Agency (IEA) forecasts the future oil price in real terms as 100 USD/barrel in 2010, 100 USD/barrel in 2015, 110 USD/barrel in 2020, and 116 USD/barrel in 2025 in its latest “World Energy Outlook 2008". The future natural gas price in the Asian area is forecast as 12.7 USD/MMBTU in 2010, 13.16 USD/MMBTU in 2015, 14.52 USD/MMBTU in 2020, and 15.28 USD/MMBTU in 2025, as the LNG price for Japan. The future coal price is forecast as 120 USD/ton in 2010, 120 USD/ton in 2015, 116.67 USD/ton in 2020, and 113.33 USD/ton in 2025 (for 6,000 kcal/kg coal). (Table 2.10-2).


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Item Unit 2000 2007 2010 2015 2020 2025 2030Real term base Crude Oil barrel 33.33 69.33 100.00 100.00 110.00 116.00 122.00 Natural gas MMBTU 5.63 7.80 12.70 13.16 14.52 15.28 16.05 Coal ton 40.06 72.84 120.00 120.00 116.67 113.33 110.00nominal term base Crude Oil barrel 28.00 69.33 107.34 120.27 148.23 175.13 206.37 Natural gas MMBTU 4.73 7.80 13.63 15.83 19.56 23.08 27.16 Coal ton 33.65 72.84 128.81 144.32 157.21 171.11 186.07(Note) 1. natural gas price is Japan LNG price. 2. Coal price is 6,000 kcal/kg base.(Source) IEA "World Energy Outlook 2008"

On the other hand, in its latest Electric Power Development Plan (RUPTL 2009-2018) PT PLN assumes that future fuel prices until 2018 will be: coal 90 USD/ton (5,300kcal/kg base), diesel fuel oil (HSD) 140USD/Barrel, industrial oil (MFO) 110USD/Barrel, and natural gas 6 USD/MMBTU. (Table 2.10-3).

In this study the following future fuel prices are used based on the above estimates: oil

100 USD/Barrel, coal 90 USD/ton (5,300 kcal/kg base), diesel fuel oil (HSD) 140 USD/Barrel, industrial oil (MFO) 110 USD/Barrel, domestic natural gas 6 USD/MMBTU and LNG 13 USD/MMBTU by the year 2016. (Table 2.10-4). To simplify the analysis, these prices are assumed to be constant until 2025. When crude oil prices change, other fuel prices are assumed to change proportionally as shown in Table 2.10-4.

Table 2.10-1 Assumptions of this study Exchange rate ： 1 USD = 10,000 IDR = 100 JPY Interest rate ：

USD base 6.5 % ( OECD Credit Arrangement) (as of October 15, 2008) IDR base 13.0 % Price ： Real term base （at 2009 price ）

Table 2.10-2 Future fuel price forecast by IEA


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Item Unit US$ Coal ton 90 HSD barrel 140 MFO barrel 110 Gas MMBTU 6 LNG MMBTU 10(Source) "RUPTL 2009-2018, PT.PLN

Item Unit BaseReal term base Crude Oil barrel 100 60 70 80 90 100 110 120 130 140 Coal ton 90 54 63 72 81 90 99 108 117 126 HSD barrel 140 84 98 112 126 140 154 168 182 196 MFO barrel 110 66 77 88 99 110 121 132 143 154 Natural gas MMBTU 6 3.6 4.2 4.8 5.4 6.0 6.6 7.2 7.8 8.4 LNG MMBTU 13 7.8 9.1 10.4 11.7 13.0 14.3 15.6 16.9 18.2(Note) Coal price is 5,300 kcal/kg base.

Oil Price Change Case

Table 2.10-3 Future fuel price forecast in RUPTL 2009-2018 of PT PLN

Table 2.10-4 Future fuel prices used in this study

CHAPTER 3

PRESENT STATUS OF GEOTHERMAL

POWER DEVELOPMENT IN INDONESIA


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CHAPTER 3 PRESENT STATUS OF GEOTHERMAL POWER DEVELOPMENT IN INDONESIA

3.1 Geothermal Power Potential in Indonesia

Indonesia may have the largest geothermal resource capacity in the world, with the about forty (40) percent (equivalent to approximately 27,000 MW) of the world’s geothermal resources concentrated in Indonesia. (Table 3.1-1)

The development of geothermal power has been strongly expected to meet the increasing electric power demand as a substitute for fossil fuel power generation. Geothermal power generation has been conducted in seven (7) fields, namely Kamojang, Darajat, Wayang-Windu, Salak in western Java, Dieng in central Java, Sibayak in north Sumatra, and Lahendong in north Sulawesi. The generation capacity has reached 1,196MW (Table 3.1-2). Although Indonesia is the fourth largest producer of geothermal power in the world, it is far from exploiting this huge potential of geothermal energy as well as possible.

The Ministry of Energy and Mineral Resources (MEMR) formulated a Geothermal Development Road Map to develop 9,500 MW in total by 2025. The Road Map was prepared on the basis of resource study results from PERTAMINA, PLN, government institutes and private development companies. However, development plans for geothermal power plants have only been prepared for plants initiated by 2016. In the JICA Master Plan Study, the resource potential was evaluated and development plans for geothermal power plants were studied. The feasibility and priority of each development were studied technically, economically and environmentally, considering power demand in the future. The Master Plan Study was formulated using these results. References to geothermal resources in Indonesia in this chapter are based on that study,.

In the Master Plan Study, a capacity of 9,076 MW for 50 geothermal fields was estimated using existing data (Fig.3.1-1). However, since more than 50 promising fields exist in Indonesia, geothermal resources greater than 14,000 MW are believed to exist in Indonesia. These resources are enough to realize the goal of the Geothermal Development Road Map of 9,500 ＭＷ by 2025.

The geothermal resources exist in Sumatra, Java, Sulawesi, East and West NTT, Northern Muluk and Muluk. They are expected to be the primary power sources in each area. Their potential can be summarized as follows. (1) Sumatra

Major promising geothermal fields; Iboih-Jaboi, Seulawah Agam (Aceh), Lau


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Debuk-Debuk/Sibayak, Sarulla, Sibual Buali, S. Merapi-Sampuraga (North Sumatra), Muaralabuh (West Sumatra), Lempur/Kerinci, Sungai Penuh (Jambi), B. Gedung Hulu Lais (Bengkulu), Tambang Sawah (Bengkulu), Marga Bayur, Lumut Balai (South Sumatra), Ulubelu, Suoh Antatai, G. Sekincau, Rajabasa, Wai Ratai (Lampung)

Sumatra is the richest island in geothermal resources in Indonesia. However, geothermal developments in Sumatra are less advanced than those in Java. Construction and operation of the small geothermal power plant in Sibayak was started in October 2000. However, the full geothermal power resource has not been exploited to date. Since the reservoir in the Sibayak field seems to lie at a relatively shallow depth and its temperature is high, the reservoir potential is estimated to be 170 MW by PERTAMINA. This capacity is sufficient to allow construction of larger power plants in this field. Considering future power demand in northern Sumatra, additional geothermal power development in this field is strongly expected.

The next developed geothermal field in Sumatra is Sarulla. A feasibility study for a geothermal power plant was completed, and the characteristics, structure and potential of the geothermal resources in this field were revealed. The study results from deep geothermal wells drilled in the 1990s show that power generation of 330 MW for 30 years could be carried out. Although the IPP companies plan geothermal power plants in this field, it is reported that the project profitability needs to be improved before construction.

Ulubelu, Lumut Balai, and B. Gedung Hulu Lais are deemed to be other major power sources for the southern Sumatra grid. In Ulubelu, exploratory wells have been drilled by PERTAMINA Geothermal Energy (PT PGE) to clarify the characteristics and capacity of geothermal resources. Also a preparatory study for a power plant using a Japanese ODA Loan is being conducted by PT PLN. PT PGE is conducting geothermal power development in Lumut Balai and B. Gedung Hulu Lais, too.

Eight other geothermal fields (Muaralabuh, Sungai Penuh, Tambang Sawah, Rajabasa, Suoh Antatai, G. Sekincau, and Wai Ratai) are given top priority in the Master Plan Study. The reservoirs of these fields show the preferred chemical and physical characteristics of deep geothermal fluid. Promotion of development of these fields as power sources for the Sumatra system can be recommended. In addition to these fields, geothermal resources in Seulawah Agam and S. Merapi-Sampuraga seem promising, because of the high temperature estimated by geoscientific study. These resources may have a huge potential (640-900 MW). However, there are still resource development risks due to shortage of data concerning these fields. Two other fields (Iboih-Jaboi and Marga Bayur) were assigned to the 2nd rank of development possibility in the Master Plan Study. Resource confirmation studies including exploratory wells are necessary to promote these fields.


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The capacity of geothermal resources in Sumatra is regarded larger than 7,500 MW. Many geothermal fields in Sumatra have large capacities (larger than 100 MW). Development of these fields will supply stable power to the north, the central and the south Sumatra electricity systems. (2) Java-Bali

Major promising geothermal fields: Kamojang, G. Salak, Darajat, Cisolok-Cisukarame, G. Patuha, G. Wayang-Windu, G. Karaha, G. Telagabodas (West Java), Dieng, Ungaran (Central Jawa), Wilis-Ngebel (East Java), Bedugul (Bali)

In Java and Bali islands, there are many promising geothermal fields adequate for power plants. The Kamojang, Salak, Darajat, Wayang Windu and Dieng fields have been developed and power plants are operating. The potential of these fields estimated in the Master Plant Study is larger than the present and planned capacity. There is a lot of reliable data for these fields, and the power plants expansion plan is expected to contribute additional power to the Java-Bali system. In Kamojang a new power plant of 60 MW was started recently in addition to the existing 140 MW (Kamojang IV) plant. The 60 MW power plant in Dieng has been in operation since 1998 and additional plants (240 MW) are planned in the Geothermal Development Road Map by 2025.

A high potential is expected for the geothermal resources in Patuha, G. Karaha, G. Telagabodas and Bedugul fields. High temperatures (245-285oC) of the reservoirs have been measured and estimated, and significant reservoirs (200-600MW) have been inferred in integrated geoscientific studies. Due to lack of test well drillings in G. Karaha, power plant construction has not proceeded so far. Cisolok-Cisukarame, Ungaran and Wilis-Ngebel should be studied for development, because the potentials and fluid characteristics of the resources in these fields seem to be adequate. Available geoscientific data for a feasibility study is not sufficient to identify resource existence and to evaluate capacity. A resource study and development programs should be prepared for these fields. Geothermal resources evaluated in the Master Plan Study are relatively large, and the development of these fields will contribute to the power supply in the Java-Bali system and activate local industries.

Geothermal capacity in Java-Bali is evaluated to be larger than 4,500 MW in the Master Plan Study. Since the promising fields in Java-Bali have a considerably large capacity, geothermal power will be a major power source for the Java-Bali system. (3) Sulawesi and East Indonesia

Major promising geothermal fields; Hu’u Daha (West Nusa Tenggara), Wai Sano, Ulumbu, Bena-Mataloko, Sokoria-Mutubusa, Oka-Larantuka, Atadei (East Nusa Tenggara), Lahendong, Kotamobagu, Tompaso (North Sulawesi), Tulehu (Maluku), Jailolo (North


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Maluku)

As the most promising fields in this region, Lahendong, Tompaso and Kotamobagu in Sulawesi and Ulumbu, and Bena-Mataloko and Sokoria-Mutubusa in Flores were pointed out in the Master Plan Study.

Of these fields, Lahendong has been under development by PERTAMINA since 1984. The commercial operation of Unit I (20 MW) began in August 2002. After the first unit, Units II and III (each 20 MW) were constructed by PT PLN. A generating capacity of 80 MW in this field has been evaluated in a well drilling study conducted by PERTAMINA. A resource potential of 175 MW is reported in the Master Plan Study in consideration of geothermal resources in the surrounding areas. Further expansion is probably feasible in and around Lahendong. The two other fields in North Sulawesi, Tompaso and Kotamobagu, are believed from surface geoscientific data to have a remarkably large capacity (240-460 MW). However, since there are resource development risks, detailed surface studies and exploratory well drilling are necessary.

In the Island of Flores, exploration wells confirmed resources in Ulumbu and Bena-Mataloko. In addition, a magneto-telluric survey was done in Sokoria-Mutubusa. The resource development risks in these fields are estimated to be not so large. Development is expected to provide power for rural electrification. Not only a feasibility study of resource development but also a feasibility study for transmission/distribution (T/D) lines is required for a rural electrification plan. The other six fields, Hu’u Daha, Wai Sano, Oka-Larantuka, Atadei, Tulehu and Jailolo, are worth studying for power development to replace the existing diesel power facilities with geothermal power facilities. In spite of the shortage of field survey data, surface manifestations reveal the possibility of resource existence. Resource confirmation study should be conducted to mitigate resource development risks.

Geothermal resource potential in Sulawesi-East Indonesia is regarded as larger than 2,000 MW. Although many geothermal fields in this region have sufficient resource potential, small to medium scale power development (5 to 30 MW) can be recommended in consideration of local electricity demand.


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Speculative Hypothetic Possible Probable ProvenSumatra 5,705 2,433 5,419 15 499 2Java-Bali 2,300 1,611 3,088 603 1,727 835Nusa Tenggara 150 438 631 - 14 -Sulawesi 1,000 125 632 110 65 20Maluku/Irian 325 117 142 - - -Kalimantan 50 - - - - -

9,530 4,714 9,912 728 2,305

251Location

Total

Total 27,18914,244 12,945

857

LocationInstalledCapacity

Resources (MWe) Reserve(MWe)

Table 3.1-1 Indonesia geothermal potential

（Source："Current State of Geothermal Development in Indonesia", Dr. Dwipa SJAFRA, 2004）

(Source: “Geothermal Development Master Plan Study in Indonesia”, JICA, 2007)

Fig.3.1-1 Major geothermal resources in Indonesia


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Table3.1-2 Geothermal power plants in Indonesia and their development scheme

3.2 Status of Recent Geothermal Development Policy (1) Regulatory framework for promotion of geothermal power development

Under the Indonesian constitutional framework, Indonesia's geothermal resources are controlled by the state. Initially, the state owned company - PERTAMINA - was the sole

Power Plant Location Unit MW Turbine

Maker Operat

ion Steam Supply Power Generation

#1 2 Unknown 1996 PERTAMINA #2 5 Unknown 2007 PERTAMINA Sibayak North

Sumatra #3 5 Unknown 2007 PERTAMINA

#1 60 ANSALDO 1994

#2 60 ANSALDO 1994

#3 60 ANSALDO 1994 #4 65.6 Fuji 1997

#5 65.6 Fuji 1997

Salak West Java

#6 65.6 Fuji 1997

Chevron Geothermal Indonesia

#1 110 Fuji 2000 Wayang- Windu West Java

#2 117 Fuji 2009 PERTAMINA / Mandala

Nusantara Ltd

#1 30 MHI 1983 #2 55 MHI 1988 #3 55 MHI 1988

PERTAMINA PLN Kamojang West Java

#4 60 Fuji 2008 PERTAMINA

#1 57.8 MHI 1994 Chevron

Geothermal Indonesia

PLN

#2 90 MHI 2000 Darajat West Java

#3 110 MHI 2007 PT. Chevron Geothermal

Indonesia

Dieng Central Java #1 60 ANSALDO 1999 Geodipa Energi

#1 20 ALSTOM 2001 PERTAMINA PLN #2 20 Fuji 2007 PERTAMINA PLN Lahendong North

Sulawesi #3 20 Fuji 2009 PERTAMINA PLN

Total 1,196.1 MW


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enterprise with responsibility for exploring and exploiting the nation's geothermal resources, including the generation of electricity powered by geothermal energy. PERTAMINA may use contractors pursuant to a joint operation contract, and may sell either the geothermal steam or the electricity produced to the state electricity company – PLN - or other parties.

In 2000, however, as a result of a program of rationalization in the geothermal power generation sector and the introduction of expanded regional autonomy, PERTAMINA's monopoly in geothermal resources was revoked. Following the introduction of this new policy, PERTAMINA transferred to the Minister of Energy and Mineral Resources, through the Director General of Geology and Mineral Resources (DGGMR), all governmental functions and returned the authority to develop geothermal resources and Work Areas.

A new Geothermal Law was enacted on October 22, 2003 in order to provide a stronger legal basis for upstream geothermal energy developments, including private investment in the sector. Prior to the law's enactment, the legal framework for geothermal undertakings was provided by a series of presidential decrees. The new Geothermal Law is also intended to accommodate expanded regional autonomy in Indonesia. Within their respective jurisdictions, provincial and local governments are given the authority to regulate, supervise and license geothermal energy developments.

The following provides an overview of regulatory frameworks, including the new

Geothermal Law and the Presidential Decrees that have played an important role in the progress of geothermal development to date.

< Presidential Decrees > In order to accelerate its development and to attract private sector investment,

geothermal development was initially undertaken under a regulatory framework in the form of Presidential Decrees (PD), beginning with Presidential Decree No. 22 in 1981 (PD 22/1981). PD 22 authorized PERTAMINA to undertake exploration and exploitation of geothermal energy resources in Indonesia and to generate and sell electricity to PT PLN and to other bodies such as the Government or private companies (including cooperatives). The PD institutionalized the Joint Operating scheme between PERTAMINA and interested field developers. A Joint Operation Contract (JOC) is awarded through negotiation with a domestic or foreign company which must be technically and financially capable of undertaking the operations.

In 1991, PD 22/1981 was replaced by Presidential Decree No. 45 of 1991. PD 45/1991 outlines two alternative paths for geothermal energy development in Indonesia. Under the first, PERTAMINA and its joint operation contractors develop and operate the steam field only, selling the steam to PT PLN or other parties for electricity generation. The second alternative allows PERTAMINA or its contractors to generate electricity as well as develop and


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operate the steam field, with the electricity produced sold to either PT PLN or other consumers. This was later followed by PD 49 of 1991, concerning the taxation of PERTAMINA and its contractor in the Joint Operating Contract. Subsequently, on 13 July 1992 the Minister of Finance (MOF) issued an implementation regulation, Ministry of Finance Decision No. 766/KMK.04/1992 (MOFD 766/1992), regarding the applicability of income tax, value added tax (VAT) and other levies imposed on the utilization of geothermal resources to generate electricity. Specifically MOFD 766/1992 outlines the procedure to be followed in the computation of the government’s share, income tax, VAT and other levies.

MOFD 766/1992 stated that a 34% tax rate is applicable to the Net Operating Income or Taxable Income, which shall be computed in accordance with Article 4 of the 1984 Income Tax Law after deducting the costs for acquisition and maintaining revenue pursuant to Article 6 of the Income Tax Law, excluding the VAT, Sales Tax on Luxury items, Land and Building Tax, duties and other levies. Under MOFD 766/1992, the VAT and other taxes will be reimbursed by the Government. Also, under a JOC, PERTAMINA is entitled to receive 4% of the net operating income, leaving the Contractor with a net profit after tax of 62% of the net operating revenue after cost.

On April 4, 1998, the Ministry of Finance issued the implementation regulation MOFD 209/KMK.04/1998, which revised some provisions of MOFD 766/1992, specifically concerning the payment of and procedures for the reimbursement. Under MOFD 209/1998 the Government will reimburse the VAT that has been paid only after the Contractor has paid the Government portion under the JOC, and the amount shall not exceed the amount that has been paid.

These Presidential Decrees have been received well by investors, as can be seen from the fact that the Joint Operation Contractors of PERTAMINA have added 400 MW to geothermal generation capacity between 1982 and 1997 and another 650 MW between 2000 and 2008. A total of USD 1.4 billion had been invested in the 11 projects before the 1997 monetary crisis. The foreign companies that are or have been involved in geothermal development projects in Indonesia include Unocal, Amoseas (a wholly owned subsidiary of Chevron Texaco), Mid-American (formerly California Energy), Magma Power Co. (Magma Nusantara), Caithness and Florida Power & Light.

In the 20 years since its inception, PT PLN has signed 11 geothermal power sales contracts with a total capacity of 3,417 MW, but only four have moved forward, and all of these are located in Java. These four projects are Darajat (West Java), Salak (West Java), Dieng (Central Java) and Wayang Windu (West Java). The other planned projects were previously expected to come on stream between 1998 and 2002. Two of the contracts, however, ended with arbitration, while the remaining were suspended after 1998, and restructured in accordance


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with Presidential Decree No. 133 of 2000 through a process of negotiation.

Furthermore, in 2000 the attractive incentive decrees of the mid-1990s were replaced by Presidential Decree No. 76. Under PD 76/2000, the GOI proposed to undertake all or part of the exploration activities. Tax payments, however, were to be in accordance with general tax law rates, i.e., 47% instead of the 34% under the previous PDs. No exploration activities have taken place since the enactment of PD 76/2000, and since the enactment, the geothermal industry has been supporting the development of a geothermal law which would more permanently fix the conditions of taxation, regional authorities, and exploration-risk sharing.

Under PD No.76 of 2000 on geothermal exploration for electric generating purposes, the government bears the risk of exploration failure when such exploration does not result in a well of sufficient potential. Early in Abdurrahman Wahid’s administration, the government decided to completely revise the existing PDs, separately from enactment of a new geothermal law, with the primary objective of liberalizing the geothermal sector and removing PERTAMINA’s absolute authority. In late 2001, a new law, Oil and Gas Law No. 22 of 2001, was promulgated replacing Oil and Gas Law No. 44 of 1960, which also regulated the geothermal sector. Law 22/2001 removes geothermal development from the jurisdiction of oil and gas regulation, creating a gap as far as regulation of geothermal investment is concerned, a situation that prompted Parliament to call on the government to develop a geothermal regulatory law.

< Joint Operation Contract (JOC) > The JOC governs the contractor’s relationship with PERTAMINA. Under the scheme,

PERTAMINA, representing the Government, is responsible for the management of the operation and the contractor is responsible for the production of geothermal energy from the contract area, the conversion of energy to electricity and the delivery of geothermal energy or electricity. The following lists the salient points of the JOC.

The JOC allows operations for 42 years. It applies to one or more generating units, with the production period for each generating unit under the JOC being 30 years, beginning on the date of first commercial generation for the unit.

During the term of a JOC, the existing field facilities and any new field facilities will be owned by PERTAMINA. The Power Stations will be the property of the contractor, and will be sold to PERTAMINA on an “as is” basis at the termination of the JOC, at an agreed-upon price, provided the contractor receives all payments owed under the JOC and ESC (Energy Sales Contract).


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Under the terms of a JOC, PERTAMINA is responsible for managing the field operation, although the Contractor is solely responsible for the conduct of geothermal operations. PERTAMINA retains title over all the operating and geological data, as well as a right to observe operations or to inspect financial and technical records. PERTAMINA will receive a monthly production allowance from the Contractor equal to 4% of Net Operating Income, which is tax-deductible.

The Contractor is permitted to conduct geothermal operations in the Contract Area, to enter into agreements with sub-Contractors and technical or professional service providers.

Certain tax provisions and exemptions apply to the Contractor, including capping the Contractor’s income tax rate at 34% and exemption from import duties, value added taxes, sales taxes and other levies on the importation of project-related equipment, provided that such items are not made in Indonesia on a reasonably competitive basis. If the income tax rate is increased for any reason, the price payable under the ESC will be adjusted so that Contractor’s economic rate of return is not changed.

The depreciation schedule for capital assets will use the declining balance method,

pursuant to Article 11 of the 1983 Tax Law and MOF Decision No. 457/1984.

< Energy Sales Contract > An ESC, an integral part of the JOC, is an agreement among the contractor and

supplier of geothermal steam, PERTAMINA (PERTAMINA and Contractor) as the seller, and PT PLN as the purchaser of geothermal energy. The following lists the salient points of the contract. ① The Energy Sales Contract (ESC) is executed on the same day as the JOC with PT PLN,

PERTAMINA and the Contractor being the parties to the agreement. ② Under the ESC, PT PLN is obligated to purchase electricity up to an agreed maximum

aggregate generating capacity, or the Contractor has the right to deliver electricity generated in the Contract Area to PT PLN on behalf of PERTAMINA.

③ PT PLN is required to purchase the Net Electrical Output (and the Curtailed Delivery Output, if applicable) plus make a payment for the Unit Rated Capacity, for each Unit in the Contract Area from the Date of First Operation until the Date of Commercial Generation. PT PLN’s obligation to pay the Unit Rated Capacity is subject to the Unit’s availability to operate, with exceptions in the case of scheduled maintenance.

④ The electricity tariff is denominated in US currency and is made up of either a single tariff or two components. When there are two components, they are as follows:

A base electricity price per kWh, adjusted by the US Consumer Price Index.


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A capacity payment based on the Unit Rated Capacity per kilowatt-year as set out below:

For year 1 – 14 : Full For year 15 – 23 : Reduced to 50% Thereafter : Reduced to 25%

< Support Letters > To provide security for lenders, the Contractor may receive Support Letters issued by

the Government of Republic of Indonesia. Under the first MOF Support Letter, the Government guarantees that PT PLN, its successors and assignees, will discharge PT PLN’s payment obligations as due and payable and unsatisfied by PT PLN. The second Support Letter is issued by the Ministry of Energy and Mineral Resources and states that the Government will ensure that PERTAMINA, its successors and assignees, will continue to perform its obligations under the terms and conditions set out in the JOC. Both Support Letters call for any dispute or claim arising out of or relating to the letters to be settled by arbitration under UNCITRAL Arbitration Rules with the procedural provisions set forth in the ESC and the JOC.

< Geothermal Law (Law No. 27/2003) > In 2003 a new geothermal law (Law No. 27/2003) was enacted, stipulating that

geothermal undertakings can be carried out either as a total-project including electricity generation as well as development and operation of the steam field or can be limited to cover only the upstream operation. The following lists the salient points of the new Geothermal Law: ① PERTAMINA will transfer to the Minister of Energy and Mineral Resources, through the

Director General of Geology and Mineral Resources, all governmental functions and will return the authority to develop geothermal resources.

② Regulation of geothermal undertakings will be carried out by the Government and the Regional Governments. The authority of the central, provincial and regency/city governments includes: A) Producing legal regulations in the geothermal energy mining sector (for provincial and

regency governments this concerns local regulations under their respective authorities);

B) Setting national policy (regional: local); C) Management and supervision of geothermal resource undertakings across provincial

boundaries (for provincial governments if the field is located in two or more regencies);

D) Granting permits for and supervision of geothermal undertakings across provincial boundaries;

E) Managing information on the geology and geothermal resource potential of areas; F) Taking inventory of geothermal resources and reserves.


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③ The authority of the provinces and regencies shall be executed in accordance with the provisions of the applicable laws and regulations and their respective authorities. For example, in granting permits for and supervising geothermal undertakings, the Provincial Government will become involved if the geothermal field is within the province but extends to two or more regencies.

④ The Minister, Governors, or Regents/Mayors, in accordance with their respective authorities, shall make offers of Work Areas through tender. The boundaries of a Work Area shall be determined by the Government. Provisions regarding guidelines, boundaries, coordinates, procedures, and other requirements regarding offers, procedures, and preparation of tender documents, and implementation of tenders will be regulated by the government.

⑤ Geothermal activities will include five phases: preliminary surveys, exploration, feasibility study, exploitation and utilization (direct and indirect). Preliminary surveys will be conducted by the Government and if necessary the Government may assign a party to conduct the survey, which will obtain a right to match the area is offered for tender. Exploration, feasibility study and exploitation will be conducted by a non-governmental party, but the Government may also conduct the exploration phase.

⑥ Direct Use in connection with the utilization of Geothermal Energy shall be regulated through government regulations. Indirect use related to the utilization of Geothermal Energy for electric power generation, for the public interest or for private interests, shall be done in accordance with the provisions of the applicable laws and regulations in the electric power industry sector.

⑦ The geothermal undertaking will be based on the business permit (Izin Usaha Pertambangan or IUP) issued by the government and covering three types of activities, namely indirect utilization, direct utilization and production of associated minerals. For example, those who have a business permit to explore and develop geothermal energy and to generate electricity will not be required to solicit another permit to sell the geothermal energy for other purposes. Byproduct minerals contained within geothermal fluid may be utilized commercially by an IUP holder or another party, in accordance with the provisions of the applicable laws and regulations.

⑧ The IUP allows: A) Exploration period, for a maximum of three (3) years from the date of issue of the IUP,

which may be extended a maximum of two (2) times, for one (1) year each time; B) Feasibility Study period, for a maximum of two (2) years from the end of the

Exploration period; C) Exploitation period, for a maximum of thirty (30) years from the end of the

exploration period, which may be extended. This can be extended on request at the earliest five years or at the latest three years prior to expiration of the exploitation phase. The law does not specify the maximum term for an extension.

D) The IUP may be issued either by the Minister of Energy and Mineral Resources or by


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the respective governor, mayor or regent (depending on the location of the working area).

⑨ The IUP may be revoked if the holder of the IUP violates one of the requirements stated in the IUP or fails to fulfill the requirements stated in the law. Prior to termination, the holder of an IUP shall be given opportunity for six (6) months to fulfill the specific requirements.

⑩ Invitations to bid for a new working area, the tender process itself, and ultimately the designation of a winning bidder, will be carried out by the minister or the respective governor, mayor or regent. Working areas for the exploration phase may not exceed 200,000 hectares and will be subject to a relinquishment program. For exploitation, the area is limited to 10,000 hectares.

⑪ The authorizations provided by the integrated business permit deal only with use of geothermal resources. Use of the surface area of privately held land must be obtained by the permit holder itself on the basis of a a negotiated consensus with the landowner.

⑫ The holders of an IUP are obliged to pay state levies in the form of taxes and also non-tax state levies in accordance with the provisions of the prevailing laws and regulations. The state levies shall consist of: A) Taxes; B) Import duties, other levies on imports, and excise duties; C) Regional taxes and regional levies; D) The non-tax state levies shall be stipulated through government regulation and consist

of: E) State levies in the form of Fixed Fees and Production Fees, and other state levies in

accordance with the provisions of the prevailing laws and regulations; F) Bonuses.

⑬ State revenues representing the revenues of the Central and Regional Governments shall be shared as follows: A) For state revenues in the form of taxes, the sharing shall be determined in accordance

with the provisions of the applicable taxation laws and regulations; B) For non-tax state revenues derived from Fixed Fees and Production Fees, the sharing

shall be set at a proportion of 20% (twenty percent) for the Government and 80% (eighty percent) for the Regional Governments.

C) This Regional Government share shall further be shared as follows: 1. 16% (sixteen percent) for Provincial Government; 2. 32% (thirty-two percent) for the producing regency/city; and 3. 32% (thirty-two percent) for the non-producing regencies/cities within

the province. ⑭ In addition, the other obligations of IUP holders include promoting local content such as

utilization of domestic products and services, conducting community development programs and observing safety, health and environmental preservation laws and regulations.


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⑮ The transitional provision states that all existing cooperation contracts for geothermal undertakings (which were entered into under the legal framework existing prior to the Geothermal Law) will remain valid until their respective contract expiration dates. Also, the transitional provision stipulates that: A) A Mining Operating Area (“Wilayah Kerja Pertambangan” or “WKP”) that has been

operated by PERTAMINA and is generating power will remain as PERTAMINA’s WKP.

B) PERTAMINA’s WKPs which are under joint operation with other parties will remain as working areas of PERTAMINA. However, if within eight years the areas have not generated power, then the areas will be returned to the government (until 2010);

C) PERTAMINA’s WKPs in which no exploration has commenced shall continue for the next three years and during that period if no exploration activities are carried out the WKP shall be returned to the Government.

D) All the existing regulations regarding geothermal endeavors, except the contracts that already existed before the enactment of the law, become unenforceable. These include Presidential Decrees No. 22/1981, 45/1991, 49/1991 and 76/2000.

⑯ Unlike the previous legal framework, which permitted foreign companies to engage in geothermal undertakings through a permanent establishment (without having to form an Indonesian legal entity), the new Geothermal Law restricts geothermal undertakings to Indonesian legal entities only, which can be state or regional-owned companies, cooperatives or private sector companies (including those with foreign shareholding). Consequently, a foreign company must form an Indonesian legal entity under the framework of the Foreign Investment Law. These entities are subject to foreign direct investment licensing and supervision by the Capital Investment Coordinating Board. Tax consolidation is not allowed thereby one company has one IUP.

Fig. 3.2-1 shows the schematic diagram of the geothermal development process under

the Geothermal Law for indirect use (electricity generation).


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Fig. 3.2-1 Geothermal development process pursuant to Law 27/2003


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< Implementing Regulations > The Geothermal Law is 'umbrella' legislation setting forth general principles that will

be further developed in a series of government regulations, presidential decrees, ministerial decrees and regional government regulations. As called for by the law, this secondary legislation will elaborate the regulatory rules on issues including among others: ① Direct use of geothermal energy; ② Indirect utilization ③ Types and tariffs of non-tax state levies from upstream activities, such as royalties

(production tax), dead rent tax and bonus payments; ④ Rules on boundaries, coordinates, size, licensing procedures, bid solicitation terms,

preparation of tender documents and tenders of work areas; and ⑤ Relinquishments of work areas.

Only one Government Regulation (GR 59/2007) has been issued concerning these five areas of secondary legislation. Promulgated at the end of 2007, GR 59/2007 regulates the upstream activities of geothermal operation, covering the preliminary survey, exploration and exploitation of geothermal resources, including management and supervision, the preparation for Work Areas, the tendering of Geothermal Work Areas, and the Geothermal Business Permit (IUP).

Note that in mid-2007 the Minister of Energy and Mineral Resources (MEMR) issued Decree No. 5 of 2007, asserting the MEMR’s right to issue a permit for preliminary survey which provides to the holder the first right of refusal. Under MEMRD 5/2007, six permits for preliminary survey have been issued, i.e. two in Java (Guci and Baturaden in Central Java) and four in Sumatra (Muara Labuh, Rantau Dedap, Kalianda and Pematang Belirang). This was followed by another decree, MEMR Decree No. 14/2008, regarding the selling price of electricity generated from geothermal plants. MEMRD 14/2008 sets the policy for establishing the selling price of geothermally generated electricity. Under this regulation, the selling price of geothermal power is set at 85% or 80% of the PT PLN’s average cost of generating electricity in the area for power plants between 10 and 55 MW and above 55 MW, respectively. For example, applying the formula for Bali and South Sumatra the electricity selling price will be about 6.6 USD Cents/kWh and around 4.5 USD Cents/kWh, respectively.

In a further move affecting taxation, in late 2007 the Ministry of Finance Issued MOFD No. 177 and 178 of 2007, providing relief on import duty and VAT for imported goods to be used in oil and gas (177) and geothermal operations (178), provided that similar goods are not produced in Indonesia, the domestic product does not meet the specification, or the domestic products are not sufficient to meet the demand. The effective date of MOFD 177/2007 is retroactive to 16 July 2007. Under MOFD 178/2007, the VAT for imported goods will be borne


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by the Government; however the VAT relief is only applicable for the period 1 January 2008 through 31 December 2008.

< New Investment Law (Law No. 25/2007) > As mentioned previously, under the Geothermal Law, foreign participation in a

geothermal resource undertaking shall be in the form of an Indonesian legal entity under the framework of the Foreign Investment Law. These entities are subject to the foreign direct investment licensing and supervision of the Capital Investment Coordinating Board. The salient points in the new Foreign Investment Law promulgated in 2007 that may be relevant to geothermal undertakings are as follows.

Law No. 25/2007 replaced separate laws on foreign and domestic investment dating back to 1967 and 1968, and thereby provides a single legislative framework for domestic and foreign investment. The law specifies the investment principles and objectives, basic investment policies, types of business entities and locations, treatment of investment, labor and business sectors; investment development for micro enterprises, SMEs and cooperatives; rights, obligations and responsibilities; implementation of investment; special economic zones; and dispute settlement and sanctions. The law also states that all business sectors are open to foreign investment unless otherwise specified in a Presidential Regulation containing Indonesia’s list of sectors not open to foreign investment. This marks the first time that an Indonesian law has required a single, such comprehensive prohibitory list that is issued by the President. It is also the first clear statement in law that activities not included on the list are fully open to investment. (2) Electricity Price

Investment in geothermal development faces substantial uncertainties and continuing challenges. The industry has identified low steam and electricity prices, high capital costs, resource risk, long repayment periods for investment, financing mechanisms, a lack of market opportunities and inappropriate regulation as major issues impeding geothermal development. In Indonesia, uncertainty over implementation of regional autonomy has also been one of the issues impeding geothermal development. Geothermal energy prices need to be competitive with other energy alternatives, and at the same time offer the contractor or producer an attractive rate of return.

Typically, in order for a geothermal power project to become financially viable, project developers must secure an electricity sales contract with an electricity purchaser called a Power Purchase Agreement (PPA) or Energy Sales Contract (ESC). In addition to spelling out the specific terms and conditions of the power sales agreement, the PPA/ESC typically specifies the first-year electricity sales price and the annual rate of price escalation that the purchaser will


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pay throughout the life of the contract. Generally, projects that can offer the lowest first-year electricity price are considered the most economically competitive. Therefore, project developers often use the first-year electricity price as an indicator of a project's attractiveness. However, because the terms and structure of PPA/ESCs vary greatly from project to project, the first-year electricity price is not a reliable indicator to use when comparing different projects.

< PT PLN’s Electricity Price > The price of electricity in Indonesia is set in Rupiahs and controlled by the

Government. Presently, a uniform price is set across regions and cross subsidy between Java (which consumes 60% of the economy’s generated electricity) and systems outside Java and among sectors. The largest subsidies are given to small residential consumers, while large consumers pay market-oriented prices.

The basic electricity price or Tarif Dasar Listrik (TDL) comprises a capacity charge for kVA installed and an energy charge for kWh used. The TDL is determined based on the cost of goods sold (HPP/BPP) plus a reasonable margin. Certain load factors to cover usage during peak hours and consumption of reactive power may be included. The TDL is divided by the type of consumer, namely residential, business/commercial, industrial, social, government offices and street lighting, and there are wholesale and multipurpose tariffs covering special cases such as the export and import of power and short-term use for parties and special events.

The HPP/BPP is reviewed quarterly based on the computed costs for generation, transmission and distribution plus the costs of services and sales. Factors affecting the computed costs include the price of primary energy, exchange rate and consumer price indices. Another key parameter in setting up the final price is affordability.

Electricity prices have reached an economic level and the mechanism for price

adjustment is automatic. The computed economic price for Java Bali is on the order of 0.07 USD Cents/kWh, assuming a discount rate or rate of return of 12%.

The existing price structure is basically still not healthy, allowing the market creaming that resulted in losses for PT PLN. The current price tends to burden the industry and subsidize the small residential consumer excessively. Therefore, the requirement for a competitive environment is to re-balance the electricity price by raising the price for small residential consumers using the principle of long-term marginal cost and lowering the price for industry.

< Electricity Prices under Original ESC > Table 3.2-1 below shows the original prices contracted under ESCs. As can be seen,

the cost to PT PLN of electricity produced by geothermal power plants varied.


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Table 3.2-1 Selling prices by power plant

Geothermal Field USD Cents/kWhBedugul, Bali 7.15 Cibuni, West Java 6.90 Daradjat, West Java 6.95 Dieng, Central Java 8.30 Kamojang, West Java 7.03 Karaha Bodas, West Java 8.46 Patuha, West Java 7.25 Salak, West Java 8.46 Sibayak, North Sumatra 7.10 Wayang Windu, West Java 8.39

< Restructuring Electricity Prices > Electricity restructuring in Indonesia began in early 1992 when the Government

opened the electricity generation market to competition. Following Presidential Decree No. 37 of 1992, which opened entry into generation markets, a number of permits have been issued for Independent Power Producers (IPP) to build, install and operate power plants, and sell the generated electricity to PT PLN for distribution to the public.

The first IPP in operation was the 135 MW gas-fired power plant at Sengkang

(Sulawesi), which started up in 1997 and was followed by Paiton I (coal-fired). A total of 27 Independent Power Producers have entered into Power Purchase Agreements (PPA) with PT PLN (or Energy Sales Contracts in the case of geothermal generation). The main characteristics of the PPAs or ESCs include:

① Electricity prices denominated in USD (ranging from 5.7 US Cents/kWh to 8.4 USD Cents/kWh).

② Take-or-pay obligation on PT PLN (for example, under Paiton’s PPA, PT PLN is obligated to pay USD 589 million per year if it does not use the electricity)

③ Applicable law, generally Indonesia law. ④ Arbitration clauses for disputes with reference to international arbitration; and ⑤ Force majeure provisions. There are two pricing schemes that commonly used in the Power Purchase Agreements

(PPA) or Energy Sales Contracts (ESC) between PT PLN and IPPs. In one of the schemes the price consists of only one component, which is based on the kWh delivered. In addition to escalation indices, the price includes a “take-or-pay” capacity provision (TOP), in which the buyer has an obligation to pay between 80% and 90% of minimum capacity charge irrespective


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of the actual amount delivered. The TOP will ensure the recovery of operation and maintenance costs, and debt servicing obligations in a timely manner and will provide the shareholders with a return on their investment.

The other pricing scheme consists of two or more components, namely the capacity charge and energy charge, which are expressed as Dollars per kVA per month and Dollars per kWh, respectively. Such a two-component pricing scheme was characteristic of the original ESCs between PT PLN and PERTAMINA/IPP, except for Darajat, Salak, Kamojang and Sibayak. Under this scheme, the calculation of electricity prices has usually been broken down into the following components:

① Capacity charge (capital recovery charge comprising return for equity capital, debt repayment, tax and depreciation, contract capacity and availability factor). The capacity charge will decline to 50% and 25% after 10 – 14 years and 22 years, respectively.

② Energy charge (usually pass-through cost components as determined by the quantity and type of fuel, specific heat rate and fuel price, and fixed and variable operating and maintenance charge).

The two-component pricing scheme is designed to provide more security to the lenders by allowing for early repayment of the loan. Under the scheme, it is only the energy charge that will escalate, while the capacity charges will decline after the project is paid out. In the case of Wayang Windu, for example, the decline starts at the beginning of the 15th year of operation.

For example, in the original ESC for Wayang Windu, the capacity payment based on the Unit Rated Capacity per kilowatt-year was set up as follows:

For years 1 – 14 : USD 329.50 (USD 34.4 million/year) For years 15 – 23 : USD 164.75 (USD 17.2 million/year) Thereafter : USD 82.38 (8.6 million/year)

For the energy, the base price has been set at 4.638 USD Cents/kWh at the

Commencement Date, to be adjusted by the US Consumer Price Index.

In Salak 4, 5 and 6, the Energy Charge during the initial 15-year operating period has been agreed at 8.467 USD Cents/kWh, consisting of Generation and Resource Components. The Resource Component is 4.302 USD Cents/kWh as of the first Quarter of 1993, escalating based on the monetary exchange factor, the Indonesia Consumer Price Index, Oil field Machinery and Tools Index and US Producer Index for All Commodities. The Generation Component during the 15-year operating period is computed by subtracting the Resource Component from 8.467 USD Cents/kWh. Given that the total Energy Charge during the 15-year operating period is fixed at 8.467 USD cents/kWh and that the Resource Charge escalates, the Generation Component is essentially declining over time.


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4.90

5.13

4.00

4.20

4.40

4.60

4.80

5.00

5.20

5.40

Jul-99 Jan-00 Jul-00 Jan-01 Jul-01 Jan-02 Jul-02 Jan-03 Jul-03 Jan-04 Jul-04 Jan-05 Jul-05

DRJ II - 4.2 US¢/KWh @ 4th QTR 1999 WW (w/ DaraDRJ III - 4.2336 US¢/KWh @ 1st QTR 2001 WW (w/ SalaGunung Salak

Following contract rationalization, the final price for Salak is computed using the

following formula: Energy charge = 0.3 + 4.15 x I (in USD Cents/kWh), I = 0.15 x (Yi x Mb)/(Yib x Mi) + 0.45 x (Ym/Ymb) + 0.40 x (Yw/Ywb) Where: Yi = Indonesia Consumer Index Yib = Indonesia Consumer Index as of 4th. Quarter of 2000 Mi = Monetary Exchange Factor as of 4th Quarter of 2000 Mb = Monetary Exchange Factor Ym = Oil Field Machinery and Tools Index Ymb = Oil Field Machinery and Tools Index as of 4th. Quarter of 2000. Yw = US Producer Index Ywb = US Producer Index as of 4th. Quarter of 2000

Note that in the process of renegotiation following the Asian monetary crisis in late

1997, PT PLN has indicated its preference for a single pricing concept with limited escalation rather than cascading prices. PT PLN also capped the base electricity price at a maximum of 5.0 USD Cents/kWh between 1999 and 2003. For example, in the case of Darajat II, PLN and Amoseas have agreed after lengthy negotiations on a base price of 4.2 USD Cents/kWh as of the fourth quarter of 1999 and, given the price escalation of 2% per year, that base price has now increased to 4.85 USD Cents/kWh in the first quarter of 2005 (see Fig.3.2-2). This compares to Gunung Salak 4, 5 and 6, which have increased from 4.5 USD Cents/kWh as of February 2001 to 5.13 USD Cents/kWh.

Table 3.2-2 tabulates the IPPs’ geothermal electricity prices prior to and after contract rationalization. Table 3.2-3 tabulates the IPPs’ electricity prices for other fuel or non-geothermal generation.

Fig.3.2-2 Electricity price development after renegotiation


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Table 3.2-2 IPP’s geothermal electricity prices: original versus negotiated Project Capacity Original Price Negotiated Price USD Cents/kWh USD Cents/kWh 1 Darajat 140 MW 6.95 Unit 2: 4.20 1999 90% capacity Unit 3: 4.91 2004 2 Gunung Salak 165 MW 1 – 5: 8.46 4.45 - 2001 85% capacity 3 Sibayak 2 MW 7.10 4.70 85% capacity 85% capacity 4 Bedugul 175 MW 7.15 10 MW; 70% of 85% capacity Base price Bali 5 Cibuni 10 MW 6.90 PLN take over 6 Kamojang 60 MW 6.95 Pertamina takes over 7 Sarulla 330 MW 6.47 PLN takes over 85% capacity 8 Patuha 180 MW 1 – 14 : 7.25

15 – 22 : 5.63 23 – 30 : 4.62

PLN/Pertamina takes over

9. Dieng 240 MW 1 – 14 : 7.65 PLN/Pertamina takes over 15 – 22 : 5.97 Only Unit 1 in 23 – 30 5.13 Operation 86% capacity 10. Wayang Windu 440 MW 1 – 14 :8.40 5.00 - 2007 15 – 23: 5.97 24 – 30: 5.13 86% capacity

Table 3.2-3 IPP’s non-geothermal electricity prices: original versus negotiated Project Type & Capacity Original Price Negotiated Price USD Cents/kWh USD Cents/kWh 1 Sengkang CCGT - 200 MW 6.7 4.286 80% capacity 85% capacity 2 Palembang Timur CCGT – 130 MW 6.4 4.2 – 4.41 80% capacity 3 Cikarang CCGT – 150 MW 5.04 4.47


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72% capacity 4 Tanjung Jati B Coal – 1320 MW 5.73 3.85 -4.50 5 Paiton I Coal – 615 MW Yr 1-6:

8.4776 4.90

Yr 7-12: 8.2176

85% capacity

Yr 13-30: 5.4576 1-5: 85% capacity 6 Paiton II Coal – 1220 MW 6.95 4.68 80% capacity 85% capacity 7 Sibolga A Coal – 200 MW 6.55 4.68 80% capacity 80% capacity 8 Amurang Coal – 110 MW 6,7 4.65 9 Pare-pare Diesel – 60 MW 6.44 (gas) 5.71 6.21 (MFO) 10 Asahan Hydro – 180 MW 1-15 yrs: 7.68 <1175 GWh: 4.60 16-30 yrs: 3.46 >1175 GWh: 2.10 11 Cilacap Coal - 450 MW 6.34 Terminated 12 Tanjung Jati A Coal - 1320 MW 5.74 Terminated 13 Serang Coal – 450 MW 6.04 Terminated 14 Tanjung Jati C Coal – 1320 MW 5.73 Terminated 15 Cilegon Coal – 450 MW 6.06 Terminated 16 Pasuruan CCGT – 500 MW 5.76 Terminated

< Law on Electricity > Prior to 1985, the power sector was entirely government-led, under the direction of the

state-owned company PT PLN. In 1985 the Government issued Law No. 15/1985, allowing the participation of the private sector in electricity generation for its own use and to sell to PT PLN. Guided by a policy paper entitled “Goals and Policies of the Development of the Electric Power Sector”, the Government issued Presidential Decree No.37/1992, later known as the Private Power Decree. This Presidential Decree was replaced by Presidential Decree No. 38/1998, which revokes the provision in Article 6 of Presidential Decree No. 37/1992 regarding the waiving of import duty, income tax, and value added tax.

As the 21st century begins, like many other nations Indonesia is in the midst of a revolution in the electricity business. An industry dominated by monopoly utility companies, regulated from top to bottom by the state, is seeing competition and deregulation in the generation and sale of electric power. The motivation for electricity restructuring has been


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slightly different in different countries. In Indonesia, for example, the motivation has been elimination of state intervention in the industry in the form of a state-owned monopoly, and this has been reinforced by the government’s commitment to reducing inefficiency and corrupt practices and to make electricity available for all people at affordable price.

The framework for the unbundling of PT PLN was prepared in 1993 with the commissioning of a study for an institutional framework by NORPLAN A/S, which led to the plan to separate the power industry into its generation, transmission and distribution components. After the enactment of the Power Private Decree, IPPs proliferated remarkably, but the majority of contracts were based on an unsolicited, non-transparent bidding process, and resulted in overpriced, dollar-pegged, take-or-pay conditions that greatly favored project investors. In the period between 1994 and 1997, 27 more power purchasing agreement were issued and signed with IPPs.

Lack of transparency in the process, however, has resulted in several years’ setback for the IPPs in building their image and for the promotion of the domestic electricity market. The multidimensional crises starting in 1997 encouraged the government to rethink the restructuring approach. An August 1998 white paper (Power Sector Restructuring Policy) supported the momentum for restructuring, and a new Electricity Law was to be drafted to support the process. The road map for the future of the Indonesia electricity industry became clearer in 2002 with the enactment of Law No. 20/2002.

Under Law No. 20/2002, the vertically integrated electricity industry would be unbundled into three segments: generation, transmission and distribution. The government, in cooperation with the industry, developed a high-level Blue Print for implementing a competitive electricity market, with Batam Island as pilot project to be followed by Java, Madura and Bali. The electricity price was also gradually adjusted based on market prices.

In addition to improved efficiency, reduced costs and affordable electricity prices, another important goal of Indonesia’s electricity restructuring is attracting increased investment in generation, transmission, distribution and energy efficiency technology. Currently Indonesia’s generation, transmission and distribution system suffers from under-investment and demand growth is creating huge demands for capital. Furthermore, one objective of electricity restructuring is to better allocate risk among investors and consumers; a sound regulatory structure must ensure that consumers are treated fairly and that investors are given opportunities to earn a fair return on their investment.

With Law No. 20/2002, Indonesia’s electricity industry was moving in accordance with world-wide trends; however, a Constitutional Court decision of December 15, 2004 has resulted in several years’ setback for the promotion of a competitive domestic electricity market.


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In its decision on 15 December 2004, the Constitutional Court revoked Electricity Law No. 20/2002, ruling that it was against the nation's Constitution to open the door to full competition in the electricity business. A judicial review by the Constitutional Court had been requested by the PT PLN’s Worker Union, PT PLN’s retirees and some Non-governmental Organizations (NGOs).

In its ruling, the Court stated that the electricity should remain under the government's control, as electricity is an important commodity pivotal to the lives of many people. The court was of the opinion that Article 16, 17, and 68 of Electricity Law No. 20/2002 violate the Indonesian Constitution. Article 16 relates to article 8 regarding the unbundling of the vertically integrated state-owned electricity company PT PLN into seven new companies with focuses from generation to retail. Article 16 explicitly prohibits the cross-ownership of generation and retail companies by the state-owned power company, except for the transmission company, which is considered to be a natural monopoly, while Article 17 allows competition in the power sector.

The Court believed that Article 16 and 17 are the heart of the Law, and consequently that Electricity Law No. 20/2002 was not legally binding and must be revoked. Furthermore, the court ruled that all contracts or permits that have been made or issued based on Law No. 20/2002 will continue to be effective until their expiry. The Government is also requested to prepare a draft of a new law, and until such law is promulgated the electricity industry will return to being operated under Law No. 15/1985.

In response to the Court decision, the Ministry of Energy and Mineral Resources stated in a Press Release that the implications of the annulment of Law No. 20/2002 are among others as follows1:

① All regulations issued based on Law No. 20/2002 are revoked, including Government Regulation No. 35/2003 regarding the establishment of an Agency to monitor the electricity market (Badan Pengawas Pasar Tenaga Listrik or Bapeptal) and 18 decisions of the Minister of Energy and Mineral Resources. These Ministry decisions cover technical matters in implementing Law No. 20/2002, such as standardization of electricity utilization safety measures, electricity equipment and frequency (50 Hz), electricity installation, inspection, professional competency in generation, transmission and distribution, telecommunication and control, and preparation of the RUKN (General Plan for National Electricity).

② The preparation of the RUKN will no longer be governed by a bottom-up approach, but it will return to a top-down approach, while the RUKD (General

1 Departemen ESDM No.:22/HUMAS DESDM/2004, 16 Desember 2004


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Plan for Regional Electricity) will be eliminated. ③ The authority of regional governments to issue permits that had been delegated

based on Law No. 20/2002 will become invalid pursuant to the annulment of the law, and the issuance of permits will again be centralized.

④ PT PLN will return to its position as the sole Holder of Authority for Electricity Business based on Government Regulation No. 29/1994 regarding the Conversion of PT PLN into a Commercial Entity.

⑤ Except for state-owned companies whose main business is providing electricity services, no other state or regional government-owned companies, private companies or cooperatives will be allowed to providing electricity service to the public.

⑥ Participation of regional government-owned companies (BUMD), private companies and cooperatives in providing electricity to the public could only be permitted through cooperation with PT PLN in cases where PT PLN itself lacks capability.

The following are some measures that will be or have been taken by the Government

in response to the Constitutional Court decision: ① The material in Law No. 20/2002 will be reformulated in the implementing

regulations of Law No. 15/1985, as long as they are still in the same spirit as Law No. 15/1985.

② The authority given to regional governments to issue permits and to plan for electricity will be regulated in accordance with Law No. 15/1985 and Law No. 31/2004 regarding Regional Government.

③ PT PLN is presently the only State-Owned Company in the field and is the sole Holder of Rights for Electricity Business (PKUK). However, in order to accelerate the construction of infrastructure throughout Indonesia, it is planned to establish in accordance with the prevailing law and regulations a number of such authorities with the sole authority to provide electricity regionally.

④ Government Regulation No. 3/2005 has been issued to replace Government Regulation No. 10/1989. In essence, Government Regulation No. 3/2005 stipulates, among other things, the following:

A) The supply and utilization of electricity are based on the National Electricity General Plan (RUKN), which shall be prepared by the Government with due consideration to inputs from the regional governments and the community.

B) The state electricity enterprise (PT PLN) is appointed by the Government as the Authority Holder for the conduct of the electricity business. PT PLN shall translate the RUKN into an Electricity Supply Plan (RPTL) which shall be approved by the Minister.


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C) Priority shall be given to the use of local primary energy sources with the obligation to give due consideration to the use of renewable energy.

D) Electricity Supply Business Licenses shall be issued by Central Government, Provincial Government or Regional Government depending on whether the electricity supply is either connected to the national grid across provincial or regional government jurisdictions or is isolated within a single region.

E) Purchase of electricity shall be through a tendering process, except for 1. Electricity purchased from a power plant fueled by renewable energy,

marginal gas, or other locally available energy, or from a mine-mouth power plant.

2. Excess electricity; or 3. Times when the local electricity system is in a critical supply condition.

F) The price of electricity shall be expressed in Rupiah. G) Provisions for compliance with safety standards, national standards and

personnel competency certification. ⑤ The Government is preparing the draft of a new law on electricity.

3.3 Recent Geothermal IPP Activities

< Geothermal IPP in Indonesia > In Indonesia, electricity is supplied by the vertically-integrated monopoly PT PLN,

which is also the monopoly provider of transmission, distribution and supply of electricity. It is the sole buyer and seller of electricity, currently purchasing approximately 80% of the power produced by the Independent Power Producers (IPPs). Strong economic expansion in Indonesia over the 15 years prior to the 1997 Asian monetary crisis has led to significant demand growth for electricity. Particularly in Java, Madura and Bali (JAMALI), strong demand for electricity has been relatively constant since the 1970’s. Between 1970 and 1997, electricity demand has grown at an annual rate of 14 to 18%. Demand growth has outstripped the capability of the government to fund electricity infrastructure rapidly enough to meet the surge in demand.

The IPPs provided a solution to the serious shortage of electricity experienced in Indonesia between 1989 and 1991. The parties in large projects were international energy companies partnered with domestic companies. By early 1997, there were 27 IPP projects with total 10,835 MW of new capacity. These included 11 geothermal power plant projects, namely Darajat (330 MW), Gunung Salak (495 MW), Dieng (400 MW), Wayang Windu (400 MW), Sarulla (330 MW), Karaha Bodas (400 MW), Patuha (400 MW), Cibuni (10 MW), Sibayak (120 MW), Kamojang (60 MW) and Bedugul (400 MW). (Note that Lahendong (60 MW) that is operated by PERTAMINA and PT PLN is not included in the list of 27 IPPs). By 2003 PT


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PLN was purchasing electricity from the IPPs to a total value of IDR 9,000 billion at an average price of 4.76 USD Cents/kWh.

In summary, in addition to the state owned company PERTAMINA, at present private companies operate most geothermal fields under a Joint Operating Contract with PERTAMINA that allocates 4% of net operating income to PERTAMINA, and an additional 34% of net operating income to the government. PD No. 45/1991 outlines two alternative paths for geothermal energy development in Indonesia. Under the first path, PERTAMINA or its joint operation contractors develop and operate the steam field only, selling the steam to PT PLN or other parties for electricity generation. The second alternative allows PERTAMINA or its contractors to generate electricity as well as developing and operating the steam field, with the electricity produced being sold to either PT PLN or other consumers. The following summarizes the current status of field development and the contracts under which the development is being carried out.

< PERTAMINA > The geothermal resource development for electricity production began in the early

1970’s with Kamojang Field in West Java. In 1974 PERTAMINA started exploration activities in Kamojang and installed a 250 KW non-condensing geothermal power turbine in 1978. PT PLN built on this initial success with the construction of Indonesia's first commercial geothermal electric power plant in late 1982 with a capacity of 30 MW. Exploration activities identified resources sufficient to expand the existing plant by an additional 110 MW, and Units II and III (2 x 55 MW), a US$61 million World Bank-financed project, commenced operation in 1987. PT PLN plans to build a fourth geothermal plant with an output capacity of 55 MW.

In December 1994, PT. Latoka Trimas Bina Energy (joint venture with ASIA POWER Ltd.) signed JOC and ESC agreements with PERTAMINA and PT PLN, respectively, to develop 2 x 30 MW in Kamojang field, West Java, with an investment of USD 72 million. In 1997 the Government decided to postpone the project (PD No.5/1998) and the JOC and ESC were finally cancelled with some compensation following a lengthy negotiation.

In addition, PERTAMINA also operates the Sibayak (North Sumatra) and Lahendong (North Sulawesi) Fields. Like Kamojang, in Sibayak PERTAMINA has signed a JOC with PT Dizamatra for development of the Sibayak geothermal field. Sibayak is located about 50 km southwest of Medan, in North Sumatra. Pertamina and PT. Dizamatra are jointly developing the Sibayak field, with Pertamina managing the steam field and planning to supply steam to a future 10 MW private power plant. Through July 1999, 10 wells had been drilled, with a proven capacity of 25 MW. Since 1995, one well has been supplying steam to a 2 MW back-pressure power plant installed and operated by PERTAMINA to supply the local power grid. The


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reservoir is liquid-dominated with temperatures from 240° C to 275° C.

In Lahendong, PERTAMINA signed a contract with PT PLN to supply steam to the unit I (20 MW) geothermal power plant constructed by PT PLN. The two parties also agreed on a steam price of IDR 161.50/kWh (2.0 USD Cents/kWh). The project became operational in August 2001, after waiting over one year for commercial operation to begin. PT PLN has also offered to cooperate with PERTAMINA in the development of unit II (20 MW), in anticipation of continuing electricity demand growth in North Sulawesi.

Lahendong is located 40 km south of Manado in north Sulawesi and has been under development by Pertamina since 1984. Fifteen exploration and development wells have been drilled with a proven generating capacity of 30 MW. In 1992, PERTAMINA was also installing a binary cycle power plant in the area with the assistance of a USD 5 million soft loan from France. The 2.5-MW plant was the first binary cycle plant installed in Indonesia and was a pilot scheme to gather experience in the development of other small-scale geothermal power stations. The 2.5 MW binary power plant has not gone into commercial operation.

< UNOCAL (now CHEVRON) > In 1982, UNOCAL Geothermal Indonesia signed the first Joint Operation Contract

(JOC) and Energy Sales Contract (ESC) for geothermal exploration and development. These contracts cover an area of 117,650 hectares in Gunung Salak, West Java. UNOCAL is responsible for supplying steam to PERTAMINA, which in turn sells it to PT PLN for power generation. PT PLN completed construction of a 2 x 55-MW geothermal power plant in 1994 and added another 55 MW in 1997. UNOCAL invested more than USD 100 million to develop the field. The company reported that the field is able to supply a power plant with a capacity of 400 MW. PT PLN and UNOCAL reached an agreement to price geothermal steam at 4.7 USD Cents/kWh. This enables UNOCAL to recover its exploration and development costs within 7-10 years.

In February 1993, UNOCAL signed another geothermal contract to exploit geothermal resources in a 980-square-kilometer area around Sarulla and Sibualbuali, North Sumatra. The Sarulla contract Area is located 300 km south of Medan in North Sumatra. The agreement is a total project contract consisting of a JOC agreement with PERTAMINA and an ESC with PT PLN. Pursuant to the terms of the JOC, UNOCAL agreed to spend at least USD 28 million during the first seven years of the exploration period. UNOCAL invested over USD 45 million in resource exploration and development and drilled 13 wells in three different prospective areas, discovering high-temperature geothermal systems in each area. These include Silangkitang, Namora-I-Langit, and Sibualbuali (Gunderson et al.). Resource feasibility studies have been submitted to Pertamina in support of the first 330 MW development at Silangkitang and


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Namora-I-Langit.

PT PLN and UNOCAL agreed to the development of a power facility with a total capacity of 220 MW, with 55 MW to be completed by 1999. The power price for the contract was to be 7.597 USD Cents/kWh for the first 14 years, 5.750 USD Cents/kWh for the following 8 years and 5.208 USD Cents/kWh for the remaining 8 years. As a first stage, UNOCAL planned to construct a 2 x 55-MW power plant. UNOCAL would operate and maintain the field facilities and electricity generation facilities under a Build, Operate and Transfer (BOT) scheme for the first 15 years. Following the contract agreement, the company invested USD 100 million for the development of infrastructure and the plant site. The government postponed the project in 1998, and PT PLN and UNOCAL finally reached an agreement in which PT PLN takes over the Sarulla Project for USD 60 million.

In Sumatra, UNOCAL and PT. Daya Bumi Lumut Balai were working towards the signing of a contract to develop a 150 MW geothermal power plant in Lumut Balai, South Sumatra, with a total investment of USD 330 million, but the contract was not signed, and negotiations ended after the negotiation period expired.

< AMOSEAS (subsidiary of CHEVRON) > In December 1984 AMOSEAS signed a JOC with PERTAMINA and an ESC with PT

PLN to develop up to 330 MW of geothermal energy within a 56,650 hectare area in Darajat, West Java. AMOSEAS, which acts as the operator for the project on behalf of CHEVRON and TEXACO, confirmed a resource sufficient to supply a 55-MW power plant and with potential for at least 400 MW. After investing US $55.2 million for the construction of the 55-MW power plant, PT PLN started commercial operation in November 1994, with steam supplied by AMOSEAS. In 1995 AMOSEAS re-negotiated and amended the ESC in a manner that enabled the company to build all the future units at Darajat. This enabled AMOSEAS to plan Unit II and drill more development wells in anticipation of further development.

In 1997 AMOSEAS began construction of unit II (nominal 70 MW), but the government suspended plant construction in 1998. As a result of contract renegotiations, PT PLN and AMOSEAS reached a final long-term solution in April 2000, with the price of electricity reportedly dropping to a base price of 4.20 USD Cents/kWh from the 6.95 USD Cents/kWh of the original ESC. The new pricing is also applicable to Unit III (110 MW), which began to operate in mid-2007.

The production from the Darajat III unit increases the total capacity at the Darajat geothermal facility to 259 MW. Also, the Darajat III unit has been approved by the United Nations as a Clean Development Mechanism (CDM) project, a market-based instrument of the


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UN's Kyoto Protocol to encourage implementation of cost-effective greenhouse gas reductions. Darajat III is the largest geothermal energy project to be registered under the CDM program and the first geothermal project in Indonesia receiving CDM status.

< CALIFORNIA ENERGY Ltd. > In December 1994, Himpurna California Energy Limited (HCE), a joint venture

between PT Himpurna Enersindo Abadi (10%) and California Energy International of the U.S. (90%), signed a contract to build the Dieng geothermal project in Central Java. The geothermal field is located in mountainous terrain in central Java Island about 80 km northwest of the city of Yogjakarta. The geothermal area at Dieng is heavily farmed (rice and vegetables) and densely populated.

The contract was for a total power capacity of 400 MW, with four (4) units. HCE has drilled about 48 exploration and development wells and identified the field’s potential as 350 MW. The geothermal system is dominated by two-phase conditions with temperatures of 280°C to 330°C. For the first unit of 60 MW, which was certified for commercial operations in July 1998, HCE has drilled 25 full-size wells. However, following the monetary crisis, all construction, exploration activities and operations for Unit II were suspended.

In late 1994, HCE also signed a total project contract for the development of Patuha geothermal field in West Java, with a total capacity of 220 MW. California Energy teamed with PT Enersindo Supra Abadi. The Patuha Geothermal field is located in West Java approximately 45 km southwest of the city of Bandung. Total planned investment was to reach USD 264 million. PPL has drilled 13 conventional exploration wells, 17 slim holes and 6 development wells since 1994. A moderate to high temperature reservoir has been discovered (175° C to 245° C). Although originally scheduled for completion in 1999, Unit 1 (55 MW) was put under review, and units 2, 3 and 4 were postponed in 1998. Patuha power had spent USD 136 million for construction and financing. The development of this field has now been assigned to Geo Dipa (a joint venture of PERTAMINA and PT PLN) for continuation of the project.

HCE filed an international arbitration claim against the Indonesian government for the postponement of its contract. In late 1999, an arbitration tribunal in Geneva issued a ruling ordering both PERTAMINA and state electricity company PT PLN to pay USD 575 million to Mid-American (which acquired California Energy), plus interest of 4 percent per year, starting from January 2001.

In November 1999, the Overseas Private Investment Corporation (OPIC) and a consortium of private insurers paid USD 290 million to Mid-American under separate contracts of insurance covering the U.S. Company’s equity investments in Dieng and Patuha. OPIC and


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the private insurers determined that compensation was payable under their respective contracts of insurance after an international arbitral panel awarded the project companies a total of USD 575 million in a judgement against the GOI. On August 27, 2001, the Indonesian Government and OPIC representatives signed a settlement agreement transferring OPIC’s shares in the Dieng and Patuha project to the Indonesian Government. A Re-commissioning Loan Agreement and Note also provided OPIC funding to re-commission the Dieng Geothermal project’s 60-MW unit. Currently, like Dieng, the Patuha field is operated by PT Geo Dipa. In order to finance the project Geo Dipa signed an agreement with BUMIGAS, but as BUMIGAS failed to obtain financing, the agreement was unilaterally cancelled by PT Geo Dipa.

Moreover, in November 1994 California Energy, through a joint venture with local company PT Pandan Wangi Sekartaji (Bali Energy), also signed a JOC with PERTAMINA and an ESC with PT PLN for a 4 x 55 MW power plant in Bedugul, Bali. The field, which is located about 60 km northwest of Denpasar, has been explored by drilling three conventional exploration wells and six slim holes which have confirmed reservoir temperatures from 245° C to 340° C. Units 1 and 2 were under review and units 3and 4 were postponed in 1998. The government has since invited investors to continue the Bedugul geothermal energy project to meet the increasing electricity demand in Bali. The project is progressing slowly due to challenges by environmentalists.

< CAITHNESS and FLORIDA POWER & LIGHT (FPL) > In December 1994, Karaha Bodas Company LLC signed an ESC with PT PLN for the

construction of a 220-MW geothermal power plant in West Java, with 55 MW to be completed by 1998. Karaha Bodas Company LLC. is a joint venture between Caithness (40.5%) and Florida Power & Light (40.5%), both of the US, and Tomen of Japan (9%) and a local company (Sumarah Daya Sakti (10%). KBC has drilled nine conventional exploration wells and 19 slim holes, discovering a liquid-dominated resource overlain by a steam cap. Reservoir temperatures range from 230° C to 245° C and there are about 30 MW in proven reserves. The Karaha field is located 80 km east of Bandung in West Java. About USD 100 million of the total planned investment of USD 264 million had been invested when the project was postponed. Under the contract, PT PLN was to buy electricity from Karaha Bodas at between 5.6 USD Cents/kWh and 8.4 USD Cents/kWh for 30 years.

KBC filed an international arbitration claim against the Indonesian government for the postponement of its contract. In December 2001, an arbitration tribunal in Geneva issued a ruling ordering both PERTAMINA and state electricity company PT PLN to pay USD 261.1 million to Karaha Bodas, plus interest of 4 percent per year, starting from January 2001. The amount comprises USD 111 million for lost expenditure, USD 150 million for lost profit and USD 66,654.92 for costs and expenses during arbitration.


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< ASIA POWER Ltd. > In December 1994, Mandala Magma Nusantara BV signed a total project contract for

the development of the Wayang Windu geothermal field in West Java, with a total capacity of 400 MW. Mandala Magma Nusantara BV was a joint venture between the Indonesian companies Figears and Oko Satrya Mandala, and Magma Power Co. of the US. However, after the merger between California Energy and Magma Power Company, Asia Power Ltd, a subsidiary of New Zealand’s Brierley Investments Ltd became the contract principal party. In 2000, Asia Power completed a 110-MW geothermal power plant, but it was handed over to bank creditors (Credit Suisse Boston and Deutsche Bank) following its failure to repay loans. Asia Power had a 95 percent stake in the power plant before it ceased operation, with the remaining shares owned by Indonesian firm Bumi Mandala Perkasa. The lenders appointed UNOCAL as the operator of the power plant following Asia Power’s pullout. The banks later sold their 100-percent stake to Star Energy Ltd. for USD 230 million, which then developed the second unit following successful negotiations on the new tariff. The construction of geothermal power plant Wayang Windu Unit II (110 MW) was completed in late 2008, bringing the total installed capacity to 227 MW. Table 3.3-1 below summarizes the current status of geothermal development contracts.

Table 3.3-1 Status of geothermal development contracts

as of 1 January 2009 Field

Contract MW

Installed MW

Additional MW of steam

Contractor/Operator

Kamojang 1-3, 1984 140 140 Pertamina Kamojang 4, 1994 60 60 LTBE-AP/Pertamina Sibayak, 1996 120 2 8 Dizamatra/Pertamina Lahendong, 1999 20 20 20 Pertamina G. Salak, 1982, 1994 495 330 Unocal/Chevron Darajat, 1984, 1994,2004 330 259 Amoseas/Chevron Dieng 1-4, 1994 400 60 60 Himpurna E/Geo Dipa Wayang Windu, 1994 400 220 Asia Power/Star Energy Sarulla, 1993 330 141 Unocal/Medco Patuha, 1994 400 60 Himpurna/Geo Dipa Bedugul, 1995 400 10 Bali Energy Ltd. Karaha Bodas, 1994 400 30 KBC/Pertamina Cibuni, 1995 10 10 Yala Teknosa Total 3,505 1,031 399


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3.4 Recent Investment Environment for Geothermal Projects

< Geothermal Development Under the New Geothermal Law > Since its promulgation in 2003, no IUP pursuant to the new geothermal law has been

issued. Geothermal development activities to date have been limited to continuing the old programs begun by existing developers under the old laws, i.e. PD 45/1991 and PD 49/1991. The following factors explain Indonesia’s lagging development of its geothermal resource for generating electricity: ① Commercial development of geothermal energy requires electrical power plant

development onsite, and this requirement may limit the resource to a small local market or one not well connected to a larger load center.

② Development entails high initial capital costs, including initial exploration, and requires a commitment to purchase a large portion of generated energy at the stage of start-up of development wells. Long-term operating costs, however, are quite low. Thus, geothermal contracts require base load status and long term price security in order to justify development.

③ Several significant benefits of geothermal development are not effectively represented in the valuation of the electricity. These benefits include the long-term low cost operation, contributions to preserving the environment, and the resultant diversification of supply with an indigenous, distributed resource.

（Source） Schlumberger Business Consulting, Improving the economics of geothermal development through an oil

and gas industry approach

Fig.3.4-1 Selling prices and geothermal activities


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<Legal Aspects >

General investment regulations are applied to private investment in the electric power sector, in addition to the regulations specifically related to the electric power business. The general regulations for foreign direct investment are as follows.

<Foreign Capital Investment Law (Law No. 1 / 1967) >

Foreign Direct Investment (FDI), also referred to as Penanaman Modal Asing (PMA), is governed primarily by the Foreign Capital Investment Law No. 1 of 1967, as amended by Law No. 11 of 1970. Based on these laws, the government has been introducing various policies and measures on FDI, and is now making great efforts to promote FDI in Indonesia. An FDI company is granted a period of 30 years to operate after its legal formation. If within the said period of time it commits an additional investment (for expansion of its project), another 30 years of time is granted for the expansion project. The granted period can be extended for an additional 30 years.

< Domestic Capital Investment Law (Law No. 6 / 1968) >

Domestic Direct Investment (DDI), also referred to as Penanaman Modal Dalam Negeri (PMDN), is for businesses entirely financed by Indonesian capital and is governed primarily by Domestic Capital Investment Law No. 6 of 1968, as amended by Law No. 12 of 1970.

< Corporate Law (Law No. 1/ 1995) >

The most common legal entity in the business community is the Limited Liability Company, or Perseroan Terbatas (PT), whether a creation of foreign direct investment or domestic direct investment.

< Government Regulation No. 20 of 1994 on Share Ownership >

In general a FDI company is established as a joint venture between foreign and Indonesian partners. The partnership may involve legal entities (corporations) or individual persons. In the case of infrastructure projects, such as ports, generation and transmission as well as distribution of electricity for public use, telecommunications, shipping, airlines, potable water, public railways and nuclear electric power generation, a FDI company should be established by way of joint ventures between foreign and Indonesian state-owned enterprise. Therefore, an enterprise which intends to carry out geothermal development needs to form a joint venture with a state company. In general, for cases other than the above-mentioned FDI companies, there is no requirement on the minimum amount of investment (equity plus loan). The amount is for the parties concerned to determine, based on their economies of scale and business considerations.


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A FDI company may be established as a straight investment, or with 100 % foreign ownership. It is required, however, that not later than 15 years after commencement of commercial operations, the company begin divestment by selling some of its shares to Indonesian individual(s) and/or business entities through direct placement and/or indirectly through the domestic stock exchange until the Indonesian share is at least 5 %.

< Taxes > As of this date, no geothermal exploration or development are taking place under the

terms of Law No. 27 of 2003. One of the reasons for this is the lack of legal certainty, including certainty concerning taxes applicable to geothermal ventures. The following is a comparison of terms for geothermal undertakings under the old law and the new law.

Table 3.4-1 Tax rates comparison under new and old laws Law No. 27 of 2003 PD 1991 Oil & Gas Income Tax rate 25% 34% 30% Tax on profit 20% - 20% VAT 0% 0% 0% Duties & Import Tax 0% 0% 0% Royalty/Gov Share ? 4% (on profit) 72.2% Withholding Tax treaty Depreciation 6.25% 6.25% 25% & 50% Pre production costs ? Amortized Amortized Loss carry forward 5 years 5 years Unlimited

(Note: Question mark means the treatment is unclear.)

There are unique aspects to the development of geothermal energy. It is site-specific

and the undertaking entails high capital costs for exploration and development of steam fields, a risk of failure to discover geothermal steam in sufficient quantity, long pay-back periods for financing, and limited markets. It requires incentives, including special treatment on taxation.

Pursuant to Article 28 of the Geothermal Law (Law No. 27 of 2003), the license holder for a geothermal undertaking may be granted tax facilities based on the prevailing laws and regulations. The following are pertinent items that may be considered in providing tax facilities for geothermal development undertakings.

For instance, pursuant to Article 31 of the amended 1983 Income Tax Law and

Government regulation No.1 of 2007, the tax facilities include among others the following: ① Reduction of net income of 30% from the invested capital for six (6) years at 5% annually. ② Accelerated depreciation and amortization


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③ Reduction of 10% in the tax on dividends paid to non-residents, or a lower tax rate. ④ Extension of carry forward loss from 5 years to 10 years.

Government Regulation No.1 of 2007 states that tax facilities will be granted to investment in certain industries and/or certain regions. It was unfortunate that geothermal energy development was not included in the list of items that receive such incentives. However, Government Regulation No. 62/2008 of October 2008 expanded the priority industry list. Fortunately geothermal development was included in the new list and can now receive the tax incentives listed above. 3.5 Evaluation of Recent Geothermal Incentives

< Geothermal Work Area Bidding System > From 2008, the MEMR started bidding for geothermal working areas based on their

own data and information obtained through the Center of Geological Resources (CGR) in Bandung under Geological Agency. First, the government made bids for the geothermal fields of Cisoroku-Cisukarame, Tangkuban Parahu and Gunung Tampomas, all in West Java. By this bidding, each working area development went to a corporation well-known in Indonesia (a construction company, a power plant installation company and a subsidiary company of PT PLN. See Table 3.5-1). Recently, government announced next biddings for the working areas of Jailolo and Sokoria.

Bidders compete on the planned selling rate of power from the working area, which the bidder estimates based on the data and information concerning the working area provided by the CGR. The bidders are required to deposit a certain amount of the bid as a bond. The winning bidder is also required to develop the geothermal resource within 4 years, with allowance for a one-year extension. The bidding system seems to feature several issues that require reconsideration: The bidding system includes prequalification evaluation. However, the biddings in

September 2008 show that there are some bidders who have no experience in exploration, development and construction of a geothermal power plant.

The DGMCG-CGR provids the geothermal data concerning the subject working areas, but these data are mere surface survey data and do not include MT survey data or data from exploration wells.

In spite of this lack of data, the bidders should present a selling rate for electricity from a geothermal power plant supposedly constructed in the subject working area. It is hard to imagine how the bidders could have decided what type of geothermal power plant to construct and what its capacity should be, without any steam conditions data from the


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subject geothermal fields. Depending on the subject working area, permission for geothermal development activities

may be granted by the provincial or regional authority. The capacity of these authorities to manage geothermal power development is also an issue.

There are some competent bidders experienced in geothermal power development like

Star Energy, but most of the companies participating in the bidding for the said work areas, are not considered to be experienced. When such inexperienced bidders are accepted, there is a fear that they will be unable to sustain the financial burden of a substantial upfront investment in risky geothermal power development and will abandon the development within the limited period of 5 years. That may result in an overall delay in the development of geothermal power in the country.

In addition, remote areas like the Eastern Archipelago of Indonesia are now overwhelmingly dependent on electricity supplied by diesel power plants in an independent power system with very expensive fuel and transportation costs. The electricity is supplied to the people there with a government subsidy which comes to reach the limit. Thus, in the areas where geothermal resources are available, PT PLN is positively taking actions to develop geothermal power to substitute for high-cost diesel generation. The use of renewable energy in remote areas is also the government priority in its energy policy. In spite of the investment in geothermal exploration, PT PLN itself cannot participate in the bidding because national law prohibits state enterprises like PT PLN or Pertamina from participating in bidding held by the government. So there is a possibility that PT PLN must abandon such geothermal fields without recovering its investment, if such sites should be included in the government working areas and become subject to public bidding. Before bidding on the working areas takes place, the development conditions should be

reviewed by the related agencies carefully, and if state companies like PT PLN have invested substantially in exploration or well drilling, a concession may be granted to such a prior developer without a bidding process

The present bidding system, in which competition centers around the future electricity selling rate, is impractical. If the present system should continue, the government should carry out sufficient exploratory surveys prior to bidding, and some well drilling, if possible. Or, the bidding system itself should be reconsidered.

The specified development period of 5 years is also too short to develop geothermal power in a green field. A longer development period should be allowed.


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Table 3.5-1Results of the bidding for geothermal power development in 2008 Project Name 1. PERINGKAT PEMENANG UNTUK WKP PANAS

BUMI GUNUNG TANGKUBAN PARAHU Rank, Company Name, Price 1. TANGKUBAN PARAHU GEOTHERMAL POWER

5 33.60 IDR/kWh (5.80 USD Cents/kWh)

Rank, Company Name, Price 2. PT. ISTECH RESOURCES ASIA 559.45 IDR/kWh (6.08 USD Cents/kWh)

Rank, Company Name, Price 3. MEDCO JABAR GEOTHERMAL 657.80 IDR/kWh (7.15 USD Cents/kWh)

Project Name 2. PERINGKAT PEMENANG UNTUK WKP PANAS BUMI GUNUNG TAMPOMAS

Rank, Company Name, Price 1. KONSORSIUM PT.WIJAYA KARYA – PT.JASA SARANA

- PT.RESOURCES JAYA TEKNIK MANAGEMENT

INDONESIA

598.00 IDR/kWh (6.50 USD Cents/kWh)

Rank, Company Name, Price 2. PT. INSTECH RESOURCES ASIA 623.76 IDR/kWh (6.78 USD Cents/kWh)

Rank, Company Name, Price 3. TAMPOMAS GEOTHERMAL POWER

809.60 IDR/kWh (8.80 USD Cents/kWh)

Project Name 3. PESERTA LELANG UNTUK WKP PANAS BUMI CISOLOK-CISUKARAME

Rank, Company Name, Price 1. JABAR HALIMUN GEOTHERMAL 630.00 IDR/kWh (6.848 USD Cents/kWh)

Rank, Company Name, Price 2. CISOLOK GEOTHERMAL POWER 630.20 IDR/kWh (6.850 USD Cents/kWh)

< Bench-mark Purchase Price of Geothermal Electricity> To promote geothermal power development in the country, the MEMR set the

benchmark electric purchase price from the geothermal power in January 2006. The benchmark prices were revised annually through DGEEU under the MEMR.

The benchmark prices was calculated as a percentage of the present average generating costs of PT PLN at each of 21 subsystems of 14 power systems. Geothermal power development was divided into two categories: 10 MW to 55 MW and more than 55 MW. For the 10 MW to 55 MW class, 85% of the present generating cost was specified as the benchmark price, and this fell to 80% for 55 MW class geothermal plants. The benchmark prices of the year


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2008 are shown in Table 3.5-2.

These benchmark prices, however, were only a guideline to the highest price PT PLN would pay for electricity and did not necessarily guarantee a PPA with PT PLN at that price, so the developer must negotiate with PT PLN with respect to the benchmark prices. There were variations in the benchmark prices, with the prices being relatively higher (at more than 10 USD Cents/kWh) in remote areas like the East Indonesia where the diesel power is dominant, and lower (at slightly less than 5 USD Cents/kWh) in West Sumatra, where large-scale geothermal plants are expected.

There were several complaints from geothermal investors about these ceiling prices. The complaints were that the price would fluctuate every year, that the procedure of price calculation was not disclosed and not clear, that the prices did not take into account geothermal resource potentials in the areas, that the prices were too low to attract geothermal investment, and so on. A new price guideline has been definitely required to accelerate geothermal power development. <Guidelines for Electric Power Purchase Price by PT PLN (MEMR Regulation No. 5/2009)>

In the backdrops of these complaints, Ministry of Energy and Mineral Resources announced the Ministerial Regulation on Guidelines for Electric Power Purchase price by PT PLN (MEMR regulation No.5/2009) in March, 2009. This regulation abolished the provisions of the benchmark purchase price of geothermal energy designated by MEMR, and instead newly stipulates that PT PLN can set forth the self-estimation price for renewable energy and can purchase renewable energy at the price when it is approved by MEMR. At the same time, the government obliged PT PLN to purchase renewable energy up to 10 MW capacity. The detail of this regulation will be discussed in Chapter 14.


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Table 3.5-2 The purchase price guideline for geothermal power plants

CHAPTER 4

CONDITIONS FOR ATTRACTIVE IPP

PROJECTS


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E L

Shareholders Lenders

EPC OM

Off Taker

Equity

DividendLoan Repayment

Interest

PPA

Construction FOM,VOM

Fuel Supplier

FSA

E L

Shareholders Lenders

EPC OM

Off Taker

Equity

DividendLoan Repayment

Interest

PPA

Construction FOM,VOM

Fuel Supplier

FSA

CHAPTER 4 CONDITIONS FOR ATTRACTIVE IPP PROJECTS

The purpose of this study is to promote private sector geothermal IPP projects. This Chapter discusses the conditions that make IPP projects attractive to private investors. ＜Stakeholders in IPP projects＞

IPP projects have various stakeholders, as shown in Fig.4-1. An IPP project is obliged to distribute the promised returns to these stakeholders through sound operation of the project.

The first stakeholder is the investor in the project. Investors provide equity and expect

dividends. An IPP project must make profits to pay dividends. The second stakeholder could be the lender. The lender provides loans to the project. Due to the cost-intensive nature of these power projects, IPP projects often apply the project financing method. The leverage ratio differs for each project and varies from 20% to 80%, subject to the financing policy of project. An IPP project is obliged to pay interest and principal to the lenders. The third stakeholder could be the off-taker. In the case of Indonesia, power business licenses are restricted to PT PLN, and therefore PT PLN is the only entity that can be the off-taker. An IPP project is responsible for supplying power to PT PLN, and receives revenues in return. Other stakeholders are the EPC (Engineering, Procurement & Construction) contractor for construction work, fuel suppliers, operation and maintenance providers, the government, which is expected to provide optimum business circumstances and so on. An IPP project is obliged to pay for their contributions in the form of fees or taxes. Fig. 4-1 An IPP project and its stakeholders


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＜Payments for IPP projects＞

An IPP project must fulfill its duty to these stakeholders by supplying power or making payments. In order for that to be possible, the project must earn sufficient revenues. As an indicator for profitability of the project as a whole, Project IRR (internal rate of return) may be useful. The stakeholders must manage to maintain Project IRR higher than their criteria level (PrIRRc) to secure sufficient profit.

Also, as the first stakeholder, the investors need to be confident of the project’s future profitability against their initial equity investments. For this purpose, the investors pay attention to the level of Equity IRR. They commit to invest only when the Equity IRR of a project is higher that their criteria level (EqIRRc). Therefore, in order to realize a project, the profitability forecast of project must satisfy these 2 conditions stated above.

cIRRIRR PrPr ≥ (4.1)

cEqIRREqIRR ≥ (4.2)

＜Business Risk＞

In executing a project, another factor more important than profitability is the business risk. The business risk is the possibility of the project failing to achieve the expected rate of return. If the possibility of the project failing is big, the project is considered to be high risk. In case of power projects, the revenue of the project will rely on power sales. Since power is a commodity that supports the basic economic activities of the country, it would not be appropriate for the tariffs to be set too high. Therefore, a project has to expect moderate and secured returns over the long term, giving the project the character of “Cash Cow”. In order to realize such a “low-risk low-return” project or a “Cash Cow” project, a long-term off-taking agreement (or PPA) with a highly reliable entity is vital. This PPA generates steady revenues regardless of market price volatility. Furthermore, construction risk, fuel procurement risk, and O&M risk are often outsourced to external organizations. A central task of an IPP project, therefore, is to hedge or minimize the various kinds of risk by passing them through to external organizations. Therefore, another condition for realizing an IPP project is the following.

Project Risk → zero or minimal (4.3)


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＜Risk needs to be hedged＞ In the case of a coal-fired IPP project, the investors manage to limit the risk to equity

and guaranteed bonds by applying the following measures.

(1) Market Price Volatility Risk To realize a Cash Cow project, future profitability must be transparent. To eliminate risk to future profitability, a PPA with a highly reliable off-taker is a must. A PPA usually lasts for 20 to 30 years, subject to the life span of the assets. PPA revenue consists of a Capacity Charge (CC), Fixed O&M fee (FOM), Variable O&M fee (VOM) and Fuel fee (F).

(2) Construction Risk

An IPP project assigns an EPC contractor to build the power plant on a turn-key basis. EPC costs are paid out of equity and loans, in line with the progress of construction services. An EPC contractor is usually required to post a completion bond to guarantee timely completion and promised capacity.

(3) O&M Risk

An IPP project company is merely the owner of the project, and often outsources the O&M work. The payment to the O&M Company equals the sum of FOM and VOM.

(4) Fuel Procurement Risk

An IPP project company cannot be responsible for fuel procurement. The responsibility for fuel procurement usually lies with the fuel supplier or the government or the off-taker. A Fuel Charge is added in the tariff so that the volatility of fuel prices will not damage the profitability of project. However, when the project fails to operate the power plant as agreed in the PPA through its own failure, the project will still have to purchase the fuel, despite the fact that the fuel cannot be immediately used for generation (Take or Pay).

(5) Foreign Exchange Rate Risk

Foreign investors investing from their US dollar accounts expect the dividends to be paid in US dollars as well. However, because the operation of a project is conducted in the local currency, a foreign exchange risk emerges. To eliminate such risks, a PPA involves an exchange rate adjustment formula to apply the rate agreed by both parties upon the execution of the PPA, at every issuance of PPA invoices. A similar formula is applied to adjust the consumer price index to cope with inflation.

＜Risk Countermeasure for Geothermal IPPs ＞

As discussed above, in investing in power deals, risk-hedging is often more important than profit-seeking. On the other hand, the responsibility of a geothermal IPP extends all the way from underground resource development to power supply. There is significant level of risk


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embedded that is by nature unavoidable. As we discussed above, investors will not tolerate these risks. In order to realize geothermal projects despite the risk, investors must be rewarded with high returns, or a certain risk-hedging structure must be in place. That is where government intervention is critical, and the level of intervention has to be sufficient to satisfy conditions (4.1) through (4.3) for geothermal projects in order to attract investors to the business.

CHAPTER 5

EVALUATION OF A COAL-FIRED IPP

PROJECT (BENCHMARK PRICE)


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CHAPTER 5 EVALUATION OF A COAL-FIRED IPP PROJECT (BENCHMARK PRICE)

5.1 Assumptions

This Chapter aims to calculate the selling price of electricity from a coal-fired IPP

project. The calculations are based on the following assumptions: ＜Specifications of the Plant＞

Generation capacity is assumed to be 600 MW, which is commonly found in Indonesia. The construction cost is assumed to be USD 726 million (1,210 USD/kW) over a 4-year construction period. ＜Coal Price＞

As stated in Table 5.1-1, the heat value of coal used in this calculation is 5,300 kcal/kg and its price is assumed to be 90 USD/ton for the evaluation period.

Table 5.1-1 Specifications of benchmark coal-fired IPP project

Items Specifications Remarks

Capacity 600 MW １unit Construction cost USD 726 million

（w/o interest） USD 800 million （with interest）

Construction cost per kW 1,210 USD/kW （w/o interest）

1,340 USD/kW （with interest）

Construction Period 4 years Heat efficiency 38% Heat value of fuel 5,300 kcal/kg Fuel price 90 USD/ton See research assumption Operation term 30 years Price calculation is based on a

15-year term ＜Capital Procurement＞

The assumed leverage ratio is 30% equity and 70% loan. The loan conditions comply with the “Arrangement on officially supported export credits” of OECD, and the assumed interest rate is 6.5%, which includes the 2% country risk of Indonesia. The assumed loan period is 15 years (including a 3-year grace period). Lenders are all assumed to be foreign banks and no domestic banks are included.


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5-2

Table 5.1-2 Finance procurement conditions

Items Assumptions Remarks Equity 30% Loan 70% Interest rate 6.5% Based on OECD Arrangement Loan period 15 years Including a 3-year grace period

＜Weighted Average Capital Costs＞

The Weighted Average Capital Cost (WACC) of a coal-fired IPP project is as shown in the following formula1:

++

+=

DEEr

DEDrWACC ed ** (5.1)

References: rd：Capital Costs for Loan（Interest）

re：Capital Costs for Equity D：Loan amount E；Equity amount

The Capital Costs for Equity may be calculated by various methods and one of the most popular methods is CAPM（Capital Asset Price Model）theory, which makes the Capital Costs for Equity as follows:

)(* fmfe rrrr −+= β (5.2)

rf：Rate of Return of risk-free business rm：Average Rate of Return in the market β：coefficient β of investor

In this Study, participating investors are assumed to be from any country, not limited

to Indonesia or Japan alone. Therefore, the 10-year maturity US Treasury Bond, which has yielded an average of 5% during the last 15 years, is taken as the risk-free business reference. Also, the Average Rate of Return in the market is assumed to be 10% for the 15 years of record (Fig. 5.1-1). Considering the fact that the major participants of IPP projects are power companies, β=1 is applied, assuming the same risk as in the market. Based on these assumptions:

%10%)5%10(*1%5 =−+=er (5.2’)

1 As PrIRR is calculated on an after-tax cash flow basis, the tax factor of (1-t) is omitted in the WACC formula.


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5-3

0.0

2.0

4.0

6.0

8.0

10.0

12.0

92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07

(%)

Average return from FDI (USA) US Treasury bond (10 year) yield JP government bond (10 year) yeild

After factoring in the 2% country risk, we have: re＝12% (5.2”)

This yields the following WACC:

%15.8%30*%12%70*%5.6 =+=WACC (5.1’) ＜Selling Price adequate to recover WACC and Capital Costs Rate for Equity＞

To recover WACC and Capital Costs Rate for Equity, the eligible selling price is calculated. Considerations outlined above lead to an 8.15% WACC, and therefore the Project IRR has to be higher than 8.15%. As for the Capital Costs Rate for Equity, since the above considerations lead to an re, of 12%, the Equity IRR has to be above 12%. Also, the Capital Costs Recovery Period is assumed to be 15 years, in accordance with existing IPP business practices and despite the fact that the actual physical lifespan of power plants exceeds 30 years. The eligible selling price should satisfy the above conditions for Project IRR and Equity IRR over a period of 15 years.

As a result, an adequate selling price would appear to be 7.7 USD Cents/kWh, which yields a 9.0% Project IRR and a 12.1% Equity IRR.

(Source) KOKUSAI Asset Management Co. Ltd.

Fig. 5.1-1 US Treasury bond yield and average return of foreign direct investment in US


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5-4

Commercial risk factor Min Base MaxForeign interest rate during construction 3.3% 6.5% 9.8%Construction Cost 0.80 1.00 1.20Inflation rate after operation (yearly) -2.0% 0.0% 2.0%Exchange rate depriciation in tariff (yearly) -2.0% 0.0% 2.0%

5.2 Risk Analysis ＜Commercial Risk＞

7.7 USD Cents/kWh is shown to be an adequate selling price to recover Project IRR and Equity IRR. However, it may not be sufficient for a healthy business, since this selling price does not take into account commercial risks, technical risks and others. The Study Team proposes to cover these risks by applying a certain risk margin. In practical terms, Project IRR shall be the sum of WACC, a Commercial Risk Margin and a Technical Risk Margin.

RMtRMcWACCIRR ++=Pr (5.3)

References: PrIRR： Project IRR

WACC：as stated before RMc：Commercial Risk Margin RMt：Technical Risk Margin

Typical examples of possible commercial risks for coal-fired IPP projects are interest rate fluctuation during construction, construction cost increases, inflation after commencement of commercial operation, exchange rate fluctuations after commercial operation begins, and so on. Fortunately, the risk of fuel price increases is ignored, as they are passed through to the off-taker.

The previous Section stated that a 7.7 USD Cents/kWh selling price creates a Project IRR of about 9.1% and an Equity IRR of 12.1%. This is based on the assumption that the above-mentioned four risk factors are as for the base case shown in Table 5.2-1 If these risk factors vary between the minimum and maximum figures shown in Table 5.2-1, the Project IRR and Equity IRR change as shown in Fig. 5.2-1 and Fig. 5.2-2, respectively. In particular, the extent of Equity IPP change is greater than that for Project IRR, due to the financial leverage effect.

Table 5.2-1 Assumed variation of risk factors


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5-5

4.0% 5.0% 6.0% 7.0% 8.0% 9.0% 10.0% 11.0% 12.0% 13.0%

Foreign interest rate<9.8%～3.3%>

Construction Cost<1.2～0.8>

Inflation rate after operation<+2.0%～-2.0%>

Exchange rate depriciation inTariff

< -2.0%～+2.0%>

PrIRR(%)

0.0% 5.0% 10.0% 15.0% 20.0% 25.0%

Foreign interest rate<9.8%～3.3%>

Construction Cost<1.2～0.8>

Inflation rate after operation<+2.0%～-2.0%>

Exchange rate depriciation inTariff

< -2.0%～+2.0%>

EqIRR(%)

Fig.5.2-1 Sensitivity analysis of Project IRR to risk factor changes

Fig. 5.2-2 Sensitivity analysis of Equity IRR to risk factor changes

As shown in the figures above, changes in risk factors have a significant impact on the profitability of project. These risk factors can be deemed to be commercial risks. To figure out the appropriate level of Commercial Risk Margin, the Study Team applied the Monte Carlo Method to generate random numbers on the four risk factors and calculated the profitability of the project. For the construction cost, the random number probability is assumed to follow the normal distribution probability curve shown in Fig. 5.2-3. For the inflation rate, the interest rate and exchange rate, the probability of these numbers is truly random, since they are inherently


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5-6

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

0.80 0.82 0.84 0.86 0.88 0.90 0.92 0.94 0.96 0.98 1.00 1.02 1.04 1.06 1.08 1.10 1.12 1.14 1.16 1.18 1.20

Construction cost

Pro

babi

lity

(cum

.)

0.000

0.010

0.020

0.030

0.040

0.050

0.060

0.070

0.080

0.090

Pro

babi

lity

Probability

Probability (cum.)

unpredictable,.

Table 5.2-2 Risk factor evaluation in Monte Carlo Method simulation

Risk Factor Base Case Variation Probability Interest rate 6.5% 3.3%～9.8% at random Construction costs 1.0 0.8～1.2 as in Fig.5.2-3 Inflation after COD 0%（ann.） -2.0%～+2.0% at random Exchange rate after COD 0%（ann.） -2.0%～+2.0% at random

(Note) COD is commercial operation date.

Fig. 5.2-3 Probability of construction costs for Monte Carlo Method simulation

A Monte Carlo Method simulation of 1,000 time trials shows the change of Project IRR in Fig.5.2-4. The Figure shows that the Project IRR varies from 1% to 15%, although it is 9.0% in the base case. The average of Project IPP in this distribution is 8.79% and the standard deviation is 2.53%.

How to evaluate commercial risks and how to address them are subject to management decisions for each project. Therefore, there is no ultimate answer to this question. In this report, the Study Team adopts a Commercial Risk Margin (RMc) of 3% in order to account for a case where each factor takes an unfavorable value. RMc ＝ 3% (5.4)


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5-7

Project IRR

0

20

40

60

80

100

120

140

160

0.01

1%-2%

2%-3%

3%-4%

4%-5%

5%-6%

6%-7%

7%-8%

8%-9%

9%-10

%

10%-11

%

11%-12

%

12%-13

%

13%-14

%

14%-15

%

15%-16

%

16%-17

%

17%-18

%18

%+

Prob

abili

ty

Trial Number = 1000 timesAverage (μ）= 8.79%Standard deviation（σ) = 2.53%WACC = 8.15%Price= 7.70 C$/kWh

Fig.5.2-4 Distribution of Project IRR in Monte Carlo simulation ＜Technical Risk＞

Unlike the geothermal IPP business, the coal-fired IPP business does not have significant technical risks. Thus, the Study Team assumes a Technical Risk Margin (RMt) of 0%.

RMt = 0% (5.5)

＜Expected Rate of Return＞

The above conditions give a Project IRR requirement of 11.2%.

%2.11%3%15.8Pr =+=++= RMtRMcWACCIRR (5.6) Also, the Equity IRR requirement is 12%. EqIRR＝12% (5.7)

The selling price of electricity from a coal-fired IPP business should satisfy these 2 conditions.


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5-8

5.3 Benchmark Price ＜Conditions of Benchmark Price Calculation＞

The selling price of electricity from a coal-fired IPP project (Benchmark Price) is calculated for the conditions shown in Table 5.3-1.

Table 5.3-1 Conditions of benchmark price calculation

Items Specifics

Depreciation period Generation machines and equipment: 16 years

Depreciation method Double declining balance method Tax rate Corporate tax: 25% (from 2010)

Withholding tax on dividends: 10% Tax incentive 5 years loss carry forward

＜Benchmark Price＞

Table 5.3-2 and Fig. 5.3-1 show the selling price calculation results of each coal price. Coal price increase pushes up the selling price, and with 90 USD/ton coal the price is estimated to be 8.2 USD Cents/kWh. Table 5.3-3 and Table 5.3-4 show the income statement and the cash flow statement of this project at this price. Table 5.3-3 also shows Project IRR while Table 5.3-4 shows Equity IRR.

Price of Benchmark coal-fired IPP project （Coal Price 90 USD/ton） 8.2 USD cents/kWh

Table 5.3-2 and Fig. 5.3-1 indicate that, due to recent fuel price hikes, coal-fired power generation is no longer the inexpensive power source that it was in the past.


JICA West JEC

5-9

Coal PriceInitial

CapitalCost

Fuel Cost O&M Cost Interest Sub total Tax Return forInvestment

SellingPrice

36 1.0 1.8 0.7 0.4 3.9 0.5 1.2 5.545 1.0 2.2 0.7 0.4 4.3 0.5 1.2 6.054 1.0 2.7 0.7 0.4 4.8 0.5 1.2 6.463 1.0 3.1 0.7 0.4 5.2 0.5 1.2 6.972 1.0 3.6 0.7 0.4 5.7 0.5 1.2 7.381 1.0 4.0 0.7 0.4 6.1 0.5 1.2 7.890 1.0 4.4 0.7 0.4 6.6 0.5 1.2 8.299 1.0 4.9 0.7 0.4 7.0 0.5 1.2 8.7

108 1.0 5.3 0.7 0.4 7.5 0.5 1.2 9.1117 1.0 5.8 0.7 0.4 7.9 0.5 1.2 9.5126 1.0 6.2 0.7 0.4 8.3 0.5 1.2 10.0135 1.0 6.7 0.7 0.4 8.8 0.5 1.2 10.4

0.0

2.0

4.0

6.0

8.0

10.0

12.0

36 45 54 63 72 81 90 99 108 117 126

Coal price (US$/ton)

Sel

ling

pric

e of

coa

l-fire

d IP

P p

roje

ct (c

$/kW

h)

Initial Capital Cost Fuel Cost O&M Cost Interest Tax Return for Investment

Table 5.3-2 Selling price for coal-fired IPP project (Benchmark Price) （Unit: Coal Price: USD/ton, Electricity Selling Price: USD Cents/kWh）

Fig. 5.3-1 Selling Price for coal-fired IPP project (Benchmark Price)

Stud

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Fis

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h）W

ACC

of P

roje

ct:

Pow

er P

lant

Pro

ject

F.I.

R.R

.11

.2%

INV

ESTM

EN

TR

EVE

NU

EC

OST

S

INV

ESTM

ENT

Tabl

e 5.

3-3

Inco

me

Stat

emen

t of c

oal-f

ired

IPP

proj

ect

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

Geo

ther

mal

Ene

rgy

Dev

elop

men

t in

the

Rep

ublic

of I

ndon

esia

Fina

l Rep

ort

JIC

A

Wes

t JEC

5-

11

IRR

on

Equ

ity

(aft

Tax,

aft

Int)

17.9

%

Ta

ble

Cas

h flo

w o

f Pow

er P

lant

Pro

ject

[Mill

ion

US

$]C

ash

Inflo

wC

ash

Out

flow

Bal

ance

No.

Initi

al

Rep

aym

ent

Per

Tota

lYe

arE

BIT

Inte

rest

Tax

Pro

fitIn

itial

Inv.

Inve

stm

ent

Cap

ital

Tota

lYe

arA

ccum

ulat

e1

23

45

67

89

1011

1213

14[3

2.5

%]

[2-3

-4]

[1+5

+6+7

][9

+10+

11]

[8-1

2]年

借入

金営

業活

動Ｃ

Ｆ合

計初

期投

資元

本返

済合

計年

累計

No

営業

利益

支払

利子

税営

業利

益当

初投

資

　（税

引前

）(税

後、

利払

後)

　　

　

1

　

　

　

　

　

　

　

　

　

2

　

　

　

　

　

　

　

　

　

3

　

　

　

　

　

　

　

　

　

4

51.6

6

　

3.

36

　

-3.3

6　

48

.31

69

.30

　

69.3

0

-2

0.99

-20.

995

167.

77

　

14

.26

　

-14.

26　

15

3.51

220.

82

　

22

0.82

-67.

31-8

8.30

6

22

9.72

　

29.1

9

　

-2

9.19

　

200.

52

29

0.43

　

290.

43

-8

9.91

-110

.90

7

13

4.91

　

37.6

8

　

-3

7.68

　

97.2

214

5.53

4.31

14

9.84

-52.

61-1

63.5

28

1　

59

.68

36.5

0

　

23

.19

75.5

6

98

.75

　

18.2

9

18

.29

80.4

6-8

3.05

9

2

　

69.1

9

34

.06

　

35.1

366

.12

101.

25　

37

.43

37.4

363

.82

-19.

2310

3　

77

.51

30.9

0

12

.36

34.2

457

.86

92.1

1　

48

.67

48.6

743

.43

24.2

011

4　

84

.79

27.7

4

18

.54

38.5

150

.63

89.1

4　

48

.67

48.6

740

.47

64.6

712

5　

91

.16

24.5

7

21

.64

44.9

444

.31

89.2

5　

48

.67

48.6

740

.58

105.

2513

6　

92

.32

21.4

1

23

.05

47.8

643

.19

91.0

5　

48

.67

48.6

742

.38

147.

6414

7　

92

.36

18.2

4

24

.09

50.0

343

.19

93.2

2　

48

.67

48.6

744

.55

192.

1815

8　

92

.41

15.0

8

25

.13

52.2

043

.18

95.3

8　

48

.67

48.6

746

.71

238.

8916

9　

92

.46

11.9

2

26

.18

54.3

743

.18

97.5

4　

48

.67

48.6

748

.87

287.

7617

10　

92

.51

8.75

27

.22

56.5

343

.18

99.7

1　

48

.67

48.6

7

51

.04

338.

8018

1192

.55

5.59

28

.26

58.7

043

.18

101.

87　

48

.67

48.6

7

53

.20

392.

0019

1292

.59

2.71

29

.21

60.6

743

.18

103.

85　

44

.37

44.3

7

59

.48

451.

4820

1392

.63

0.73

29

.87

62.0

443

.18

105.

21　

30

.39

30.3

9

74

.82

526.

3121

1492

.68

　

30.1

2

62

.56

43.1

8

10

5.73

　

11.2

4

11

.24

94.4

962

0.80

22

15

128.

02

　

41

.61

86.4

17.

84

94.2

6　

　

　

94

.26

715.

0523

1613

5.81

　

44.1

4

91

.67

0.05

91

.72

　

　

　

91

.72

806.

7824

1713

5.81

　

44.1

4

91

.67

0.05

91

.72

　

　

　

91

.72

898.

5025

1813

5.81

　

44.1

4

91

.67

0.05

91

.72

　

　

　

91

.72

990.

2226

1913

5.81

　

44.1

4

91

.67

0.05

91

.72

　

　

　

91

.72

1,08

1.94

27

20

135.

81

　

44

.14

91.6

7

0.

05

91.7

2

　

　

　

91.7

21,

173.

6728

2113

5.81

　

44.1

4

91

.67

0.05

91

.72

　

　

　

91.7

21,

265.

3929

2213

5.81

　

44.1

4

91

.67

0.05

91

.72

　

　

　

91.7

21,

357.

1130

2313

5.81

　

44.1

4

91

.67

0.05

91

.72

　

　

　

91.7

21,

448.

8331

2413

5.81

　

44.1

4

91

.67

0.05

91

.72

　

　

　

91.7

21,

540.

5632

2513

5.81

　

44.1

4

91

.67

0.05

91

.72

　

　

　

91.7

21,

632.

2833

2613

5.81

　

44.1

4

91

.67

0.05

91

.72

　

　

　

91.7

21,

724.

0034

2713

5.86

　

44.1

5

91

.70

0.00

91

.71

　

　

　

91.7

11,

815.

7135

2813

5.86

　

44.1

5

91

.71

　

91.7

1　

　

　

91

.71

1,90

7.41

36

29

135.

86

　

44

.15

91.7

1　

91

.71

　

　

　

91.7

11,

999.

1237

3013

5.86

　

44.1

5

91

.71

　

91.7

1　

　

　

91

.71

2,09

0.83

584.

063,

380.

2132

2.69

999.

422,

058.

1069

1.50

0.00

3,33

3.66

726.

080.

0058

4.06

1,31

0.14

2,02

3.52

2,09

0.83

Tota

l

減価

償却

Bor

row

ing

Cas

h Fl

ow fr

om O

pera

ting

Act

iviti

esD

epre

ciat

ion

Tabl

e 5

.3-4

Cas

h Fl

ow S

tate

men

t of c

oal-f

ired

IPP

proj

ect


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5-12

＜Policy to off-take at a price of 80%0 of BPP (PT PLN production costs in a grid)＞ As mentioned in Section 3.4, the Minister of Energy and Mineral Resources

Regulation No.14 of 2008 obliges PT PLN to purchase power from geothermal IPP projects at a ceiling price equivalent to 80%-85% of BPP (Biaya Pokok Produksi: Main Cost of Production). However, this system has been criticized for various reasons, such as the insufficient transparency of the BPP calculation method, the lack of consideration of geothermal resource distribution and the unsuitable price levels that it yields. In fact, as shown in Table 3.5-2 in Chapter 3, reasonable prices are available with small grid systems, but these small grid systems can hardly attract private investors, due to their small market size. On the other hand, for grid systems with a large capacity, only quite cheap prices are available, e.g. 4.50 USD Cents/kWh for Sumatra and 5.59 USD Cents/kWh for Java-Bali.

Therefore, the BPP price needs to be reevaluated as soon as practicable. This study applies the selling price calculated in this Section as a Benchmark Price, since the BPP price is not suitable as a Benchmark Price.

CHAPTER 6

EVALUATION OF A GEOTHERMAL IPP

PROJECT


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6-1

CHAPTER 6 EVALUATION OF A GEOTHERMAL IPP PROJECT 6.1 Assumptions

This Chapter aims to calculate the selling price of electricity generated by a

geothermal IPP project. The calculations are based on the following assumptions: ＜Specifications of Geothermal IPP project＞

Geothermal power generation uses steam heated and stored in a reservoir underground. Therefore, the generation capacity has to be in line with the size of geothermal reservoir. Also, its economic aspects are site-specific. However, for simplicity purposes, the Study Team has chosen a 60 MW capacity, in stead of the common 55 MW capacity, for the model geothermal IPP project because it can easily be compared with the benchmark coal-fired IPP project, which has a capacity of 600 MW.

One of the major hurdles in compiling a model geothermal power project is the unavailability of steam well data. There are some well depth data for existing geothermal power plants in the Center for Geothermal Resources (CGR) of MEMR, but other precise data, such as data concerning steam production ability per well or drilling costs, has not yet been compiled. Therefore, the model geothermal power plant is elaborated based on data publicly available in Japan and many other assumptions.

Major characteristics of the model case are as shown in Table 6.1-1.

Table 6.1-1 Specification of geothermal IPP project

Items Specifications Remarks

Capacity 60 MW １unit Construction costs USD 180 million

（w/o interest） USD 190 million （with interest）

Construction costs per kW 3,010 USD/kW （w/o interest）

3,170 USD/kW （with interest）

Construction period 6 years Production well depth 2,000 m Production well steam output 8 MW/well Generation efficiency 7.0 t/h/MW Operation term 30 years Price calculated based on

15 year term Make up wells One every 5 years


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6-2

Lead Time Development Stage Activity Finance

2 Years

2 Years

2 Years

30 Years

Surface Survey Stage

Resource Confirmation Stage

Construction Stage

Development Stage(Reservoir Evaluation Stage)

Operation Stage

Development Process of 60 MW Model Case

Surface survey (Geology,Geochemical, Geophysics MT, etc)

To Find steam (Approximately 10%)Drilling 2 wells →　1 well success

To confirm 40% of steam,Drilling 3 wells →　2 well success

To obtain 100% steam,Drilling 8 wells →　6 well success

Equity 100%

Equity 30% Debt 70%

Equity 100% Debt 0%

Equity 100%

Operation & Maintenance Expenditure

＜Process of Geothermal Development＞ The following process is assumed: - Surface survey - Resource confirmation survey: 2 years - Development（Resource evaluation）: 2 years - Construction: 2 years （ Total development lead time）: （6 years） - Commercial Operation: 30 years

Fig. 6.1-1 Geothermal development process for 60 MW plant


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6-3

0

10

20

30

40

50

60

70

80

-6 -5 -4 -3 -2 -1

Lead Time (Year)

Annual

Inve

stm

ent

(m$)

0

20

40

60

80

100

120

140

160

180

200

Cum

ula

tive

Inve

stm

ent

(m$)

Annual Investment Cumulative Investment

ConstructionDevelopment

(Reservoir Eva.)Surface Svy. &Resource Conf.

Fig. 6.1-2 Up-front investment amount estimation for 60 MW geothermal power plant

(a) Surface survey Geological survey from ground surface.

(b) Resource confirmation: Exploratory wells will be drilled to confirm the existence of the resource. This

model assumed 1 success out of 2 exploratory drills. The well that confirmed the resource existence will be used as a production well. 2 years is assumed for this stage.

(c) Development（Resource evaluation survey） Further exploratory wells will be drilled to evaluate the capacity of resource. This model assumes 2 successes out of 3 exploratory drills. Together with the production well developed during the resource confirmation stage, this will provide a total of 3 production wells to be used in the operation stage. This process requires 2 years.

(d) Construction Once the feasibility study for the geothermal IPP project is complete, a construction plan will be drawn up and will be ready for financial close. The construction will be conducted with 30% equity and 70% loan in this stage. The model assumes that 8 further drillings will yield 6 more production wells. Steam pipelines, power plant and other equipment will also be constructed concurrently. The construction period is assumed to be 2 years.

＜Finance Procurement Conditions＞

Geothermal energy development involves significant risks during the surface survey, resource confirmation and development stages. Since a project has little chance of obtaining financial support in the early stages, its early stage development may need to be conducted with


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6-4

equity alone. After a certain level of progress, the project can acquire funding from banks, leveraged with a ratio of 70% debt to 30% equity .

In accordance with “Arrangement on officially supported export credits” of OECD, the interest rate is assumed to be 6.5%, as for the model coal-fired IPP project. This rate includes a 2% country risk factor. The loan period is 15 years. Since the assumed investors are foreign investors, no domestic banks participate as lenders.

Table 6.1-2 Finance procurement condition

Development Stage Equity Loan Surface survey, Resource confirmation survey

100% ―

Development 100% ― Construction 30% 70%

Interest rate 6.5% Loan period 15 years Grace period 3 years (included

in Loan period) ＜WACC＞

The WACC of the geothermal IPP project is calculated as follows1:

++

+=

DEEr

DEDrWACC ed ** (6.1)

References: rd：Capital Costs for Loan（Interest）

re：Capital Costs for Equity D：Loan amount E；Equity amount

Note: Ｅ＝Ｅ1+Ｅ2+Ｅ3

Ｅ1：Equity to cover early stage survey Ｅ2：Equity to cover development stage Ｅ3：Equity to cover construction stage

As for the model geothermal IPP project, CAPM theory is applied to Capital Costs for Equity. CAPM gives as follows:

1 The tax factor is also omitted as for the model coal-fired power plant.


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6-5

Rec. - Explanatory Confirmation Construction

Equity 13.8 21.2 43.7 78.7 43.6%Debt 102.0 102.0 56.4%Total 13.8 21.2 145.7 180.7 100.0%

<7.6%> <11.7%> <80.6%> <100.0%>MONEY COST

Equity 17.0% 17.0% 17.0%Debt 6.5%

WACC Total 1.3% 2.0% 7.8% 11.1%

Development cost(m$)

Total

)(* fmfe rrrr −+= β (6.2)

rf：Rate of Return of risk-free business rm：Average Rate of Return of market β：coefficient β of investor

As for the model geothermal IPP project, the Rate of Return of risk-free business is

assumed to be 5%, which equals the yield of the 15-year average return on 10-year maturity US treasury bonds. The Average Rate of Return of the market is assumed to be 10%, based on the record of a 15-year average of returns on foreign investment in the US. β is assumed to be 2, in consideration of the higher risk-higher return nature of geothermal IPP projects compared to coal-fired ones.

%15%)5%10(*2%5 =−+=er (6.2’)

Incorporating the 2% country risk, as in the case of interest yields:

re＝17% 2 (6.2”) This result yields the WACC shown in Table6.1-3,

%1.11=WACC (6.1’) Table 6.1-3 WACC of geothermal IPP project

2 17% is also used for Capital Cost for Equity in Brandon Owens (2002)


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6-6

6.2 Risk Analysis ＜Commercial Risk＞

Prior to the calculation of the selling price, Project IRR requirement needs to be determined. Like the coal-fired IPP project, Project IRR shall be calculated as follows:

RMrRMcWACCIRR ++=Pr (6.3)

PrIRR： Project IRR WACC：Weighted Average Capital Costs RMc： Commercial Risk Margin RMr： Resource Development Risk Margin Commercial Risk Margin should be the same as for the coal-fired IPP project: RMc ＝ 3% (6.4) ＜Resource Development Risk＞

Geothermal energy development involves various kinds of risks since it is a development of underground resources. The major risks of a geothermal IPP project are as follows:

(a) Survey stage cost overruns due to; －Access road construction difficulty －Survey difficulty due to geographical problems －Unfavorable drilling success rate, etc.

(b) Development stage cost overruns due to; －Depth of production wells －Capacity of production wells

－Characteristics of steam and hot water, uncondensed gas concentration －Production well drilling success rate －Construction material price increases, etc.

(c) Operation stage degradation of performance due to: －Decline in steam, etc.

In order to evaluate these risks, as for the model coal-fired IPP project, the Study Team has calculated a selling price which is sufficient to recover the WACC and commercial risks. Project IRR has to be above 14.1% since the WACC is 11.1% and the Commercial Risk Margin


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6-7

Well Depth Range

-

500

1,000

1,500

2,000

2,500

3,000

3,500

Well

Dept

h (

m)

Average 1,400 2,040 2,480 1,960 2,120 2,210

Field A Field B Field C Field D Field E Field F

0

1

2

3

4

5

1,400-1,800 1,800-2,200 2,200-2,600

Average depth of production wells (m)

Num

ber o

f geo

ther

mal

fiel

ds

6 Geothermal power plants Average 2,035 m Standard deviation 359 m

is 3%. Equity IRR has to be above 17% since the cost of equity is 17%. The evaluation period is 15 years, the as same as for the model coal-fired IPP project. A selling price adequate to satisfy these 2 conditions is calculated to be 9.9 USD Cents/kWh. At this price, Project IRR is 14.1% and Equity IRR is 20.5%.

The risk factors deemed to have significant impact, namely the production well depth, steam production of wells, steam/hot water ratio, and construction costs will be evaluated. It is true that today’s sophisticated surface survey technology estimates these factors with a certain accuracy. However, reliable confirmation still relies on actual data from exploratory drilling. Sometimes the results of drilling fail to fulfill the estimation of surface surveys.3

(a) Production well depth Fig. 6.2-1 and Fig. 6.2-2 indicate the average for and variation in production well depth for six major geothermal power plants in Indonesia. As shown here, the depth of production wells varies from 1,000 m to 2,500 m. Even the same project site has production wells of different depths. Depth has a significant impact on drilling costs. Therefore, when the actual depth is deeper than expected, drilling costs will increase and the profitability of the project will decrease.

Fig. 6.2-1 Well depth variation in Indonesia Fig. 6.2-2 Distribution of production well depth in Indonesia

(b) Steam production of wells

Fig. 6.2-3 shows the average production per well for twelve major Japanese geothermal power plants. This figure shows that capacity varies from 1.5 MW to 7.0 MW with an average of around 4 MW to 5 MW. Indonesia has wells with a bigger capacity than Japan.

3 According to Deloitte (2008), the success rate of drilling is 50% in exploration drilling, 80-90% in initial drilling,

and 90-100% in production drilling.


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6-8

Average Power per One Well

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

0.0 20.0 40.0 60.0 80.0

Authorized Rated Output of Power Plant (MW)

Avera

ge P

ow

er

per

One

Well

(MW

)

0

1

2

3

4

5

1-2 2-3 3-4 4-5 5-6 6-7 7-8 8+

Average output per well (MW/Well)

Num

ber

of g

eoth

erm

al p

ower

pla

nts 12 Geothermal power plants

(larger than 20 MW)Average 4.4 MW/wellStandard deviation 1.4 MW/well

The average steam production per well is around 6 MW to 9 MW, and some even exceed 10 MW. For this model case 8 MW was specified as the average steam production per well. Although the steam production of wells has a significant impact on the profitability of a geothermal IPP project, it is difficult to precisely assess this production capacity in the early stages. Therefore, when the actual steam production proves to be smaller than expected, increased construction costs will be necessary to procure sufficient steam.

Fig. 6.2-3 Average steam production per well Fig. 6.2-4 Distribution of average steam production in Japan per well in Japan

(c) Steam/Water ratio

Production wells produce steam and hot water. Hot water is re-injected back into the ground for resource conservation purposes. However, an increase in the amount of hot water requires more drilling of re-injection wells, which reduces the profitability of the project. The model case assumes a steam/water ratio of 1:1. Fig. 6.2-5 shows the distribution of the steam/water ratio of wells in Japan. Apparently, the ratio varies for each location. The situation is same in Indonesia. For example, the Kamojang field produces only steam (a steam-dominated field), the Salak field produces a mixture of steam and water (30% steam and 70% water). while the Wayang Windu field produces a mixture of 70% steam and 30% water.

(d) Construction Costs

There are many other unknown technical factors in the development of geothermal power plants. This model integrates these factors into the variation in construction costs.


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6-9

0

1

2

3

4

0-1 1-2 2-3 3-4 4-5 5-6 6-7 7+

Average steam/water ratio (MW/Well)

Num

ber

of g

eoth

erm

al p

ower

pla

nts

12 Geothermal power plants (larger than 20 MW) Average 2.8 Standard deviation 2.2

Technical risk factor Min Base MaxWell Depth 1,500m 2,000m 2,500mSteam Production 6.0 MW 8.0 MW 10.0 MWSteam/Water ratio 0 1 2Construction Cost 0.8 1.0 1.2

10.0% 11.0% 12.0% 13.0% 14.0% 15.0% 16.0% 17.0% 18.0%

Well Depth<1,500m ～ 2,500m>

Steam Production<6MW ～10MW>

Steam/Water ratio<0～2>

Construction Cost<0.8 ～1.2>

PrIRR(%)

Fig. 6.2-5 Distribution of steam/water ratio of wells in Japan

As stated before, 9.9 USD Cents/kWh emerged as an adequate selling price to satisfy the WACC and the Equity Rate of Return, considering the commercial risk over 15 years, but this is the base case. When these 4 risk factors vary as shown in Table 6.2-1, Project IRR will be influenced as shown in Fig. 6.2-6 and Equity IRR, as shown in Fig. 6.2-7.

Table 6.2-1 Assumed variation in risk factors

Fig. 6.2-6 Analysis of Project IRR Sensitivity to risk factor changes


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6-10

15.0% 16.0% 17.0% 18.0% 19.0% 20.0% 21.0% 22.0% 23.0% 24.0% 25.0%

Well Depth<1,500m ～ 2,500m>

Steam Production<6MW ～10MW>

Steam/Water ratio<0～2>

Construction Cost<0.8 ～1.2>

EqIRR(%)

Fig. 6.2-7 Analysis of Equity IRR Sensitivity to risk factor changes

As shown above, changes in risk factors will have significant impact on the project profitability. These can be deemed to be the technical risks of a geothermal IPP project. In order to figure out an eligible Resource Development Risk Margin, the Study Team applied the Monte Carlo Method to generate random representations of these risk factors. In doing so, the probabilities of random numbers regarding well depth, steam production and construction costs were deemed to follow the normal distribution probability curve. The probability of the steam/water ratio is deemed to remain constant. The probability of production well depth is assumed to be as shown in Fig. 6.2-8 (a). The probability of steam production per well is as shown in Fig. 6.2-8 (b). The probability of the steam/water ratio is as shown in Fig. 6.2-8 (c). The probability of construction costs is as shown in Fig.6.2-8 (d). These probability curves are constructed with reference to data from Japan and from Indonesia.

Table 6.2-2 Risk factor evaluation by Monte Carlo Method simulation

Risk Factor Base Case Variation Probability Well depth 2,000 m 1,000 m - 3,000 m Fig. 6.2-8 (a) Steam production 8.0 MW 1.6 MW - 14.4 MW Fig. 6.2-8 (b) Steam/water ratio 1.0 0.0 – 6.0 Fig. 6.2-8 (c) Construction costs 1.0 0.8 - 1.2 Fig. 6.2-8 (d)


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6-11

Well depth probability distribition assumption

0.000

0.100

0.200

0.300

0.400

0.500

0.600

0.700

0.800

0.900

1.000

1,00

01,10

01,20

01,30

01,40

01,50

01,60

01,70

01,80

01,90

02,00

02,10

02,20

02,30

02,40

02,50

02,60

02,70

02,80

02,90

03,00

0

Depth (m)

Pro

babi

lity

(cum

.)

0.000

0.020

0.040

0.060

0.080

0.100

0.120

Pro

babi

lity

Probability Probability (cum.)

Normal distribution μ=　2,000m σ=　　400m

Average well output probability distribition assumption

0.000

0.100

0.200

0.300

0.400

0.500

0.600

0.700

0.800

0.900

1.000

1.60

2.24

2.88

3.52

4.16

4.80

5.44

6.08

6.72

7.36

8.00

8.64

9.28

9.92

10.56

11.20

11.84

12.48

13.12

13.76

14.40

Average well output (MW/well)

Pro

babi

lity

(cum

.)

0.000

0.020

0.040

0.060

0.080

0.100

0.120

Pro

babi

lity


Normal distribution μ=　8.0 MW/well σ=　2.5 MW/well

Construction cost change distribition assumption

0.000

0.100

0.200

0.300

0.400

0.500

0.600

0.700

0.800

0.900

1.000

0.80 0.82 0.84 0.86 0.88 0.90 0.92 0.94 0.96 0.98 1.00 1.02 1.04 1.06 1.08 1.10 1.12 1.14 1.16 1.18 1.20

Construction cost change

Pro

babi

lity

(cum

.)

0.000

0.010

0.020

0.030

0.040

0.050

0.060

0.070

0.080

0.090

Pro

babi

lity


Normal distribution μ=　1.0 σ=　0.2

Steam water ratio probability distribition assumption

0.000

0.100

0.200

0.300

0.400

0.500

0.600

0.700

0.800

0.900

1.000

0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50 5.00 5.50 6.00

Steam water ratio

Pro

babi

lity

(cum

.)

0.000

0.010

0.020

0.030

0.040

0.050

0.060

0.070

0.080

0.090

0.100

Pro

babi

lity


Random distribution p = 0.077

(a) Well depth (b) Steam production (c) Steam/water ratio (d) Construction cost

Fig. 6.2-8 Probability of risk factors for Monte Carlo Method simulation

Base on these conditions, we have conducted 1,000 Monte Carlo Method simulations. The distribution of Project IRR is shown in Fig. 6.2-9. This result indicates that Project IRR varies from less than 5% to more than 22.0%, although it is 14.1% when all the risk factors remain as for the base case. This wide variation in Project IRR is the resource development risk. The average of distribution is 12.9%, which is slightly smaller than the base case. The standard deviation is 2.97%.


JICA West JEC

6-12

0

20

40

60

80

100

120

140

160

-5% 5%-6%

6%-7%

7%-8%

8%-9%

9%-10%

10%-11%

11%-12%

12%-13%

13%-14%

14%-15%

15%-16%

16%-17%

17%-18%

18%-19%

19%-20%

20%-21%

21%-22%

22%+

Prob

abilit

y (T

imes

/100

0 tim

es tr

ial)

Number of Trials = 1000 timesPrice = 9.9 c$/kWh,WACC = 11.1%Target FIRR = 14.1%

Average (μ）= 12.9%Standard deviation（σ) =2.97%

Fig. 6.2-9 Distribution of Project IRR in Monte Carlo Method simulation ＜Resource Development Risk Countermeasures for Geothermal IPP Projects＞

The resource Development Risk for a geothermal IPP project is essentially inevitable. , The following countermeasures may be appropriate to reduce these risks (Fig. 6.2-10).

(a) Risk Premium (Risk Margin)

As with the commercial risk, a certain level of risk premium (Resource Development Risk Margin) should be allowed for. This risk premium helps the project to maintain some economical viability, even if the risk is triggered. In short, this measure aims to compensate risks with rewards. Although the level of risk premium needs further detailed consideration, this measure is deemed to be effective in practice. The model case in this Chapter makes use of this measure.

(b) Risk mitigation through initial survey by government

The level of risk which public investors can take is limited. Therefore, a body that can bear greater risk, i.e., the government, is expected to take responsibility for the initial surveys to reduce the resource development risk. Most of the developers we had interviews with were of the opinion that they would not bear the green-field risks of geothermal development. Therefore, the involvement of a government body in the early stage to develop the green-field to brown-field status is effective in attracting more investors to geothermal IPP projects. This will be further discussed in Chapter 8 and Chapter 9.

(c) Risk mitigation through multi-location development

It is known that the average of “n” number of samples out of a random distribution comes


JICA West JEC

6-13

close to the normal distribution with 1/√n of standard deviation from the original random distribution. This means that developments in 4 locations will reduce the risk by 1/2 and in 9 locations by 1/3. This is risk dilution by multi-location development. If PT Pertamina can carry out this sort of multi-location development, the resource development risk for PT Pertamina will be reduced accordingly. Through this measure, PT Pertamina will become a reliable steam supplier, and private companies will be able to buy steam from PT Pertamina, generate electricity with it, and sell the electricity to PT PLN. Under such a scheme, private companies will be able to focus on the energy conversion projects and will not be troubled by resource development risks. The Philippines adopted this scheme and successfully developed geothermal power plants in the 1990s. The same scheme can be applicable in Indonesia as well. This will be discussed again in Chapter 9.

(d) Risk Pass-Through Policy

One of the biggest risks of coal-fired IPP projects is future increases in fuel prices. However, coal-fired IPP projects remove this risk by passing it through to the off-taker (PT PLN). Geothermal IPP projects may consider adopting similar measures. For example, the Ministry of Energy and Mineral Resources (MEMR) can form a Third-Party Committee to analyze the development costs of each geothermal project and to mediate cost negotiations between a geothermal IPP and PT PLN. Establishment of such measures may be a long shot, but is worth considering.

This Chapter makes use of a risk premium measure known as the Resource Development Risk Margin (RMr). The RMr adopted here is 3%, taking into consideration the standard deviation of the distribution in Fig. 6.2-9. RMr ＝ 3% (6.5) ＜Internal Rate of Return＞

The Project IRR required for a geothermal IPP project is 17.1%, as shown in the formula below: %1.17%3%3%1.11Pr =++=++= RMrRMcWACCIRR (6.6) On the other hand, Equity IRR is required to be greater than 17%. EqIRR = 17% (6.7) The selling price of electricity from a geothermal IPP project should satisfy both of these conditions.


JICA West JEC

6-14

SurveyEffect

Improvement of Uncertaininty by Governmental Preliminary Survey

Distribution of "Mother Group" Average = μ Standard deviation = σ

Distribution of "Sample of n" Average = μ Standard deviation = σ/√n

PortofolioEffect

X1 Xn

XiX2Y=(X1+X2+.....+Xn)/n

Riskpremium

Risk should be rewarded by profit.Risk premium may improve profitability of the project.

Profitable line

X Field Price = PxY Field Price = Py

Independent third-party "Geothermal Price ArbitrationBoard" will decide buying price based on the actual data.

Passthrough

PLN X Field Price = Px Y Field Price = PyX Field

Y Field

(a) Risk Premium Countermeasure (b) Risk mitigation through initial survey by a government body (c) Risk mitigation through multi-location development (d) Risk ”Pass Through” structure for geothermal energy

Fig. 6.2-10 Risk countermeasures in geothermal energy development


JICA West JEC

6-15

6.3 Selling Price of Electricity from Geothermal IPP Project ＜Assumptions for calculations＞

The Table 6.3-1 shows the assumptions to calculate the selling price of electricity from a geothermal IPP project. These assumptions are based on the current tax regulations. An eight-year depreciation period and tax incentives have applied to geothermal plants since 2008.

Table 6.3-1 Assumptions for calculation of Geothermal Price

Items Specifications

Depreciation period Wells : 8 years Generation machines and equipment: 8 years (Originally category –III applies to geothermal plants, but category –II can apply as a tax incentive since 2008.)

Depreciation method Double declining balance method Tax rate Corporate tax: 25% (From 2010)

Withholding tax on dividends: 10% Tax incentives 1. 7 years loss carry forward

2. 30% Investment Allowance (5% per ann., 6 years) ＜Price Calculation＞

The above assumptions yield a selling price of 11.9 USD Cents/kWh. This price brings about Project IRR of 17.1% and Equity IRR of 23.8% . The income statement and the cash flow statement for this project at this price are as shown in Table 6.3-2 and Table 6.3-3. Note that Table 6.3-2 also shows Project IRR, while Table 6.3-3 shows Equity IRR.

Electricity price of Geothermal IPP project 11.9 USD Cents/kWh

There is a 3.7 USD Cents/kWh difference between this price and the price for the

benchmark coal-fired IPP project, which is 8.2 USD Cents/kWh. The objective of this Study is to bridge this price gap by fiscal incentives.

Price for Geothermal IPP project 11.9 USD Cents/kWh Price for Benchmark Coal-fired IPP project 8.2 USD Cents/kWh Price Gap 3.7 USD Cents/kWh

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

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ate

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ate

Sect

or

Geo

ther

mal

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rgy

Dev

elop

men

t in

the

Rep

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of I

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JIC

A

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6-

16

Tabl

e

Prof

it &

Los

s an

d FI

RR

of T

otal

Dev

elop

men

t Pro

ject

[Mill

ion

US

$]

OU

TPU

TS

ALE

SN

ET

INC

OM

EIN

TER

ES

TTA

XN

ET

INC

OM

EC

ASH

FLO

W

by N

EW P

LAN

TN

o. o

f

No.

Year

MW

GW

H S

ALE

Supp

lem

.SU

PPLM

.TO

TAL

SAL

ESO

ther

C

DM

TOTA

LO

PER

INT.

INV.

SU

P. W

ELL

Surv

eyFi

xed

Ass

et

Roy

alty

TOTA

LN

ET

[A

fter T

ax]

FREE

Tota

lTo

tal

Wel

lsIN

VE

ST.

INV

EST.

REV

EN

UE

Rev

enue

RE

VEN

UE

RE

VEN

UE

CO

ST

DE

PN.

DE

PN.

Fee

Tax

EXP

EN

SE

SIN

CO

ME

CA

SH

FLO

W1

23

45

67

89

1011

1213

14　

[2+3

]5.

15.

2[6

+7+8

][5

-9]

[10-

12]

[-4+7

+8+1

3][G

Wh]

　[5

M$/

wel

l]11

.88

$/kW

h[0

.7 ￠

/kW

h]　

　[3

2.5

%]

Trai

ffEs

c.In

tere

stC

DM

Pric

e E

sc.

運転

期間

出力

売電

(受電

端）

初期

投資

追加

井追

加井

投資

0.0%

Supp

lem

ent

0 $/

t 0.

0%初

期投

資追

加井

促進

調査

固定

資産

税ロ

イヤ

ルテ

ィ費

用営

業利

益支

払利

子税

営業

利益

ﾌﾘｰ

ｷｬｯｼｭﾌﾛｰ

全体

[MW

][G

Wh]

　本

数投

資合

計売

電収

入利

子補

給C

DM

収入

営業

収入

合計

運転

経費

減価

償却

減価

償却

特別

費用

合計

（税

前,利

払前

)（税

後,利

払前

）(F

or P

roje

ct IR

R

1#

　

　

　

　

0.

002

#

6.36

　

　

6.36

　

-6.3

6 3

#

7.42

　

　

7.42

　

-7.4

2 4

#

9.28

　

　

9.28

　

-9.2

8 5

#

11.9

3

　

　

11.9

3

　

-11.

93

6#

70

.96

　

　

70

.96

　

3.44

-7

0.96

7

#

74.7

2

　

　

74.7

2

　

7.

27

-74.

72

81

60

444.

66

　

　

　

52

.83

52

.83

3.

31

28

.58

　

0.

13

1.32

33

.33

19.4

97.

27

19.4

948

.07

92

60

444.

66

　

　

　

52

.83

52

.83

3.

31

21

.47

　

0.

10

1.32

26

.20

26.6

26.

98

2.42

24.2

145

.67

103

60

444.

66

　

　

　

52

.83

52

.83

3.

31

19

.09

　

0.

09

1.32

23

.81

29.0

26.

38

4.42

24.6

043

.68

114

60

444.

66

　

　

　

52

.83

52

.83

3.

31

19

.08

　

0.

07

1.32

23

.78

29.0

55.

77

4.63

24.4

243

.50

125

60

444.

66

　

1.

09

5.45

5.45

52

.83

52

.83

3.

31

19

.07

　

0.

05

1.32

23

.75

29.0

75.

17

4.83

24.2

437

.85

136

60

444.

66

　

　

　

52

.83

52

.83

3.

31

19

.06

0.68

0.03

1.

32

24.4

0

28

.42

4.56

4.

82

23

.60

43.3

414

760

44

4.66

　

　

　

52.8

3

52.8

3

3.31

19.0

5

0.

68

0.

01

1.32

24

.38

28.4

53.

95

7.96

20.4

940

.22

158

60

444.

66

　

　

　

52

.83

52

.83

3.

31

7.

21

0.68

0.01

1.

32

12.5

3

40

.29

3.35

12

.01

28

.29

36.1

816

960

44

4.66

　

　

　

52.8

3

52.8

3

3.31

0.11

0.

68

0.

00

1.32

5.

43

47.4

02.

74

14.5

1

32.8

933

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1710

60

444.

66

　

1.

09

5.45

5.45

52

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52

.83

3.

31

0.

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0.01

1.

32

5.42

47

.40

2.14

14

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32

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28.0

218

1160

44

4.66

　

　

　

52.8

3

52.8

3

3.31

0.10

1.

36

0.

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1.32

6.

10

46.7

21.

53

14.6

9

32.0

333

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1912

60

444.

66

　

　

　

52

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52

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3.

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0.

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0.01

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32

6.10

46

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31

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33.3

020

1360

44

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52.8

3

52.8

3

3.31

0.10

1.

36

0.

00

1.32

6.

10

46.7

3

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15.0

8

31.6

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33

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2114

60

444.

66

　

　

　

52

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52

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3.

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0.

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0.00

1.

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5.42

47

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15

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.00

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822

1560

44

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1.09

5.

45

5.

45

52.8

3

52.8

3

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0.10

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5.

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0

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15

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31

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44

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3

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15

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31

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44

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44

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9

31.5

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60

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52

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52

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3.

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0.

10

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0.00

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44

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45

5.

45

52.8

3

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3

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0.10

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0.

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5.

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0

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0

27

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3326

60

444.

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52

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52

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0.

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0.01

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15

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3

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0.00

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6.

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2

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2

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0

32

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3528

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52

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0.00

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6.00

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15

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31

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32.9

7

3629

60

444.

66

　

　

　

52

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52

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3.

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0.68

0.00

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15

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5

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0.00

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5

999

　

　

　

　

Tota

l13

,339

.73

180.

675

27.2

720

7.94

1,58

4.76

0.00

0.00

1,58

4.76

99.3

415

4.41

25.2

30.

000.

6039

.62

319.

201,

265.

5661

.79

375.

0289

0.54

862.

23

Ele

ctric

ity P

rice

11.8

8（￠

/kW

h）W

ACC

of P

roje

ct:

Pow

er P

lant

Pro

ject

F.I.

R.R

.17

.1%

RE

VEN

UE

CO

STS

INV

ESTM

EN

T

INVE

STM

ENT

Tabl

e 6.

3-2

Inco

me

Stat

emen

t of g

eoth

erm

al IP

P pr

ojec

t

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

Geo

ther

mal

Ene

rgy

Dev

elop

men

t in

the

Rep

ublic

of I

ndon

esia

Fina

l Rep

ort

JIC

A

Wes

t JEC

6-

17

IRR

on

Equi

ty

(aft

Tax,

aft

Int)

23.8

%

Ta

ble

Cas

h flo

w o

f Tot

al D

evel

opm

ent P

roje

ct[M

illio

n U

S$]

Cas

h In

flow

Cas

h O

utflo

wB

alan

ceN

o.In

itial

A

dditi

onal

Rep

aym

ent

Per

Tota

lYe

arEB

ITIn

tere

stTa

xP

rofit

Initi

al In

v.A

dd'n

alIn

v.In

vest

men

tInve

stm

ent

Cap

ital

Tota

lYe

arAc

cum

ulat

e1

23

45

67

89

1011

1213

14[3

2.5

%]

[2-3

-4]

[1+5

+6+7

][9

+10+

11]

[8-1

2]年

借入

金営

業活

動Ｃ

Ｆ合

計初

期投

資追

加井

投資

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t

CHAPTER 7

BENEFITS OF GEOTHERMAL POWER

DEVELOPMENT


JICA West JEC

7-1

CHAPTER 7 BENEFITS OF GEOTHERMAL POWER DEVELOPMENT

7.1 Power Demand and Supply Simulation

The benefits of geothermal power development will be brought out most clearly against the background provided by a simulation of the future power demand and supply situation in Indonesia. The Study Team has used WASP-IV (Wien Automatic System Planning, version 4) computer code to carry out such a simulation. The simulation period is from 2007 to 2016. <Input Data to WASP-IV>

The simulation takes as its starting point the indications in the Electric Power Provision Plan of PT PLN (RUPTL) that the power demand in Indonesia is likely to increase at a rate of 9.0% per annum, as shown in Table 7.7-1 and Fig. 7.7-1, and that the load factor and demand patterns can be considered constant. That is to say that the load duration curve in 2010 shown in Fig. 7.1-2 is assumed to continue.

Appropriate power source facilities should be installed to cope with such increasing power demand. Table 7.1-2 shows a summary of existing power plants in Indonesia, broken down by type of fuel. The table delineates all thermal power plants by fuel types and capacities, based on PT PLN’s statistics and the advice of a JICA expert. Prior to inputting into the WASP program, the actual power capacities were rounded up or down to the approximated capacities shown in Table 7.1-3. The specifications of those existing and planned power plants are assumed to be as per Table 7.1-4. The WASP-IV simulation provides an optimum combination of new power plants at minimum supply cost to the whole system to cope with the power demand insufficiency of the existing and already planned power plants. The specifications of new candidate plants are assumed to be as in Table 7.1-5. For purposes of simplicity, the retirement of existing power plants is not considered.

Table 7.1-1 Power demand forecast (2007 – 2016)

Year Peak Load Gr. Rate Min. Load Gr.Rate Energy Gr.Rate Load FactorMW % MW % GWh % %

2007 22,186 10,414 135,099 69.52008 24,183 9.0 11,352 9.0 147,260 9.0 69.52009 26,359 9.0 12,373 9.0 160,510 9.0 69.52010 28,731 9.0 13,486 9.0 174,954 9.0 69.52011 31,317 9.0 14,700 9.0 190,702 9.0 69.52012 34,136 9.0 16,023 9.0 207,868 9.0 69.52013 37,208 9.0 17,465 9.0 226,574 9.0 69.52014 40,557 9.0 19,038 9.0 246,968 9.0 69.52015 44,207 9.0 20,751 9.0 269,194 9.0 69.52016 48,185 9.0 22,618 9.0 293,418 9.0 69.5


JICA West JEC

7-2

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0Time

Dem

and

0

10,000

20,000

30,000

40,000

50,000

60,000

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Peak

Loa

d D

eman

d (M

W)

Installed Capacity (MW)GAS OIL COAL GAS OIL GAS OIL

PT PJB Cirata & Brantas 1,289 1,289Gresik 61 600 1,578 2,239Muara Karan 400 300 1,229 1,929Paiton 800 800Muara Tawar 1,148 225 640 2,013Sub Total 1,289 61 1,148 800 400 900 1,454 2,218 0 0 8,270

Indonesia Suralaya 3,400 3,400Power Priok 98 52 100 1,900 2,150

Saguling & Mrica 1,116 1,116Kamojag 375 375Semarang 300 1,034 1,334Perak Grati 302 100 462 864Bali 259 76 335Sub Total 1,116 400 311 3,400 0 500 2,362 1,034 76 375 9,574

Ciregon 730 7301,320 1,320

Sub Total of PJB, IP, Cir, Sur, TJ 2,405 461 1,459 5,520 400 1,400 4,546 3,252 76 375 19,894Other Java 4 11 15Total Java 2,409 461 1,459 5,520 400 1,400 4,546 3,252 87 375 19,909

South Kalimantan 30 21 130 131 312Southern part of Sumatra 612 318 485 215 1,630Other　Outside Java 478 323 285 878 2,504 20 4,488Total Outside Java 1,120 662 615 285 878 2,850 20 6,430

Total Indonesia (PLN) 3,529 1,123 1,459 6,135 400 1,685 5,424 3,252 2,937 395 26,339

IPP Paiton 2,400 2,400IPP Cilacap 55 600 655IPP Geothermal 462 462IPP Sub Total 0 0 55 3,000 0 0 0 0 0 462 3,517

Total Indonesia (PLN+IPP) 3,529 1,123 1,514 9,135 400 1,685 5,424 3,252 2,937 857 29,856

(Source: Made by West JEC from PLN Statistic 2006 and data from Mr. Nagai, JICA expert.)

Tanjung Jati B

DSL GEO TOTALSTEAMHYD GT CC

Indonesia HYD FGTＧ FGTO FSC FSG FSO FCCG FCCO FDSL FGEO TOTALHYD1 1,500HYD2 2,000Unit Capacity (MW) 50 50 600 400 400 400 400 50 55Unit No. 24 30 15 1 4 14 8 60 15Total MW 3,500 1,200 1,500 9,000 400 1,600 5,600 3,200 3,000 825 29,825

Fig. 7.1-1 Peak load forecast Fig. 7.1-2 Assumed Load Duration Curve (Source) JICA “Power Sector Study for Optimum

Power Development”, August 2002

Table 7.1-2 List of power plants in Indonesia by fuel type (2006)

Table 7.1-3 Approximated capacity and unit numbers of present power plants for WASP-IV simulation


JICA West JEC

7-3

Fuel Cost Unit FGTG FGTO FSC FSG FSO FCCG FCCO FDSL FGEOOil Price $/MMBTU $/Brrl $/ton $/MMBTU $/Brrl $/MMBTU $/Brrl $/Brrl C$/kWh100 $/B 13.0 140 90 13.0 110 13.0 140 140

kcal/BTU kcal/L kcal/kg kcal/BTU kcal/L kcal/BTU kcal/L kcal/L kcal/kWh0.252 9,200 5,300 0.252 9,200 0.252 9,200 9,200 860

Fuel Cost cent/Gcal 5,185 9,619 1,966 5,850 8,528 5,556 10,307 9,969 0

Heat Rate Kcal/kWh 3,440 3,440 2,389 2,263 2,263 1,792 1,792 2,263 8,600milSCF/GWh kL/GWh ton/GWh milSCF/GWh kL/GWh milSCF/GWh kL/GWh kL/GWh

13.36 375.79 521.90 9.92 278.96 7.46 209.73 256.25Fuel Cost cent/kWh 17.84 33.09 4.70 13.24 19.30 9.95 18.47 22.56

CO2 EmissionFactor(*1) kg CO2/GJ 56.10 74.10 101.00 56.10 77.40 56.10 74.10 74.10

(*2) ditto kg CO2/kWh 0.808 1.067 1.010 0.532 0.734 0.421 0.556 0.702 0.002

(*1) 2006 IPCC Guidelines for National Greenhouse Gas Inventories(*2) Central Research Institute of Electricity Power Industry, Japan CRIEPI Review NO. 45, 2001 (Nov.)

Fuel Consumption

Basic Fuel Price

Heat Value

Fuel Cost Unit VGTG VSC VCCG VGEO$/MMBTU $/ton $/MMBTU C$/kWh

13.0 90 13.0kcal/BTU kcal/kg kcal/BTU kcal/kWh

0.252 5300 0.252 860

Fuel Cost cent/Gcal 5,185 1,966 5,556

Heat Rate Kcal/kWh 3,440 2,263 1,792 8,600milSCF/GWh ton/GWh milSCF/GWh

13.4 521.9 7.46Fuel Cost cent/kWh 17.8 4.45 9.95

CO2 EmissionFactor(*) kg CO2/GJ 56.1 101.0 56.1

ditto kg CO2/kWh 0.808 0.957 0.421 0.002

Basic Fuel Price

Heat Value

Fuel Consumption

Table 7.1-4 Specifications of existing and planned power plants for WASP-IV simulation.

Table 7.1-5 Specifications of new candidate power plants for WASP-IV simulation.

<WASP-IV Simulation for Business as Usual Scenario>

Where the power sources should be developed under a Business as Usual (BAU) scenario, the simulation results shown in Table 7.1-6 indicate that all additional power sources, totaling about 25,800 MW, should be coal-fired power plants. The evolution of the power source mix in this scenario is shown in Fig. 7.1-3. <WASP-IV Simulation for Geothermal Acceleration Scenario>

For comparison, a geothermal acceleration scenario was also simulated. In the Geothermal Road Map formulated by the Ministry of Energy and Mineral Resources and shown in Fig. 7.1-4, the government has set as a target the development of a geothermal power plant capacity of 9,500 MW by the year 2025, and as a milestone on the way to that goal, has underlined the desirability of developing a capacity of 4,600 MW by 2016. Further, the JICA Master Plan Study forecast that a geothermal power plant capacity of 3,340 MW might have


JICA West JEC

7-4

TOTAL SYSTEM RES.0 1 2 3 4 5 6 7 8 9 PEAK MARG. LOLP

YEAR HYD NGAS HSD COAL MFO GEO VGTG VSC VCCG VGEO （MW) (MW) (%) (%)

2007 3,500 6,800 8,100 9,000 1,600 935 0 0 0 0 29,935 22,186 34.9% 0.1102008 3,500 6,800 8,100 9,000 1,600 935 0 0 0 0 29,935 24,183 23.8% 1.8512009 3,500 6,800 8,100 12,000 1,600 1,100 0 0 0 0 33,100 26,359 25.6% 1.3062010 3,500 6,800 8,100 15,600 1,600 1,100 0 0 0 0 36,700 28,731 27.7% 0.8112011 3,500 6,800 8,100 15,600 1,600 1,100 0 4,200 0 0 40,900 31,317 30.6% 0.3802012 3,500 6,800 8,100 15,600 1,600 1,100 0 7,800 0 0 44,500 34,136 30.4% 0.4132013 3,500 6,800 8,100 15,600 1,600 1,100 0 11,400 0 0 48,100 37,208 29.3% 0.5742014 3,500 6,800 8,100 15,600 1,600 1,100 0 16,200 0 0 52,900 40,557 30.4% 0.4092015 3,500 6,800 8,100 15,600 1,600 1,100 0 21,000 0 0 57,700 44,207 30.5% 0.3972016 3,500 6,800 8,100 15,600 1,600 1,100 0 25,800 0 0 62,500 48,185 29.7% 0.513

Existing Additional

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

MW

GEO

MFO

COAL

HSD

NGAS

HYD

PEAK

been developed by 2016. Taking these forecasts into consideration, the Study Team has simulated the geothermal acceleration scenario with the development of 3,500 MW of geothermal power plant capacity by 2016. (New development would represent 2,400 MW of that total by 2016.) Table 7.1-8 and Fig. 7.1-6 show the results of the geothermal acceleration scenario. As 2,400 MW of geothermal capacity is developed, the balance of 23,400 MW is supplied by coal-fired power plants. This means geothermal power plants are substituting for coal-fired power plants (Table 7.1-9).

Table 7.1-6 Power plant development plan (2007 – 2016) ~ Business as usual scenario ~

Fig. 7.1-3 Power plant development plan (2007 – 2016) ~ Business as usual scenario ~


JICA West JEC

7-5

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

Geo

ther

mal

Cap

acity

(MW

)

GeothermalCapacity(Master PlanStudy)

WASP-IVSimulation

NewDevelopment

(MW) (MW) (MW)Existing 857

2007 888 9352008 1,188 9352009 1,194 1,100 02010 1,214 1,100 02011 1,534 1,100 02012 1,974 1,700 6002013 1,974 2,300 1,2002014 2,399 2,900 1,8002015 2,409 2,900 1,8002016 3,344 3,500 2,400

Fig. 7.1-4 Geothermal Development Road Map 2004-2025

Fig. 7.1-5 Forecast of geothermal energy development by “JICA Master Plan Study”

Table 7.1-7 Geothermal energy development in the geothermal acceleration scenario


JICA West JEC

7-6

TOTAL SYSTEM RES.0 1 2 3 4 5 6 7 8 9 PEAK MARG. LOLP

YEAR HYD NGAS HSD COAL MFO GEO VGTG VSC VCCG VGEO （MW) (MW) (%) (%)

2007 3,500 6,800 8,100 9,000 1,600 935 0 0 0 0 29,935 22,186 34.9% 0.1102008 3,500 6,800 8,100 9,000 1,600 935 0 0 0 0 29,935 24,183 23.8% 1.8512009 3,500 6,800 8,100 12,000 1,600 1,100 0 0 0 0 33,100 26,359 25.6% 1.3062010 3,500 6,800 8,100 15,600 1,600 1,100 0 0 0 0 36,700 28,731 27.7% 0.8112011 3,500 6,800 8,100 15,600 1,600 1,100 0 4,200 0 0 40,900 31,317 30.6% 0.3802012 3,500 6,800 8,100 15,600 1,600 1,100 0 7,200 0 600 44,500 34,136 30.4% 0.3812013 3,500 6,800 8,100 15,600 1,600 1,100 0 10,200 0 1,200 48,100 37,208 29.3% 0.5002014 3,500 6,800 8,100 15,600 1,600 1,100 0 14,400 0 1,800 52,900 40,557 30.4% 0.3312015 3,500 6,800 8,100 15,600 1,600 1,100 0 19,200 0 1,800 57,700 44,207 30.5% 0.3262016 3,500 6,800 8,100 15,600 1,600 1,100 0 23,400 0 2,400 62,500 48,185 29.7% 0.407

Existing Additional

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

MW

GEO

MFO

COAL

HSD

NGAS

HYD

PEAK

TOTAL SYSTEM RES.0 1 2 3 4 5 6 7 8 9 PEAK MARG.

YEAR HYD NGAS HSD COAL MFO GEO VGTG VSC VCCG VGEO （MW) (MW) (%)

2007 0 0 0 0 0 0 0 0 0 0 0 0 0.0%2008 0 0 0 0 0 0 0 0 0 0 0 0 0.0%2009 0 0 0 0 0 0 0 0 0 0 0 0 0.0%2010 0 0 0 0 0 0 0 0 0 0 0 0 0.0%2011 0 0 0 0 0 0 0 0 0 0 0 0 0.0%2012 0 0 0 0 0 0 0 -600 0 600 0 0 0.0%2013 0 0 0 0 0 0 0 -1,200 0 1,200 0 0 0.0%2014 0 0 0 0 0 0 0 -1,800 0 1,800 0 0 0.0%2015 0 0 0 0 0 0 0 -1,800 0 1,800 0 0 0.0%2016 0 0 0 0 0 0 0 -2,400 0 2,400 0 0 0.0%

Existing Additional

Table 7.1-8 Power plant development plan (2007 – 2016) ~ Geothermal acceleration scenario ~

Fig. 7.1-6 Power plant development plan (2007 – 2016) ~ Geothermal acceleration scenario ~ Table 7.1-9 Effect of substitution of geothermal power for thermal power (MW) (2007 – 2016)

~ Difference between business as usual scenario and geothermal acceleration scenario ~


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7.2 Fuel Saving Benefit (Reduction of PT PLN Generation Costs) Table 7.2-1 and Fig.7.2-1 show evolution of generated energy by fuel types in the business as usual scenario. In contrast, Table 7.2-2 and Fig. 7.2-2 show the evolution of the geothermal acceleration scenario. Then, Table 7.2-3 and Fig. 7.2-3 show the differences between two scenarios in the fuel types of generated energy. The simulations reveal that when an additional 2,400 MW of geothermal power is developed by the year 2016, the generated geothermal energy would be 59,151 GWh and would substitute for a sum of 54,396 GWh (92.0%) of coal-fired power, 2,527 GWh (4.3%) of gas-turbine and diesel power, 1,577 GWh (2.7%) of natural gas-fired power and 535 GWh (0.9%) of oil-fired power. Considering installed capacities, 2,400 MW of geothermal power would substitute for the same capacity of coal-fired power, but considering the generated energy, geothermal would substitute not only for coal-fired but also for gas-turbine and diesel power, natural gas-fired power and oil-fired power, though the substituted energy for this oil-related power is considerably smaller than that for coal-fired power. Table 7.2-4 shows the amount of substituted energy in terms of the volume of each fuel. This table reveals that the introduction of geothermal power would save a remarkable amount of fossil fuel consumption over the 5 years from 2012 to 2016: 26,894,000 tons of coal, 728,000 kl of diesel oil (HSD), 14,542 million SCF of natural gas and 149,000 kl of heavy oil (MFO). Table 7.2-5 delineates the monetary savings of USD 5,034 million over the 5 years with crude oil prices at 100 USD/barrel. As mentioned above, 59,151 GWh of geothermal power will be generated over this period. Thus, the fossil fuel saving value of geothermal power is 8.5 USD Cents/kWh. Fig.7.2-4 shows how the fossil fuel saving value of geothermal power varies with oil prices. If the benchmark oil price should once again reach a level of 140 USD/barrel, the fossil fuel saving value - which is 8.5 USD Cents/kWh at the benchmark oil price of 100 USD/barrel - becomes as high as 10.8 USD Cents/kWh. In addition, the selling price of electricity from coal-fired power plants, or the benchmark price, is 8.2 USD Cents/kWh where the coal unit price is 90 USD/ton, corresponding to the benchmark oil price of 100 USD/barrel. Thus, 0.3 USD Cents/kWh, the difference between the fossil fuel saving value of geothermal at 8.5 USD Cents/kWh and the said coal-fired benchmark price of 8.2 USD Cents/kWh, can be considered to be a premium that geothermal brings in to PT PLN as a fuel saving effect. Fig 7.2-5 shows how this premium value changes in response to variations in benchmark prices of coal and oil. Should the benchmark oil price increase to 140 USD/barrel, the premium increases to 0.8 USD Cents/kWh. This premium can be attributed to the effect of substituting geothermal power for such high fuel-cost power generation as oil-fired power, diesel power, and natural gas-fired power, whose generation cost is higher than for geothermal power. This is to say that the introduction


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GWH HYD NGAS HSD COAL MFO GEO TOTALYEAR （GWｈ）（GWｈ）（GWｈ）（GWｈ）（GWｈ）（GWｈ） (GWh)

2007 7,882 35,387 24,375 55,238 6,795 7,067 136,7442008 7,882 40,708 27,633 58,491 7,135 7,099 148,9482009 7,882 37,775 25,640 75,749 7,009 8,338 162,3932010 7,882 34,648 24,801 94,529 6,843 8,341 177,0422011 7,882 32,771 23,899 113,491 6,615 8,347 193,0042012 7,882 32,421 23,632 131,533 6,526 8,381 210,3742013 7,882 32,211 23,601 150,695 6,504 8,402 229,2942014 7,882 31,629 22,977 172,708 6,362 8,387 249,9442015 7,882 31,255 22,631 196,001 6,281 8,385 272,4362016 7,882 31,067 22,570 220,785 6,258 8,383 296,944

Total (07-16) 78,820 339,870 241,758 1,269,220 66,327 81,128 2,077,1243.8% 16.4% 11.6% 61.1% 3.2% 3.9% 100.0%

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

GW

h

GEO MFOCOAL HSDNGASHYD

of geothermal power would be effective in decreasing the fuel cost expenses of PT PLN as a whole, and therefore, that would also be effective in decreasing the cost of the government subsidy to PT PLN. The government may be able to reduce the cost of its subsidy to PT PLN thanks to this premium margin. However, an alternative view is that PT PLN should use this premium to buy geothermal energy at a higher price than the benchmark price because PT PLN obtains these cost reduction benefits as a direct result of geothermal energy substitution. In this case, the existing government subsidy to non-geothermal energy will remain at the same level as before. To date, PT PLN has been insisting that coal-generated energy and energy from geothermal sources is of the same value and should be sold at the same price. However, this simulation revealed that geothermal energy has a higher value than coal-fired power.

This value comes from the difference between geothermal power and coal-fired power in supply reliability. The frequency of downtime of geothermal power plants is far less than that of coal-fired power plants, and the periodical overhaul maintenance shutdown requires fewer days for geothermal than for coal-fired plants. The benefits from these differences in power supply reliability are realized with the reduction in substituted thermal power plant operations and the reduction in fuel cost expenses.

Table 7.2-1 Energy generation by fuel types (2007 -2016) ~ Business as usual scenario ~

Fig. 7.2-1 Energy generation by fuel types (2007 -2016) ~ Business as usual scenario ~


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2007 7,882 35,387 24,375 55,238 6,795 7,067 136,7442008 7,882 40,708 27,633 58,491 7,135 7,099 148,9482009 7,882 37,775 25,640 75,749 7,009 8,338 162,3932010 7,882 34,648 24,801 94,529 6,843 8,341 177,0422011 7,882 32,771 23,899 113,491 6,615 8,347 193,0042012 7,882 32,353 23,454 127,287 6,485 12,918 210,3802013 7,882 31,974 23,246 142,217 6,424 17,567 229,3102014 7,882 31,281 22,361 160,154 6,239 22,042 249,9592015 7,882 30,867 22,010 183,510 6,157 22,024 272,4502016 7,882 30,529 21,767 204,158 6,091 26,538 296,965

Total (07-16) 78,820 338,293 239,186 1,214,824 65,792 140,280 2,077,1953.8% 16.3% 11.5% 58.5% 3.2% 6.8% 100.0%

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

GW

h

GEO MFOCOAL HSDNGASHYD


2007 0 0 0 0 0 0 02008 0 0 0 0 0 0 02009 0 0 0 0 0 0 02010 0 0 0 0 0 0 02011 0 0 0 0 0 0 02012 0 -68 -177 -4,246 -42 4,538 52013 0 -237 -355 -8,478 -79 9,165 152014 0 -347 -616 -12,554 -122 13,655 152015 0 -388 -621 -12,492 -124 13,639 142016 0 -537 -802 -16,627 -167 18,155 21

Total (07-16) 0 -1,577 -2,572 -54,396 -535 59,151 712.7% 4.3% 92.0% 0.9% 100.0%

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

2012 2013 2014 2015 2016

Sav

ed G

Wh

by G

EO

(GW

h)

MFO HSDNGASCOAL

Table 7.2-2 Energy generation by fuel types (2007 -2016) ~ Geothermal acceleration scenario ~

Fig. 7.2-2 Energy generation by fuel types (2007 -2016) ~ Geothermal acceleration scenario ~

Table 7.2-3 Thermal power substitution effect of geothermal power (GWh) (2007 – 2016) ~ Difference between business as usual scenario and geothermal acceleration scenario ~

Fig. 7.2-3 Thermal power substitution effect of geothermal power (GWh) (2007 – 2016) ~ Difference between business as usual scenario and geothermal acceleration scenario ~


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Fuel Q'ty HYD NGAS HSD COAL MFO GEO TOTALYEAR mil SCF 000 k L 000 ton 000 k L - -

2007 0 0 0 02008 0 0 0 02009 0 0 0 02010 0 0 0 02011 0 0 0 02012 -711 -49 -2,099 -122013 -2,131 -98 -4,192 -222014 -3,231 -175 -6,207 -342015 -3,564 -177 -6,176 -352016 -4,905 -229 -8,221 -46

Total (07-16) -14,542 -728 -26,894 -149

GEO VALUE HYD NGAS HSD COAL MFO GEO

BenchMark OilPrice

Bench MarkCoal PP Price

Fuel Price 13 140 90 100 0.0 100 0.0(Unit) ($/MMBTU) ($/B) ($/ton) ($/B) (C$/kWh) ($/B) (C$/kWh)M$ HYD NGAS HSD COAL MFO GEO TOTAL GEO Gen. Ave. Cost

YEAR (M$) (M$) (M$) (M$) (M$) (M$) (M$) (GWh) (C$/kWh)2007 0 0 0 0 0 0 0 02008 0 0 0 0 0 0 0 02009 0 0 0 0 0 0 0 02010 0 0 0 0 0 0 0 02011 0 0 0 0 0 0 0 02012 0 -10 -44 -315 -8 0 -376 4,538 8.292013 0 -29 -88 -633 -15 0 -765 9,165 8.352014 0 -44 -155 -939 -24 0 -1,162 13,655 8.512015 0 -49 -157 -940 -24 0 -1,169 13,639 8.572016 0 -67 -203 -1,258 -32 0 -1,561 18,155 8.60

Total (07-16) -198 -647 -4,085 -103 0 -5,034 59,151 8.51

10.8

6.26.8

7.47.9

8.5

9.19.7

10.2

0.0

2.0

4.0

6.0

8.0

10.0

12.0

60 70 80 90 100 110 120 130 140

Bench Mark Oil Price ($/B)

Geo

ther

mal

Ene

rgy

Val

ue (C

$/kW

h)

2012-2016

Table 7.2-4 Thermal power fuel reduction effect of geothermal power (Volume) (2007 -2016)

Table 7.2-5 Thermal power fuel reduction effect of geothermal power (2007 -2016) ~ For Benchmark oil price at 100 USD/barrel ~

Fig. 7.2-4 Fuel reduction value (2007 -2016)


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FUEL EXPORT EFFECT

EXPORT HYD NGAS HSD COAL MFO GEO Bench Mark Oil PriceFuel Price 13 140 90 100 - 100

(Unit) ($/MMBTU) ($/B) ($/ton) ($/B) - ($/B)M$ HYD NGAS HSD COAL MFO GEO TOTAL GEO Gen. Ave. Cost

YEAR (M$) (M$) (M$) (M$) (M$) (M$) (M$) (GWh) (C$/kWh)2007 0 0 0 0 0 0 0 0 0.002008 0 0 0 0 0 0 0 0 0.002009 0 0 0 0 0 0 0 0 0.002010 0 0 0 0 0 0 0 0 0.002011 0 0 0 0 0 0 0 0 0.002012 0 10 44 191 8 0 253 4,538 5.572013 0 29 88 382 15 0 514 9,165 5.612014 0 44 155 565 24 0 788 13,655 5.772015 0 49 157 562 24 0 792 13,639 5.802016 0 67 203 747 32 0 1,050 18,155 5.78

otal (07-16) 0 198 647 2,447 103 0 3,396 59,151 5.74

6.4 6.9 7.3 7.8 8.2 8.7 9.1 9.5 10.0

0.80.7

0.60.4

0.30.2

0.0

0.0

2.0

4.0

6.0

8.0

10.0

12.0

60 70 80 90 100 110 120 130 140

Bench Mark Oil Price ($/B)<Bench Mark Coal Price ($/ton) >

Valu

e of

Geo

ther

mal

Ene

rgy

(C$/

kWh) Fuel Cost Reduction Value

Bench Mark Coal Price

Fig. 7.2-5 Fuel reduction premium of geothermal power (2007 -2016)

7.3 Fuel Saving Benefit (Export Benefit) Geothermal power reduces coal and other fossil fuel consumption. That saved fossil fuel may be allocated for export, earning foreign exchange and contributing to the improvement of the nation’s balance of external payments. The volume of fuel saved by geothermal power was shown in Table 7.2-4, and the value of that saved fuel, if it should be exported, is shown in Table 7.3-1. Over the 5 years from 2012 to 2016, this saved fuel would contribute a USD 3,396 million equivalent to foreign exchange earnings. When that value is divided by the amount of geothermal power generated, we find that geothermal power contributes 5.7 USD Cents/kWh of export earnings. The export earnings for each benchmark oil price are shown in Fig. 7.3-1, which shows that the export earning value increases to 8.0 USD Cents/kWh if the benchmark oil price should rise to 140 USD/barrel.

Tabel 7.3-1 Export value of fuel saved through use of geothermal power (2007 – 2016) ~ For Benchmark oil price at 100 USD/barrel ~


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8.0

3.44.0

4.65.2

5.76.3

6.97.5

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

60 70 80 90 100 110 120 130 140

Bench Mark Oil Price ($/B)

Fuel

Exp

ort V

alue

(C$/

kWh)

2007-2016

Fig. 7.3-1 Export value of fuel saved through use of geothermal power (2007 – 2016)

7.4 Tax Increase Benefit Table 7.4-1 delineates a comparison of the power selling price makeup of geothermal and coal-fired IPP projects. In the case of the geothermal IPP project, return for investment accounts for a remarkably large share of the selling price because a large up-front investment must be recovered, and the share of corporate income tax is proportionally larger, too. In addition, the local government often levies royalties on geothermal IPP projects. In this model case, a royalty of 2.5% on electricity sales is assumed. As a result, the selling price of geothermal IPP electricity includes 1.8 USD Cents/kWh for tax (corporate income tax and dividend tax) and 0.3 USD Cents/kWh for royalties, for a total of 2.1 USD Cents/kWh.. On the other hand, the coal-fired IPP of the benchmark case sells electricity at a price of which fuel costs account for over half, and which has a much smaller return-for-investment component, as the up-front investment is relatively small. So, the corporate income tax is merely 0.5 USD Cents/kWh for a coal-fired IPP project. Accordingly, the government could attain increased tax revenue of 1.6 USD Cents/kWh, due to the difference in tax payments between geothermal and coal-fired IPP projects,

Table 7.4-1 Comparison of selling price composition between geothermal and coal-fired power

~ For benchmark oil price at 100 USD/barrel ~

(c$/kWh) (%) (c$/kWh) (%)Initial Capital Cost 2.8 (23.7%) 1.0 (11.8%)Additional Capital Cost 0.1 (1.0%) - -Fuel Cost - - 4.4 (54.2%)O&M Cost 0.8 (6.4%) 0.7 (9.0%)Interest 0.9 (7.3%) 0.4 (5.0%)Tax 1.8 (15.0%) 0.5 (5.6%)Royalty 0.3 (2.5%) - -Return for Investment 5.2 (44.2%) 1.2 (14.4%)TOTAL (Selling Price) 11.9 (100.0%) 8.2 (100.0%)

Geothermal PP Coal PP


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0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

Geothermal IPP Coal IPP

Bre

akdo

wno

fSel

lingP

rice（

c$/k

Wh）

Return for Investment TaxRoyaltyInterestO&M

Fuel　CostAdditional Capital Cost Initial Capital Cost

Geothermal PPTax 1.8 C$/kWhRoyalty 0.3 C$/kWhTotal 2.1 C$/kWh

Coal PPTax 0.5 C$/kWhRoyalty noTotal 0.5 C$/kWh

Corporate Tax rate 25%Dividend tax rate 10%

if geothermal projects should be realized instead of coal-fired ones. This tax revenue increase is one benefit that flows to the government from geothermal IPP projects.

Fig. 7.4-1 Selling price composition comparison of geothermal and coal-fired Power ~ For Benchmark oil price at 100 USD/barrel ~

7.5 Environmental Improvement Benefit Geothermal power uses steam from underground water heated by magma without any combustion process, and therefore emits few air pollutants. Emitting no sulfur oxide, nitrogen oxide or dust, the geothermal power is an environmentally friendly power source for the vicinity of the power plant. From the point of view of the global environment, geothermal power is a blessing in that it emits little carbon dioxide. So where the exploitation of geothermal power might avoid generation from fossil fuel sources, a reduction in the carbon dioxide volumes generated in fossil fuel-based projects is a social benefit due to its environmental value. With reference to the fossil fuel avoided by geothermal power (Cf. Table 7.2-3), the volumes of carbon dioxide reduction from each power source obtained by multiplying the carbon dioxide emission coefficient (as given in Tables 7.1-4 and 7.1-5) are shown in Table 7.5-1. These tables show that carbon dioxide emissions of 55,843 thousand tons could be suppressed over 5 years from 2012 to 2016. This means that geothermal power reduces emissions by 0.944 kg of carbon dioxide per 1 kWh of generation over the 5 years. As Fig. 7.5-1 shows, carbon dioxide emission credits are traded in the range of 1,000 JPY/ton (10 USD/ton) ~ 3,500 JPY/ton (35 USD/ton). With the carbon credit provisionally set at 20 USD/ton, a reduction of 0.944 kg/kWh of carbon emissions is worth 1.9 USD Cents/kWh, and this is another measure of the environmental improvement benefit of geothermal power.


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CO2 HYD NGAS HSD COAL MFO GEO TOTAL GEO Gen. Ave. Red.YEAR ('000 ton) ('000 ton) ('000 ton) ('000 ton) ('000 ton) ('000 ton) (GWh) (kg/kWh)

2007 0 0 0 0 0 0 02008 0 0 0 0 0 0 02009 0 0 0 0 0 0 02010 0 0 0 0 0 0 02011 0 0 0 0 0 0 02012 -42 -137 -4,115 -31 7 -4,318 4,538 0.9522013 -126 -275 -8,211 -58 14 -8,656 9,165 0.9442014 -191 -489 -12,155 -90 20 -12,903 13,655 0.9452015 -211 -495 -12,087 -91 20 -12,863 13,639 0.9432016 -290 -639 -16,077 -122 27 -17,102 18,155 0.942

Total (07-16) -860 -2,035 -52,645 -392 89 -55,843 59,151 0.944

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

2008

/4/2

120

08/5

/520

08/5

/19

2008

/6/2

2008

/6/1

620

08/6

/30

2008

/7/1

420

08/7

/28

2008

/8/1

120

08/8

/25

2008

/9/8

2008

/9/2

220

08/1

0/6

2008

/10/

2020

08/1

1/3

2008

/11/

1720

08/1

2/1

2008

/12/

1520

08/1

2/29

2009

/1/1

220

09/1

/26

2009

/2/9

2009

/2/2

3Nik

kei-J

BIC

Car

bon

Inde

x (J

PY/to

n C

O2

Table 7.5-1 CO2 Reduction through adoption of geothermal power (2007 -2016)

（Source: Nikkei-JBIC Carbon Quotation Index） Fig. 7.5-1 Price of carbon dioxide emission credits

7.6 Total Value of Benefits of Geothermal Power The geothermal benefits mentioned in Sections 7.2 to 7.5 above are summarized in Table 7.6-1, which shows that the additional benefits of geothermal power amount to a total value of 17.7 USD Cents/kWh, for a benchmark oil price at 100 USD/barrel. The breakdown is: i) energy value (a benchmark price) at 8.2 USD Cents/kWh, ii) fossil fuel reduction value at 0.3 USD Cents/kWh, iii) saved fossil fuel export value at 5.7 USD Cents/kWh, iv) increased tax revenue value at 1.6 USD Cents/kWh and v) carbon dioxide reduction value at 1.9 USD Cents/kWh. The value may further increase to 22.3 USD Cents/kWh if the benchmark oil price should increase to 140 USD/barrel.


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6.4 6.9 7.3 7.8 8.2 8.7 9.1 9.5 10.0

0.00.0

0.00.2

0.30.4

0.60.7

0.8

3.44.0

4.65.2

5.76.3

6.97.5

8.0

1.61.6

1.6

1.6

1.6

1.6

1.6

1.6

1.6

1.91.9

1.9

1.9

1.9

1.9

1.9

1.9

1.9

0.0

5.0

10.0

15.0

20.0

25.0

60 70 80 90 100 110 120 130 140

Bench Mark Oil Price ($/B)<Bench Mark Coal Price ($/ton)>

Valu

e o

f G

eot

herm

al E

nerg

y (

C$/k

Wh)

CO2 Reduction Value (20$/ton)

Tax Value

Fuel Export ValueFuel Cost Reduction Value

Bench Mark Coal Energy Price

2007-2016

14.4

22.321.2

20.018.9

17.716.6

15.5

13.4

<54> <63> <72> <81> <90> <99> <108> <117> <126>

2012-2016 CO2 Price 20 $/tonAverage Emission Coef. 0.944 kg/kWh

Bench MarkOil Price

Bench MarkCoal Energy

Price

Fuel CostReduction

ValueFuel Export

Value Tax Value

CO2Reduction

Value(20$/ton) Total

$/B C$/kWh C$/kWh C$/kWh C$/kWh C$/kWh C$/kWh60 6.4 0.0 3.4 1.6 1.9 13.470 6.9 0.0 4.0 1.6 1.9 14.480 7.3 0.0 4.6 1.6 1.9 15.590 7.8 0.2 5.2 1.6 1.9 16.6

100 8.2 0.3 5.7 1.6 1.9 17.7110 8.7 0.4 6.3 1.6 1.9 18.9120 9.1 0.6 6.9 1.6 1.9 20.0130 9.5 0.7 7.5 1.6 1.9 21.2140 10.0 0.8 8.0 1.6 1.9 22.3

Table 7.6-1 Total value of benefits of geothermal power (2007 – 20016)

~ CO2 credit at 20 USD/ton ~

Fig. 7.6-1 Total value of benefits of geothermal power generation (2007 – 2016) Table 7.6-2 summarizes these values by beneficiaries. The table shows that PT PLN

receives 6.4 USD Cents/kWh ~ 10.0 USD Cents/kWh (for a benchmark oil price of 60 USD/barrel ~ 140 USD/barrel) as an energy value. The government receives 3.0 USD Cents/kWh ~ 4.2 USD Cents/kWh (ditto), of which the breakdown is: (i) fuel cost reduction value as subsidy reduction to PT PLN, (ii) 32.5% (tax rate) of fuel export value, and (iii) tax increase value. The society receives 4.2 USD Cents/kWh ~ 7.3 USD Cents/kWh as the remaining fuel export value and environment value (at 20 USD/ton CO2 credit price). The table


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Oil Pricecase

EnergyValue

Fuel CostReduction

ValueFuel Export

Value Tax ValueEnvironment

al Value Total(US$/B) (C$/kWh) (C$/kWh) (C$/kWh) (C$/kWh) (C$/kWh) (C$/kWh)

Total 60 6.4 0.0 3.4 1.6 1.9 13.480 7.3 0.0 4.6 1.6 1.9 15.5

100 8.2 0.3 5.7 1.6 1.9 17.7120 9.1 0.6 6.9 1.6 1.9 20.0140 10.0 0.8 8.0 1.6 1.9 22.3

Beneficiary 60 6.4 6.4 PLN 80 7.3 7.3

100 8.2 8.2120 9.1 9.1140 10.0 10.0

Government 60 0.0 1.1 1.6 2.780 0.0 1.5 1.6 3.1

100 0.3 1.9 1.6 3.8120 0.6 2.2 1.6 4.4140 0.8 2.6 1.6 5.0

Social 60 2.3 1.9 4.280 3.1 1.9 5.0

100 3.9 1.9 5.8120 4.7 1.9 6.5140 5.4 1.9 7.3

(Note) Fuel export value is divided between government and social sector using tax rate (32.5%).

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

20.0

Value component Beneficiary

Valu

e of

Geo

ther

mal

Ene

rgy

(C$/

kWh)

Environmental Value

Energy ValuePLN

Social

GovernmentTax Value

Fuel Export Value

Fuel Cost Reduction Value

ｘ 32.5% Tax rate

shows that geothermal power can bring remarkable benefits to PT PLN, the government and the society, if it is well developed.

Table 7.6-2 Total value of benefits of geothermal power by beneficiaries

Fig. 7.6-2 Total value of benefits of geothermal power and its beneficiaries

7.7 Construction Effects of Geothermal Power Plants

This Study has discussed the benefits derived from geothermal power generation up to


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Section 7.6, and this Section continues with a discussion of the benefits of geothermal power plant construction.

While a thermal power plant can be completed largely off-site, construction of a geothermal power plant is site-specific and involves a lot of drillings and civil work at the site. So geothermal power plant construction relies heavily on the procurement of work and services from the vicinity of the construction site. That induces domestic demand increases in the country and stimulates the domestic economy. These ripple effects are calculated using the Input-Output Table for Indonesia. <Input-Output Table for Indonesia>

Input-output tables are complied in Indonesia every 3 to 5 years. The latest one is the 2005 version. The tables are prepared for 19 sectors, 66 sectors and 175 sectors. Each table consists of the total table, the domestic table and the import table. In this study, the Study Team has integrated several sectors of agriculture, livestock and forestry of the 66 sector table, and made a new 47 sector table for easily handling in Excel spreadsheets. The modified input-output tables of domestic 47 sectors are given in ANNEX-2 Table-1 (1) to (4). The input coefficients for the domestic table (Ad) of those 47 sectors are also given in ANNEX-2 Table-2 (1) to (3). <Construction Investment in Geothermal Power Plants>

This section refers to construction of a 60 MW geothermal power plant discussed in Chapter 6. During construction of a geothermal power plant, drilling services, cement, reinforcment bars, civil structure construction work, etc. for exploratory and production wells may be procured locally, and this is different from the thermal power plant construction, which involves a lot of imported equipment. Of the total construction costs for a geothermal power plant, the costs of work and services to be procured from local industries is assumed in this study as per Table 7.7-1. <Ripple Effect Calculation Method>

Where domestic demand as shown in Table 7.7-1 would be created by construction of a 60 MW geothermal power plant in Indonesia, the production of sectors involved in the construction would increase, and the production increase would spread to all sectors through inter-industry relationships. The effects can be calculated with the following demand and supply formula: AdX + F = X (7.1) Where, Ad : Domestic input coefficients (matrix of 47 rows and 47 columns) X : Domestic production of each sector (a column vector of 47 rows) F : Domestic final demands (a column vector of 47 rows)


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From the formula (7.1), X can be obtained as follows. (I is an unit matrix.) X = (I – Ad)-1F (7.2) Therefore, where the column vector F is the domestic procurement value as in Table 7.7-1, F multiplied by the inversion matrix (Leontev’s inversion matrix) of (I – Ad)-1 calculates the corresponding domestic production increase. In addition, the production increase results in an increase in employees’ income and a consequent increase in their consumption expenditures. The consumption increase will induce further domestic production. In this study, the ripple effect of production accompanying direct domestic procurement is regarded as the primary ripple effect and the subsequent ripple effect induced by consumption increase through increase of employees’ income is regarded as the secondary ripple effect. Both the effects are calculated and the summed up as the total effect. In addition, the employment increase is also considered and is referred to in Table 7.7-2. <Ripple Effect on Production Increase ~ Primary Ripple Effect ~ >

Though direct domestic procurement from local industries amountng to IDR 1,043 billion, the ripple effect on production increase in all sectors (the primary ripple effect) totals IDR 1,526 billion, or a multiplier effect of about 1.46 times. The ripple effect is estimated to create 7,464 jobs.

<Ripple Effect on Consumption Increase ~ Secondary Ripple Effect ~ >

Through the primary ripple effect above, the employees’ income increases by IDR 150 billion as a whole in Indonesia. A substantial part of the increased income may be spent as consumption in the domestic market and further stimulates the economy. In this study, the consumption propensity for Indonesia is assumed to be the 0.55 figure arrived at in the study of the Japan Research Institute, Ltd. Given this consumption propensity, expenditure is expected to expand to IDR 83 billion and the production increase effect (the secondary ripple effect) is calculated at IDR 136 billion. At the same time, the employment increase is counted at 2,596 persons. <Total Effects>

When the primary and secondary ripple effects are summed up, direct domestic procurement from local industries amounting to IDR 1,043 billion brings about an increase of domestic production of IDR 1,662 billion, which is about a 1.59 multiplier effect on the initial procurement.

Industries especially increasing their production of those directly receiving


JICA West JEC

7-19

procurement orders are the crude oil, natural gas and geothermal mining sector (No. 25), basic iron and steel manufacturing sector (No. 45), construction sector (No. 52) and cement manufacturing sector (No. 44). Affected by these sectors, the petroleum refining sector (No. 41) and trade sector (No. 53) are also found to expand their production.

As for employment opportunities, geothermal power plant construction would have a significant job-creating effect as large as 10,060 opportunities. Industries feeling a large employment-creating effect are the trade sector (No. 53) with 1,653 jobs, the agriculture sector (No. 1) with 1,499, the construction sector (No. 52) with 1,498, and cement manufacturers (No. 44) with 1,400. It is remarkable that a large job-creation effect is seen in the agriculture sector, which receives no direct procurement orders. Refer to Fig. 7.7-1, and Tables 7.7-3 and 7.7-4.

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Tabl

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7-2

Con

stru

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fect

s of a

geo

ther

mal

pow

er p

lant


JICA West JEC

7-22

Rank Sector (Million Rp)1 Crude oil, natural gas and geothermal mining 510,1382 Manufacture of basic iron and steel 247,2733 Construction 192,7184 Manufacture of cement 130,0105 Petroleum refinery 97,6216 Trade 71,4747 Real estate and business service 66,6518 Electricity, gas and water supply 39,2359 Coal and metal ore mining 32,56210 Other services 18,557

Rank Sector （Psn)1 Trade 1,6532 Agriculture 1,4993 Construction 1,4984 Manufacture of cement 1,4005 Other services 4026 Manufacture of basic iron and steel 3537 Road transport 2918 Crude oil, natural gas and geothermal mining 2889 Real estate and business service 26910 Other mining and quarrying 267

Ripple effect of construction investment of 60 MW class geothermal power plant in Indonesian bRP: billion Rupia

Purchase in domesticmarket

Production increase（primary）

Demand increase in each industry

Wage increaseEmployment increase

（primary）

Employment increase（secondary）

Production increase（secondary）

Consumption increase

Prim

ary

eff

ect

Seconda

ry e

ffect

1,043 bRp

2,596 psn

7,464 psn

83 bRp

150 bRp

136 bRp

1,526 bRp

Employment increase（primary + secondary）

Production increase（primary + secondary）

Tota

l eff

ect

1,662 bRp（multiplier effect 1.59 times）

10,060 psn

Fig. 7.7-1 Ripple effect of 60 MW geothermal power plant construction

Table 7.7-3 Sectors with increasing production

Table 7.7-4 Sectors with increasing employment


JICA West JEC

7-23

<Construction Effects of a Coal-fired Power Plant> The construction effects of a coal-fired power plant are analyzed here and compared

with those of a geothermal power plant. The examined model plant is the 600 MW coal-fired power plant discussed in Chapter 5. In the construction of a coal-fired power plant in Indonesia, a large part of the equipment and materials are ordered from outside the country, and so the value of domestic orders is not so large as for geothermal power. Of the total investment for the construction, direct domestic procurement from local industries is assumed as per Table 7.7-5. The calculations of the production increase effects are carried out with the same method used for the model geothermal power plant. In addtion, since the subject coal-fired power plant has a capacity of 600 MW, 1/10 of actual investment and order values is used for comparison with the 60 MW geothermal power plant. The calculation results are given in Table 7.7-6 <Ripple Effect on Production Increase ~ Primary Ripple Effect ~ >

Though the direct domestic procurement from local industries amounts to IDR 251.5 billion, the ripple effect on production increases in all sectors (the primary ripple effect) totals IDR 439.1 billion, a multiplier effect of about 1.75. The ripple effect is estimated to create 3,187 jobs. <Ripple Effect on Consumption Increase ~ Secondary Ripple Effect ~ >

The primary ripple effect increases employees’ income by IDR 51 billion as a whole in Indonesia. A substantial part of the increased income may be spent as consumption in the domestic market and further stimulates the economy. When the consumption propensity of Indonesia is assumed to be 0.55, the expenditure is expected to expand to IDR 28.1 billion and the production increase effect (the secondary ripple effect) is calculated at IDR 46.2 billion. At the same time, 880 jobs will be created. <Total Effects>

When the primary and secondary ripple effects are added together, the direct domestic procurement from local industries amounting to IDR 251.5 billion brings an increase in domestic production of IDR 485.3 billion, a multiplier effect of about 1.93 times from the initial procurement. In total, the employment increase will be 4.067 jobs. <Comparison of Construction Effects of Geothermal and Coal-fired Power Plants>

Table 7.7-7 and Fig.7.7-2 show a comparison of the direct domestic procurement of the geothermal and coal-fired plants. The unit construction cost per output is 3,010 USD/kW for geothermal and 1,210 USD/kW for coal-fired, making the cost of geothermal 2.5 times higher than coal-fired. Because the domestic procurement share of geothermal is also higher than for a coal-fired plant, the unit domestic procurement value per output for geothermal is 1,739 USD/kW as against 419 USD/kW for coal-fired. The value for geothermal is about 4.2 times that for coal-fired generation.


JICA West JEC

7-24

Table 7.7-8 and Fig.7.7-3 show a comparison of construction effects of geothermal and

coal-fired plants. Because the domestic procurement for geothermal plant construction is much higher than that for coal-fired plant construction, its domestic production increase effect per unit capacity is IDR 27.7 billion, 3.4 times the coal-fired equivalent. Similarly, the value added increase is IDR 15.7 billion (4.4 times), the employee income increase, IDR 2.5 billion (2.9 times) and the employment increase, 168 jobs (2.5 times). These reveal that geothermal plant construction affects the domestic economy more positively than coal-fired construction. Power plant construction of 60 MW, for example, creates 10,060 jobs for a geothermal plant, while only 4,070 are created for coal-fired plant (Fig. 7.7-4). <Geothermal Acceleration Effects from 2012 to 2016>

As presented in section 7.1, the construction of 2,400 MW of geothermal capacity is expected from 2012 to 2016. Table 7.7-9 presents a case study of the economic effects of these 2,400 MW should the capacity be developed with coal-fired plants instead of geothermal ones, while Table 7.7-10 presents the economic effects when all 2,400 MW are developed geothermally. Table 7.7-11 shows the differences between the two cases.

If geothermal power of a total capacity of 2,400 MW should be developed in the period from 2012 to 2016 instead of coal-fired power, the additional investment will be about IDR 43,224 billion. With this increase in investment, domestic production will increase by IDR 47,088 billion, employee wages will increase by IDR 3,984 billion, and employment opportunities will increase by 240 thousand jobs, as Table 7.7-11 shows. These results suggest the possibility of an Indonesian “Green New Deal Policy”, which aims at economic development and job creation through renewable energy development.

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7-6

Con

stru

ctio

n ef

fect

s of a

coa

l-fire

d po

wer

pla

nt (6

0 M

W e

quiv

alen

t)

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

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ate

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ate

Sect

or

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ther

mal

Ene

rgy

Dev

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men

t in

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Rep

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ndon

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Oil,

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finar

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teel

Con

stru

ctio

n

Rea

l est

ate

& B

usin

ess

serv

ice

Dom

estic

Tota

l

181

m$

41 m

$5

m$

12 m

$22

m$

18 m

$5

m$

104

m$

76 m

$(1

00%

)(2

3%)

(3%

)(7

%)

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)(1

0%)

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)(5

8%)

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55 m

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97 m

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252

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475

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(100

%)

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Geo

ther

mal

Coa

l

60 M

W

600

MW

Inve

stm

ent B

reak

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n

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cure

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tfro

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port

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er P

lant

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acity

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vest

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cure

men

t for

m D

omes

tic M

arke

t

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p/M

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oal)

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p/M

W(G

eo/C

oal)

mR

p/M

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p/M

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on/M

W(G

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oal)

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ther

mal

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10(2

.5)

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85(4

.1)

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)

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0(1

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68(1

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eren

ce)

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6,60

0 m

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3,12

0 m

Rp

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p15

0,41

4 m

Rp

10,0

59 p

sn.

180.

7 m

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m$

166.

2 m

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$15

.0 m

$-

(Not

e) E

xcha

nge

rate

is a

ssum

ed to

be

1US

$=10

,000

Rp.

Em

ploy

men

t Inc

reas

eEf

fect

Eco

nom

ic E

ffect

of P

ower

Pla

nt C

onst

ruct

ion

Geo

ther

mal

(60M

W C

ase)

Dom

estic

Pro

cure

men

tP

ower

Pla

ntTo

tal I

nves

tmen

tD

omes

tic P

rodu

ctio

nIn

crea

se E

ffect

Val

ue A

dded

Incr

ease

Effe

ctW

age

Incr

ease

Effe

ct

Tabl

e 7.

7-7

Com

paris

on o

f dom

estic

pro

cure

men

t of g

eoth

erm

al a

nd c

oal-f

ired

pow

er p

lant

s

Tabl

e 7.

7-8

Com

paris

on o

f con

stru

ctio

n ef

fect

s of g

eoth

erm

al a

nd c

oal-f

ired

pow

er p

lant

s

Study on Fiscal and Non-fiscal Incentives to Accelerate Geothermal Energy Development by Private Sector in the Republic of Indonesia Interim Report

JICA West JEC

7-28

Power PlantGeothermal

Effect(b)-(a)

DomesticProductionIncrease Effect

Value AddedIncrease Effect

Wage IncreaseEffect

EmploymentIncrease Effect

(MW) (mRp) (mRp) (mRp) (mRp) (mRp) (Person)2012 - 10,806,000 7,920,000 11,772,000 7,260,000 996,000 59,9162013 - 10,806,000 7,920,000 11,772,000 7,260,000 996,000 59,9162014 - 10,806,000 7,920,000 11,772,000 7,260,000 996,000 59,9162015 - 0 0 0 0 0 02016 - 10,806,000 7,920,000 11,772,000 7,260,000 996,000 59,916

TOTAL - 43,224,000 31,680,000 47,088,000 29,040,000 3,984,000 239,665

TotalInvestment

DomesticProcurement

Economic Effect of Power Plant Construction

Power Plant

Coal PP (a)DomesticProductionIncrease Effect


Wage IncreaseEffect


12,100 4,190 8,090 3,610 850 68mRp/MW mRp/MW mRp/MW mRp/MW mRp/MW Person/MW

(MW) (mRp) (mRp) (mRp) (mRp) (mRp) (Person)2012 600 7,260,000 2,514,000 4,854,000 2,166,000 510,000 40,6752013 600 7,260,000 2,514,000 4,854,000 2,166,000 510,000 40,6752014 600 7,260,000 2,514,000 4,854,000 2,166,000 510,000 40,6752015 0 0 0 0 0 0 02016 600 7,260,000 2,514,000 4,854,000 2,166,000 510,000 40,675

TOTAL 2,400 29,040,000 10,056,000 19,416,000 8,664,000 2,040,000 162,699

Economic Effect of Power Plant ConstructionDomestic

ProcurementYEAR

ConstructionEffect

TotalInvestment

Power Plant

GeothermalPP (b)

DomesticProductionIncrease Effect


Wage IncreaseEffect


30,110 17,390 27,710 15,710 2,510 168

mRp/MW mRp/MW mRp/MW mRp/MW mRp/MW Person/MW(MW) (mRp) (mRp) (mRp) (mRp) (mRp) (Person)

2012 600 18,066,000 10,434,000 16,626,000 9,426,000 1,506,000 100,5912013 600 18,066,000 10,434,000 16,626,000 9,426,000 1,506,000 100,5912014 600 18,066,000 10,434,000 16,626,000 9,426,000 1,506,000 100,5912015 0 0 0 0 0 0 02016 600 18,066,000 10,434,000 16,626,000 9,426,000 1,506,000 100,591

TOTAL 2,400 72,264,000 41,736,000 66,504,000 37,704,000 6,024,000 402,365

Economic Effect of Power Plant Construction

YEAR

TotalInvestment

DomesticProcurement

ConstructionEffect

Table 7.7-9 Effects of coal-fired power plant construction (2012 – 2016) ~ Business as usual scenario ~

Table 7.7-10 Effects of geothermal power plant construction (2012 – 2016) ~ Geothermal acceleration scenario ~

Table 7.7-11 Deference of effects between two scenarios (2012 – 2016) ~ Effects of geothermal acceleration scenario ~

Study on Fiscal and Non-fiscal Incentives to Accelerate Geothermal Energy Development by Private Sector in the Republic of Indonesia Interim Report

JICA West JEC

7-29

10,060

4,070

0 2,000 4,000 6,000 8,000 10,000 12,000

Geothermal PP

Coal-fired PP

Employment (person)

181

73

104

25

166

49

94

22

0 50 100 150 200

Geothermal PP

Coal-fired PP

Investment / Effect (million US$)

Total Investment Domestic Procurement Domestic Production Increase Effect Value Added Increase Effect

0 1,000 2,000 3,000

GeothermalPP

Coal-fired PP

Procurement ($/kW)

Oil,Gas, Geothermal mining(Drilling service)Oil refinary (Fuel)

Cement

Steel

Construction

Real estate & BusinessserviceImportForeign Procurement (42%)

Domestic Procurement (35%)

Domestic Procurement (58%)

Foreign Procurement (65%)

1,210 $/kW

3,010 $/kW

Fig.7.7-2 Comparison of investment in power plant construction (per kW)

Fig7.7-3 Effects on domestic economy of 60 MW power plant construction

Fig.7.7-4 Employment increase for 60MW power plant construction

CHAPTER 8

SHORT-TERM INCENTIVES TO

PROMOTE GEOTHERMAL

DEVELOPMMENT


JICA West JEC 8-1

0

20

40

60

80

100

120

140

160

2000

2001

2002

2003

2004

2005

2006

2007

2008

WTI

Spo

t Pric

e (F

OB

) (U

S$/

B)

(Source) US Energy Information Administration

CHAPTER 8 SHORT-TERM INCENTIVES TO PROMOTE GEOTHERMAL DEVELOPMMENT

8.1 Market Failure and Necessity of Government Intervention

In Indonesia, electric power generation is carried out by the National Power Company, PT PLN and IPP companies. Both parties endeavor to supply power at competitive prices. However, the steep increase in fuel prices that started 2 years ago has strongly influenced Indonesia’s energy market to alter its energy pricing paradigm (Fig. 8.1-1 & Fig. 8.1-2). The coal price (5,300kcal/kg base) is expected to remain 90 USD/ton, the domestic natural gas price around 6 USD/MMBTU, the LNG price for export around 13 USD/MMBTU, the fuel oil price for generation (MFO) around 110 USD/barrel and the diesel price (HSD) around 140 USD/barrel. Also the drilling costs for geothermal steam wells have skyrocketed in the past 2 years to 5 USD million/well from 3 USD million/well.

Due to the changes in energy prices, the generation costs from various energy sources have significantly altered during last 2 years. The selling price calculation method the Study Team introduced in Chapter 5 and Chapter 6 is now applied to other energy sources. Fig. 8.1-3 shows the calculation results. Based on the current energy price status quo Fig. 8.1-3 indicates that the cheapest generation source is gas-fired combined-cycle power generation (GCC) followed by coal-fired power generation. The selling price of geothermally generated power exceeded 10 USD Cents/kWh due to the increase in drilling costs. The low cost of GCC is due entirely to the far cheaper domestic fuel gas price (6 USD/MMBTU) compared to the international market price (13 USD/MMBTU). Nevertheless, domestic gas production is decreasing and some gas-fired power plants may need to switch from gas to oil. Therefore, PT PLN and IPPs see coal as the main source of power generation. This is a natural reaction for entities that seek competitive prices following market principles. （Source：Argusmedia group）

Fig.8.1-1 WTI Spot Price variation Fig. 8.1-2 Coal Price variation in Indonesia（5,800kcal/kg）


JICA West JEC 8-2

0 10 20 30 40 50

Diesel

Steam (MFO)

Gas CC

Steam (Coal)

Geothermal

Selling Price (C$/kWh)

Capital Cost Fuel Cost Opportunity Cost

Oppotunity Cost (= Fuel Cost)Geothermal NO Coal 4.2 C$/kWh Gas CC (for LNG) 9.3 C$/kWh

Steam 17.6 C$/kWh

Diesel 21.7 C$/kWh

0 10 20 30 40 50

Diesel

Steam (MFO)

Gas CC

Steam (Coal)

Geothermal


Capital Cost Fuel Cost

Fuel Price

Oil 100 US$/B

Coal 90 US$/ton

N' Gas 6.0 US$/MMBTU (Domestic price) 13.0 US$/MMBTU (International price)

MFO 110 US$/B HSD 140 US$/B

Capital CostGeothermal 3,010 US$/kW

Coal 1,210 US$/kW

Gas CC 800 US$/kW

Steam 1,000 US$/kW

Diesel 1,150 US$/kW

Fig. 8.1-3 Estimated selling prices of power by fuel sources

One must not forget that the natural gas and the coal consumed in the power plants are precious natural resources that can be exported. Merely consuming them as fuel for power generation should be seen as a loss of economic opportunity. In accounting for the economy of each power plant from the broader point of view of the overall national economic interest, these opportunity losses must be taken into consideration. Fig. 8.1-4 shows the impact of these losses. It indicates that geothermal power generation could be the most cost-competitive form of generation. However, this “cost of lost opportunity” is negligible for players acting only in compliance with market principles. Therefore, they tend to choose coal-fired power generation, instead of geothermal power generation. As a result, the various benefits of geothermal power generation are lost. This constitutes a failure of market, and clearly some form of government intervention is required to enable an optimal mix of energy sources.

Fig. 8.1-4 Estimated selling prices of power taking into account opportunity costs


JICA West JEC 8-3

0 10 20 30 40 50

Diesel

Steam (MFO)

Gas CC

Steam (Coal)

Geothermal


Capital Cost Fuel Cost Opportunity Cost Environmental Cost

CO2 Price 20 US$/ton CO2

CO2 EmissionFactorGeothermal 0.002 kg/kWh Coal 0.957 kg/kWh Gas CC 0.421 kg/kWh

Steam 0.734 kg/kWh

Diesel 0.702 kg/kWh

Furthermore, we can consider the environmental impact of thermal power plants. Thermal power plants emit greenhouse gases such as SOx, NOx, dust and CO2. These environmental impacts lead to health problems in local residents, thereby increasing the medical costs of the society. Although the global trend is to reduce greenhouse gas emissions, these environmental costs are not considered to be the responsibility of emitters. This means that the emissions of power suppliers are an externality which the local government pays a price for. Fig. 8.1-5 represents these impacts. Economics sees these externalities created by “demerit goods” as indicating a failure of markets and the necessity of encouraging government intervention.

As explained in Chapter 7, geothermal power generation brings direct and indirect benefits to the society and the government. However, these benefits are not considered in the power generation market, and they are therefore lost in the market mechanism. In order to realize these benefits, the government needs to intervene in the market. Government intervention can take various forms. For example, the government can apply taxation to conventional thermal energy, or they can provide fiscal incentives for geothermal energy. This chapter discusses the fiscal and non-fiscal incentives for geothermal energy development. （Note） CO2 emission factor of geothermal refers to CRIEPI Review No.45 2001 (Nov)

CO2 emission factor of other fuel refers to 2006 IPCC Guideline for National Greenhouse Gas Inventories

Fig. 8.1-5 Estimated selling price of power accounting for environmental impact costs

8.2 Geothermal Energy Promotion Policy

As stated in Chapter 2, geothermal energy promotion policy can be divided into compulsory-type policy, which obliges power companies (or end-users) to bear the costs, and


JICA West JEC 8-4

Benefit of GeothermalEnergy

Geothermal Selling Price Benchmark Price

Val

ue /

Pric

e (C

$/kW

h)

PLN

Government

SocialGovernment Gross Benefit (GBgov)

Price Gap (Pgap)

Social Gross Benefit (GBsoc)

Government Net Benefit (NBgov)

incentive-type policy, in which the government bears the costs. Compulsory-type policy includes a fixed price buying system and a renewable energy quota system. On the other hand, incentive-type policy includes tax incentives, fiscal incentives and financial incentives. Table 8.2-1 shows the characteristics of these policies.

As stated in Chapter 7, geothermal power generation brings about various benefits for the society and the government. However, because of its higher price compared with benchmark coal-fired power generation, the market alone does not promote geothermal power generation automatically. Therefore, government interventions are required to realize the benefits of geothermal power generation.

Fig. 8.2-1 Incentive cost and benefit ＜Compulsory-Type Policy＞

Compulsory-type policy aims to realize the benefits of geothermal power generation to the society（GBsoc）and to the government（GBgov）by obliging PT PLN to utilize geothermal energy. The difference between the selling prices of geothermal power and coal-fired power (Pgap)will be borne by PT PLN (or end-users), and therefore the government enjoys the full benefit of GBgov. However, PT PLN relies heavily on the government to compensate for its financial deficits. Also, end-users will not tolerate any increases in electric power tariffs. Therefore, the government will end up bearing the price gap（Pgap）after all. In this case, the benefit to the government becomes NBgov, which is GBgov minus Pgap（＝GBgov-Pgap）.

＜Incentive-Type Policy＞

Incentive-type policy aims to realize the benefits of geothermal power generation to the society and to the government by providing supports to bridge the price gap（Pgap）. In this


JICA West JEC 8-5

case, since the government bears the incentive costs (IC), the government’s benefit will be NBgov（＝GBgov - IC）.

When the government provides incentives, some leverage effects may appear, but they are small in scale. These leverage effects are typically observed in the execution of fiscal incentives. As shown in Fig. 8.2-2, the selling price of geothermal power (P) consists of generation costs (C), tax (T) and investment returns (R). P = C + T + R (8.1) Or their differentials can be expressed as below: ΔP = ΔC + ΔT + ΔR (8.2)

Fiscal incentives show effects in reducing generation costs (ΔC). Generation costs (C), investment returns (R) and tax (T) are related in the following ways: R = α*C (8.3) T = t *R (8.4) where α is the ratio of investment return to generation costs and t represents the tax rate. Although α is a function determined by the expected rate of return of investors and generation costs, we provisionally treat it as a fixed figure here. These relations allow us to develop formula (8.2) into the following formulas:

ΔP = ΔC + ΔT + ΔR

＝ ΔC + α*t*ΔC + α*ΔC ＝（1+α*t＋α）ΔC (8.5)

The ΔC of formula (8.5) represents reductions in generation costs through the direct effect of fiscal incentives. SoΔC is equal to the incentive cost (IC). ΔT is the tax reduction attributable to the selling price reduction realized by fiscal incentives. ΔR is the reduction in investment returns due to reduction in generation costs. Therefore, the selling price reduction effect（ΔP）is bigger than the incentive costs provided by the government（ΔC）because of the leverage effect. That is to say, ΔC is the direct cost and ΔT is the indirect cost to government, but these will instigate investors to reduce their required investment returns. This is deemed to be a collateral effect and the governmental net benefit (NBgov) increases by this amount (Fig.8.2-3).

Tax Incentives only show limited leverage effects. Tax Incentives reduce tax (T) and


JICA West JEC 8-6

Geothermal Selling Price Geothermal Selling Price(after incentive)

R

△RR'

△T

△C

T

CC'

T'

△C+△T+△R

Incentive



OthersO&M Cost


have no impact on generation costs (C). Therefore, ΔC=0. Also, (8.4) indicates R =T/t to obtain (8.6). The equation of (8.6) shows the leverage effects are limited (Fig. 8.2-4). ΔP＝ΔT+Δ(T/t) (8.6)

Financial incentives come in the form of low-interest-rate loans, and thereby bring down the expected rate of return as well. This reduction in the expected rate of return leads to a reduction in R through the reduction in α. Also, smaller interest payments contribute to reducing the generation costs (C). At a result, the selling price can be reduced by the total amount of reduced items (Fig. 8.2-5). The leverage effect may also be limited in this case. ＜Benefit to Government＞

Chapter 7 shows that geothermal power generation brings 5.8 USD Cents/kWh of benefit to the society（GBsoc）and 3.8 USD Cents/kWh of benefit to the government（GBgov）, when the crude oil price is set at 100 USD/barrel. On the other hand, the price gap between geothermal power generation and benchmark coal-fired power generation (Pgap)is calculated to be 3.7 USD Cents/kWh. Therefore, the benefit to the government remains at 3.8 USD Cents/kWh with compulsory-type policy (because the government does not bear the incentive cost). However, when incentive-type policy prevails, where the government bears the price gap and incentive cost, the net benefit to the government (NBgov＝GBgov-Pgap-IC) becomes 0.1 USD Cents/kWh (3.8 USD Cents/kWh – 3.7 USD Cents/kWh). At this point, the benefit to the government is positive, and in addition, the society enjoys a big benefit of 5.8 USD Cents/kWh (GBsoc), making this option worth considering.

In the next sections, the effects of various incentives are discussed. Fig. 8.2-2 Composition of selling price Fig. 8.2-3 Effect of fiscal incentives


JICA West JEC 8-7


R △R R'

△T

△C

T

C C'

T'

△C+△T+△RIncentive

Incentive


R

△R+△T

R'

△TT

C C

T'

Incentive

△R

Fig. 8.2-4 Effect of tax incentives Fig. 8.2-5 Effect of financial incentives

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

Geo

ther

mal

Ene

rgy

Dev

elop

men

t in

the

Rep

ublic

of I

ndon

esia

Fina

l Rep

ort

JI

CA

Wes

t JEC

8-8

Tabl

e 8.

2-1

Cla

ssifi

catio

n of

Ren

ewab

le E

nerg

y Pr

omot

ion

Polic

ies

Ty

pe

Polic

y C

onte

nts

Cos

t bea

rer

Adv

anta

ges

Dis

adva

ntag

es

Exam

ples

Fi

xed

Buy

ing

Pric

e Sy

stem

・

The

gove

rnm

ent s

peci

fies

the

purc

hase

pric

e fo

r th

e fo

rced

pur

chas

e of

ren

ewab

le e

nerg

y (R

E).

・Th

e pr

ice

is s

peci

fied

as a

cer

tain

rat

e (e

.g.

90 %

) of

the

tarif

f or

an

abso

lute

pric

e (e

.g.

7.0

USD

cen

ts/k

Wh)

・

If

the

pric

e le

vel

is

appr

opria

te, i

t will

exp

edite

RE

rapi

dly

(exa

mpl

es:

win

d po

wer

in

Ger

man

y an

d D

enm

ark)

. ・

RE

pow

er c

ompa

ny is

abl

e to

m

ake

the

inve

stm

ent s

tabl

e.

・

The

cost

to u

tiliti

es is

hea

vy.

・

Ther

e is

lit

tle

ince

ntiv

e to

re

duce

R

E co

sts.

・

The

setti

ng o

f th

e pr

ice

leve

l is

diff

icul

t an

d w

hen

it is

set

to

o lo

w,

the

RE

intro

duct

ion

does

not

pro

ceed

.

PUR

PA

law

(U

.S.A

.) Po

wer

pu

rcha

se

law

(G

erm

any)

Com

puls

ory

Type

Quo

ta S

yste

m

・

To

mak

e th

e in

trodu

ctio

n of

R

Es

com

puls

ory,

go

vern

men

t fo

rces

po

wer

co

mpa

nies

to

gene

rate

a c

erta

in a

mou

nt o

f el

ectri

city

fro

m R

E its

elf

or p

urch

ase

RE

from

out

side

. ・

Th

e m

etho

d in

whi

ch th

e ra

tio o

f REs

to th

e to

tal

gene

rate

d en

ergy

is

spec

ified

is

calle

d “R

enew

able

Por

tfolio

Sta

ndar

d” (R

PS).

・

Ack

now

ledg

ing

certi

ficat

ion

of

RE

is

issu

ed a

nd t

he p

urch

ase

pric

e is

dec

ided

by

the

mar

ket

for

trada

ble

gree

n ce

rtific

ates

(T

GC

).

Pow

er

com

pany

(U

tility

)

・

Cos

t co

mpe

titio

n ca

n be

cr

eate

d am

ong

REs

an

d co

st-r

educ

tion

ince

ntiv

es s

tart

to

wor

k.

・

The

rela

tions

hip

betw

een

the

purp

ose

of i

ntro

duct

ion

of R

Es

and

the

targ

et a

mou

nt o

f R

Es

beco

mes

cle

ar.

・ B

ecau

se t

he p

rice

of T

GC

s is

de

cide

d in

th

e m

arke

t, it

is

likel

y to

be

unst

able

, m

akin

g th

e in

vest

men

t ris

k fo

r R

E la

rger

.

RPS

la

w

(U.S

.A.,

UK

, Ja

pan

and

othe

rs)

Tax

Ince

ntiv

es

・

Pref

eren

tial

tax

rate

, ta

x ho

liday

s, or

tax

cr

edits

are

app

lied

to t

he R

E bu

sine

ss a

nd

intro

duct

ion

of R

E ge

nera

tion

equi

pmen

t.

・

The

redu

ctio

n of

tax

prod

uces

an

in

cent

ive,

bu

t no

ac

tual

m

oney

is n

eede

d fo

r inc

entiv

es.

・B

ecau

se i

t is

a k

ind

of p

assi

ve

polic

y,

the

indu

cem

ent-a

ttrac

tion

is w

eak.

Prod

uctio

n ta

x cr

edit

(U.S

.A.)

Fisc

al

Ince

ntiv

es

(Gov

ernm

ent

Expe

nditu

re)

・Th

e go

vern

men

t di

rect

ly

supp

orts

th

e pr

omot

ion

of

REs

by

m

eans

of

fis

cal

expe

nditu

re

such

as

a

subs

idy

for

cons

truct

ion

cost

s.

・Th

is i

s di

rect

sup

port

for

the

prom

otio

n of

RE

proj

ects

and

th

e ef

fect

is re

mar

kabl

e.

・Th

e go

vern

men

t fin

ance

bur

den

is h

eavy

C

onst

ruct

ion

cost

su

bsid

y (D

enm

ark,

Ja

pan)

Ince

ntiv

e ty

pe

Fina

ncia

l In

cent

ives

・

Fina

ncia

l sup

port

for t

he p

rom

otio

n of

RE

by

finan

cing

at

lo

w

inte

rest

ra

tes

from

go

vern

men

tal b

anks

.

Gov

ernm

ent

・B

ecau

se

this

fin

anci

ng

is

repa

yabl

e,

it m

aint

ains

th

e en

trepr

eneu

r’s c

onsc

ious

ness

of

owne

rshi

p.

・A

lar

ge a

mou

nt o

f in

itial

fun

ds

are

need

ed

as

capi

tal

for

finan

cing

.

Low

in

tere

st

rate

lo

ans

(Jap

an,

U.S

.A.,

Ger

man

y et

c.)


JICA West JEC 8-9

8.3 The Feed-in Tariff (FIT) Scheme

Many countries oblige power companies to purchase power from renewable energy sources at fixed prices to promote renewable energy. The fixed purchase price can be specified as a certain ratio (e.g. 90%) of the retail tariff or as a definite price (e.g. 15 Euro cents/kWh) for each renewable energy source. One of the examples of the latter is the PURPA in the USA. Nowadays, the Feed-in Tariff scheme seen in Germany and the EU is becoming popular.

In 1978, the United States Federal Government enacted “The Public Utility Regulatory Policies Act (PURPA)”. The PURPA places power companies under an obligation to buy power from the Qualifying Facilities (QFs) at the Avoided Price. QFs are defined as non-power companies with an equipment capacity less than 80 MW and which engage in cogeneration or renewable energy power generation. The definition of “Avoided Price” was left to respective states. In California, the avoided price was defined as “the price of natural gas-fired and oil-fired power generation”. Because of this high price, the development of renewable energy (particularly wind power generation) was very successfully promoted. Thereafter, however, partly because the price of crude oil fell and partly because in 1995 the Federal Government unified the definition of the Avoided Price as “the cost at which the power company itself generates power, or the cost at which it buys the power from other power companies”, the development of renewable energy stagnated. However, the role of the PURPA was very significant in promoting renewable energy1.

In 1991, Germany enacted “The Electricity Feed-in Law”. This Law places power

companies under an obligation to buy renewable power at a price of 90% of the general power tariff to the end-user with an upper limit of 5% of sales. This has contributed greatly to increasing renewable energy generation in Germany, particularly the capacity of wind power generation. In 2000 Germany further enacted the “Renewable Energy Law”. Under this law, the system for setting the purchase price as a ratio of the power tariff was replaced by a system for setting the purchase price at absolute values for each respective form of renewable energy. The reason for the change is that the purchase price of electricity was lowered by the liberalization of the power business, and it was feared that the purchase price for renewable power would drop2. The purchase prices per kWh as of 2006 are3: Hydro 6.7- 9.7 Euro cents/kWh Biomass 3.8 - 21.2 Euro cents/kWh Geothermal 7.2 - 15.0 Euro cents/kWh Wind 9.1 Euro cents/kWh Solar 40.6 - 56.8 Euro cents/kWh 1 Energy Information Agency, USA Non-Hydraulic renewable energy promotion policy (Feb., 2005) 2 Ibid. 3 Arne Klein et al, Evaluation of different feed-in tariff design options, The World Future Council


JICA West JEC 8-10

These prices are guaranteed for 20 years (30 years for mini hydro) of the period of

investment recovery (fixed price system). In an amendment to the “Renewable Energy Law” in 2008, the purchase price was increased to 10.5 Euro cents/kWh for geothermal power plants with more than a 10 MW capacity and 20.0 Euro cents/kWh for geothermal power plants with a capacity less than or equal to 10 MW4.

Table 8.3-1 Feed-in Tariff prices for geothermal plants in Germany (January, 2009）

Capacity FIT Price Less than or equal to 10 MW 20.0 Euro cents/kWh More than 10 MW 10.5 Euro cents/kWh

Thanks to the “Electricity Feed-in Law”, wind power generation in Germany rapidly

increased from 48 MW in 1990 to 4,443 MW in 1999. Furthermore, the fixed price system of the “Renewable Energy Law” provided a further great impetus to the development of renewable energies. In 2007, the capacity of wind power generation reached 22,247 MW. Under this policy, renewable energies now account for 14.2% of the total power generation, already exceeding the 2010 target of 12.5%.

In the EU, the successful introduction of FIT in Germany encouraged other nations to follow the same strategy. Fig. 8.3-1 shows the renewable energy policies of 25 EU nations. 18 nations out of 25 have adopted the FIT scheme. Table 8.3-1 shows the FIT prices and terms for these nations.

As proven by Germany, FIT can promote renewable energy development swiftly if the price is set at an adequate level. In the EU, there are some reports discussing the 4 Ing.H.Kreuter, Feed-in Tariff in Germany, German Geothermal Society, (June,2008)

（Source）Arne Klein et al, Evaluation of different feed-in tariff design opt

Fig. 8.3-1 Renewable energy development policies of 25 EUnations


JICA West JEC 8-11

superiority of FIT over RPS (Renewable Energy Portfolio Standard, Cf. Section 8.4 below). However there are no structural differences in the efficiency of FIT and RPS, and what differences there are are just the result of their application. The cases of Germany and Spain indicated the efficiency of FIT, but in the case of Italy FIT allegedly did not prove efficient. The challenging and key point is the setting of an adequate purchase price level5.

5 Arne Klein et al, Evaluation of different feed-in tariff design options, The World Future Council


JICA West JEC 8-12

Table 8.3-2 FIT prices and purchase terms for 18 EU nations

（Source）Evaluation of different feed-in tariff design options, Arne Klein et al, The World Future Council

＜Proposal for FIT introduction to Indonesia＞

FIT may be introduced to Indonesia. The selling price calculation for geothermal power generation in Chapter 5 indicated that 11.9 USD Cents/kWh is necessary if no specific


JICA West JEC 8-13

(C$/kWh)

Stage Year FixedPrice Case-1 Case-2 Case-3

1 st stage 1-8 th year 11.9 12.2 12.5 12.82 nd stage 9- 30 th year 11.9 10.6 9.3 8.1Average (discount rate=12%) 11.9 11.7 11.6 11.5


1 st stage 1-8 th year 1.000 1.037 1.074 1.1112 nd stage 9- 30 th year 1.000 0.900 0.800 0.700（Note) These cases are equivalent over 15 years at the discount rate of 12%.

incentives are provided. Here, the Study Team uses this figure as a provisional FIT price for the case in which there are no incentives. Note that this calculation assumed a 15-year period of economical evaluation for investors. Accordingly, the FIT purchase term shall be 15 years. The purchase price from the 16th year shall be subject to negotiations between PT PLN and investors. The purchase price should be enough to compensate for O&M costs, the remaining depreciation, the drilling costs for additional make-up wells and tax. Only investment return for initial investment can be ignored at this stage.

The FIT price does not have to be fixed; it can escalate or change in phases. FIT price

changes may be appropriate when generation cost changes are taken into consideration. The generation cost for geothermal power plants decreases in step with amortization. Therefore, a top-heavy purchase price may work favorably for investors. This sub-section considers a 2-stage FIT price system, which has a price for year 1 to year 8 as the 1st stage and another price for year 9 to year 15 as the 2nd stage. The purchase price after year 16 is open to negotiation among stakeholders. To equalize two price systems, the value of prices over 15 years in the 2-stage FIT price system should be same as those of the fixed FIT price system in the net present value base. A discount rate of 12%, which equals the capital costs of PT PLN, is used to calculate the net present value of prices. With the selling price calculation model introduced in Chapter 5, three kinds of 2-stage FIT price patterns shown in Table 8.3-3 and Fig. 8.3-3 are calculated. The results of the calculations are shown in Table 8.3-4 and Fig. 8.3-4. In these 3 cases, a higher case number indicates a bigger tariff in the first stage. The higher numbered are more favorable to investors because the project can be carried out at substantially lower FIT price.

Table 8.3-3 Price change patterns for 2-stage FIT price system

Table 8.3-4 Price calculation results for 2-stage FIT price system（at 25% tax rate）


JICA West JEC 8-14

0.0000

0.2000

0.4000

0.6000

0.8000

1.0000

1.2000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Years

Pric

e le

vel

Case-1Case-2Case-3

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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Years

Pric

e le

vel

Case-1

Case-2

Case-3

Tax = 25% (32.5%)

(C$/kWh)


1 st stage 1-8 th year 10.9 11.2 11.5 11.82 nd stage 9- 30 th year 10.9 9.7 8.6 7.4Average (discount rate=12%) 10.9 10.8 10.7 10.6

Fig. 8.3-2 Price change patterns of 2-stage Fig.8.3-3 Prices under 2-stage FIT price system

FIT price system (at 25% tax rate)

Shown above are the calculation results with a 25% tax rate. Geothermal IPPs bear heavier taxes than coal-fired IPPs. Therefore, some tax incentives should be provided for geothermal power generation. While detailed tax incentives will be discussed in Section 8.5, FIT prices under a preferential tax rate of 5% for 15 years are also calculated here. Calculation of a fixed FIT price and the prices for 3 cases in a 2-stage FIT price system are shown in Table 8.3-4. The fixed FIT price under tax incentives is calculated as 10.9 USD Cents/kWh. The 2-stage FIT price system yields prices that are 0.9 USD cents/kWh smaller than those for the 25% tax case. Fig. 8.3-5 and Fig. 8.3-6 show the generation cost and FIT price in the business as usual case (tax rate = 25%) and the tax incentive case (tax rate = 5 % for 15 years).

Table 8.3-5 Fixed FIT price and 2-stage FIT prices (at 5 % tax rate for 15 years） The considerations outlined above lead to the following proposals:


JICA West JEC 8-15

0.0

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4.0

6.0

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12.0

14.0

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Year

Sel

ling

Pric

e (C

$/kW

h)

Depreciation (initial) Depreciation (additional) O&MRoyalty Interest Case-3Fixed Price

Tax = 25% (32.5%)

Table 8.3-6 Proposal for FIT prices

60 MW case Term

Fixed FIT price 2 stage FIT price (Case-3)

Without Tax Incentive Y 1-8 Y 8-15

11.9 C$/kWh 11.9 C$/kWh

12.8 C$/kWh 8.1 C$/kWh

With Tax Incentive （15years, 5 % Tax）

Y 1-8 Y 8-15

10.9 C$/kWh 10.9 C$/kWh

11.8 C$/kWh 7.4 C$/kWh

Fig. 8.3-4 Generation costs and FIT price change during operation period（at 25% tax）


JICA West JEC 8-16

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Year

Sel

ling

Pric

e (C

$/kW

h)


Tax = 5%　(14.5%)　 (for 1-15 year) Fig. 8.3-5 Generation costs and FIT price change during operation period (at 5 % tax for 15 years）＜FIT price proposal to small scale geothermal IPP＞ In our discussion of FIT prices so far we have considered the case of 60 MW geothermal power plants which requires geothermal IPP projects in a large grid such as the Java-Bali system. Large grids enable large power plant installation, e.g. 600 MW in the case of coal-fired power plants, and 60 MW in the case of geothermal power plants. However, the small grids outside Java only require small power plants, e.g., 100 MW for coal-fire power plants, or 20 MW for geothermal power plants. This sub-section discusses the FIT prices for small projects.

Table 8.3-7 and Table 8.3-8 show the specifications and the selling prices for a 100 MW coal-fired power plant and a 20 MW geothermal power plant respectively. Both cases reflect the less economical nature of such projects, which is due to the relatively higher construction costs for smaller capacity plants. The selling price for the 20 MW geothermal power plant is 18.0 USD Cents/kWh, which is 6.8 USD Cents/kWh higher than the selling price for the 100 MW benchmark coal-fired power plant.


JICA West JEC 8-17

Table 8.3-7 Specifications and selling prices for a 100MW coal-fired power plant

Specifications Items Base Case Small Case

Capacity 600MW 100MW Const. Costs（w/o interest）（w interest）

USD 726 million USD 800 million


Costs/kW （w/o interest）（w interest）

1,210 USD/kW 1,330 USD/kW


Construction period 4 years Ditto Heat efficiency 38% 35% Heat value of fuel 5,300 kcal/kg Ditto Fuel Price 90 USD/ton Ditto Operation term 30 years Ditto

Selling price

8.2 USD Cents/kWh

11.2 USD Cents/kWh

Table 8.3-8 Specifications and selling prices for a 20 MW geothermal power plant

Specifications Items

Base Case Small Case Capacity 60 MW 20 MW Const. Costs（w/o interest）（w interest）



Costs/kW （w/o interest）（w interest）



Construction period 6 years ditto Production Well Depth 2,000 m ditto Production well steam output 8 MW/well ditto Generation efficiency 7.0 t/h/MW ditto Operation term 30 years ditto Make up Wells One in 5 years ditto

Selling price

11.9 USD Cents/kWh

18.0 USD Cents/kWh

Price Gap with Benchmark

3.7 USD Cents/kWh

6.8 USD Cents/kWh


JICA West JEC 8-18

(C$/kWh)

FixedPrice

StepPrice

FixedPrice

StepPrice

1 st stage 1-8 th year 18.0 20.0 17.6 19.02 nd stage 9- 30 th year 18.0 12.6 17.6 12.0Average (discount rate=12% 18.0 18.0 17.6 17.1

Stage YearTax = 25%

Tax = 5%for 1-15 year

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

20.0

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Year

Sellin

g P

rice

(C$/

kWh)


Tax = 25% (32.5%)

Table 8.3-9 shows the results of FIT calculation for a 20 MW geothermal power plant based on these assumptions. Fig. 8.3-6 and Fig. 8.3-7 show the change in FIT price and generation costs in a business as usual case and a tax incentive case.

Table 8.3-9 Selling price for a 20 MW geothermal power plant

These considerations lead to the following proposal:

Table 8.3-10 Proposal of FIT prices (20 MW or less capacity case）

20MW or less capacity case Term

Fixed FIT price 2 stage FIT price (Case-3)

Without Tax Incentive Y 1-8 Y 8-15

18.0 C$/kWh 18.0 C$/kWh

20.0 C$/kWh 12.6 C$/kWh

With Tax Incentive （5 % tax for 15 years）

Y 1-8 Y 8-15

17.6 C$/kWh 17.6 C$/kWh

19.0 C$/kWh 12.0 C$/kWh

Fig. 8.3-6 Generation costs and FIT price change during operation period (20 MW at 25% tax）


JICA West JEC 8-19

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

20.0

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Year

Sellin

g P

rice

(C$/

kWh)


Tax = 5% (14.5%)　(for 1-15 year)

Fig. 8.3-7 Generation costs and FIT price change during operation period (20 MW at 5 % tax for 15 years）

＜Periodical review of FIT prices＞

The above FIT prices are based on current values. For sustainable usage, an adjustment for price increases in the CPI is necessary. Also, these calculations assume a continuation of present economic circumstances. Therefore, FIT prices require periodical reviews. Furthermore, in accordance with Indonesian government regulations, the actual transaction of electricity sales is conducted in Rupiah. However, the price should be dollar-pegged to attract foreign investors. ＜Influence of FIT scheme＞

FIT obliges a power company to purchase power from renewable energy at a fixed tariff. The purchase cost will be borne by the power company and passed through to end-users. Let us measure the influence of FIT prices proposed in this Section. The fixed FIT price is 11.9 USD Cents/kWh without tax incentives. The price difference with the benchmark coal-fired power plant is 3.7 USD Cents/kWh, which will be borne by PT PLN. A 60 MW geothermal power plant generates approximately 445 GWh energy per year. Therefore PT PLN needs to absorb a price difference of USD 16.5 million per year. As discussed in Chapter 7, if 2,400 MW of geothermal power plants are developed as planned by 2016, the average power purchase from geothermal power plants during 2012 to 2016 will be 11,830 GWh (Table 7.2-3). During the same period, PT PLN’s annual average generation amount will be 251,813 GWh, meaning that


JICA West JEC 8-20

Item RemarksFIT Price 11.9 C$/kWh (a)Benchmark Price 8.2 C$/kWh (b)Price difference 3.7 C$/kWh (c)=(a)-(b)Geothermal cost reduction effect 0.3 C$/kWh (d) 60MW geothermal plant sales 444.7 GWh/year (e)Fiscal expenditure 16.5 m$/year (f)=(c)*(e)Geothermal plant annual sales 11,830 GWh/y (g) during 2012-2016PLN annual average sales 251,813 GWh/y (h) during 2012-2016Proportion of geothermal energy 4.70% (i)=(g)/(h)Amount of price Increase 0.17 C$/kWh (j)=(c)*(i)General tariff of PLN 7.00 C$/kWh (k)Price increase rate 2.48% (l)=(j)/(k)

Item IncreaseElectric tariff increase 2.48%Producer price increase 0.10%Consumer price increase 0.08%

4.7% of total generation will be supplied from geothermal. As a result, the purchase of geothermal energy will cause a 0.17 USD Cent/kWh increase in generation costs. When this cost increase is passed through to end-users, power bills will be 2.48% higher than for the current 7.0 USD Cents/kWh (Table 8.3-11).

Table 8.3-11 Influence of FIT scheme

The price analysis based on the Input Output Table (2005) indicates that a 2.48% increase in power bills will result in a 0.10% rise in the producer price and a 0.08% rise in the consumer price6. This is seen as a negligible influence when compared with the inflation rate of 2007 (6.4%). Therefore it can be recommended that the FIT price differential be passed through to end-users. Table 8.3-12 Influence of FIT passed through to end-users

If PT PLN cannot afford to absorb the FIT price, the government has to support it through subsidies. Since the cost reduction effect of geothermal power generation is 0.3 USD Cents/kWh, the same amount will be deducted from the government subsidy to PT PLN. As the result, the net subsidy will be 3.4 USD Cents/kWh, which means USD 15.1 million per annum for a 60 MW geothermal power plant.

6 The calculation process is shown in ANNEX-3.


JICA West JEC 8-21

Renewable Energy Supply (Q)

Ren

ewab

le E

nerg

y P

rice

(P)

FIT Price

RPS Quota

Renewable Energy Supply Curve(=Marginal Cost)

Fig. 8.4-1 FIT and RPS

8.4 The RPS Scheme

In an approach which differs from the FIT scheme, a quota system for renewable energy, which forces electric power companies to use a certain amount of renewable energy has also been widely adopted. Among these systems, an implementation which mandates a certain proportion of renewable energy in the total power generation mix is called the RPS (Renewable Energy Portfolio Standard) scheme. The U.S.A, UK and Japan have adopted this RPS scheme. Alongside the RPS scheme, many countries also adopt the Tradable Green Certificate (TGC) system, in which government issues TGCs to renewable energy producers which are tradable in the market. The market mechanism operating in the TGC system is expected to reduce the development cost of renewable energy.

In the U.S.A., the RPS scheme was first introduced in 1983. At present 24 states and one Special District have adopted this scheme. In California, where regulation is most severe, the RPS was introduced in January 2003. The RPS was introduced in the UK in April 2002 and in Japan in April 2004. The target of the renewable energy mandate in California is 20% by 2010. The target of renewable energy generation in Japan is 12.2 TWh by 2010, which will account for 1.35% of total energy generation, and 16.0 TWh by 2014. Renewable energy includes solar, wind, geothermal energy, micro hydraulic, biomass and others. But in Japan, only binary cycle generation plants are eligible from the geothermal power plant category.

In comparison with FIT, RPS has the merit, among others, of making clear the relation between the government’s targets for renewal energy use and government policy. Also, a reduction in the cost of renewable energy can be expected through competition among forms of renewable energy. On the other hand, RPS has the demerit, among others, that the price of TGCs is subject to market price volatility, thereby creating some investment risk.

If a supply curve function of renewable energy is clearly identified, FIT and RPS should have the same effects, meaning that the government can either set RPS development targets or set the FIT price in accordance with development targets. As with FIT, the key challenge of RPS is the setting of appropriate development targets. In the case of Japan, the critics claim that the development target for RPS is too small to realize appropriate development.


JICA West JEC 8-22

＜Proposal of RPS to Indonesia＞ According to the Geothermal Master Plan Study, geothermal energy development is

estimated to have reached 3,344 MW as of 2016. Therefore, if Indonesia applies RPS, the development target for 2016 should be 3,344 MW. The government should assign PT PLN to develop this capacity, with the costs of development to be borne by PT PLN. PT PLN needs to declare its responsibility to off-take geothermal power in order to achieve the development target.

One should note that PT PLN is already suffering chronic financial deficits and being supported by government subsidies. Therefore, PT PLN’s payment obligations will ultimately be borne by the government after all. Under such circumstances, there might be not much difference between the RPS and FIT schemes. Furthermore, RPS scheme needs more than one utility companies which form a market for trading excess power or Tradable Green Certificates. RPS scheme without this market would merely increase the financial burden of PT PLN and the subsidy burden of the government as a result, and would not be a sustainable scheme. 8.5 Tax Incentives

Tax incentives are designed to provide preferential treatment in the tax system to

promote renewable energies. Since the up-front investment is very large for renewable energy plants, preferential tax treatment has a great effect on renewable energy development.

Many countries have adopted tax incentives for renewable energy development. For

example, the US government has the Production Tax Credit (PTC) scheme. In 1992, the US government enacted the “Energy Policy Act”. By this act, when power is generated from wind or biomass, a “Production tax Credit” of 1.5 USD cents per kWh counts toward corporate taxes for 10 years. This tax credit is adjusted for inflation. This scheme expired in 1999, but has been revived several times since7. The latest revival was in October, 2008, and the latest tax credit for geothermal energy is 2.0 USD cents/kWh for 10 years.

Countries other than the United States also have a tax incentive system for renewable energy. For example, in Guatemala the corporate tax rate is 31%, but it has been the case since 2003 that renewable energy development can enjoy a tax exemption for 10 years. In Nicaragua, an exemption from the 30% corporate tax has been granted for 7 years for renewable energy development. In Panama as well, corporate tax is exempted up to a total of 25% of total investment for renewable energy power plants of less than 20 MW. In Asia, the Philippines enacted the Renewable Energy Act in December, 2008, and introduced this kind of tax credit system to promote renewable energy. (Table 8.5-1)

7 EIA Report Non-hydraulic renewable energies promotion policy in USA and major countries (Feb., 2005)


JICA West JEC 8-23

Country Philippines Guatemala Nicaragua Panama

General Tax Rate 35% 31% 30% 30%

Tax Holiday Term 7 yrs 10 yrs 7 yrs up to 25% of DirectInvestment

Base Law Renewable EnergyLaw

Law on theDevelopment of New

and RenewableEnergy

Law for Promotion ofElectricity

Generation withRenewable Energy

Law 45 of August2004

Start year 2008 2003 2005 2004

(Source: Philippines: http://www.doe.gov.ph/ipo/IncRE.htm CA: Economist Intelligence Unit, Country Commerce 2005)

Table 8.5-1 Tax exemption incentives for renewable energy

＜Tax incentives in Indonesia＞

The following Tax Incentives are currently in effect in Indonesia: (i) Import Duty Exemption

Equipment used for Geothermal development, such as boring machines, turbines, and generators have been exempted from import duty since April 2005（Minister of Finance Regulation No.26/ PMK. 010/2005）. Now new Ministry of Finance Regulations are the basis for this treatment (Minister of Finance Regulation No.177/PMK.0177/2007, No. 178/PMK 0178/2007).

(ii) 30% Investment Allowance With a view to encouraging investment, a total of 30% of the investment in specific

projects or specific regions is deductible from taxable profit at a rate of 5% each year for 6 years. Geothermal projects are eligible for this treatment (Government Regulation No.62/2008, Minister of Finance Regulation No.16/PMK.03/2007).

(iii) Accelerated Depreciation and 7-year Loss Carry Forward The Government Regulations mentioned above also allow specific projects to

accelerate deprecation and carry forward their losses for 7 years, and geothermal projects are eligible for this treatment.

The economic analysis in Chapter 6 has already mentioned this treatment. This

Chapter further studies the effects of additional tax incentives. (a) Accelerated Depreciation

Indonesia applies the depreciation formulas shown in Table 8.5-2. Taxpayers can choose either the straight-line method or the double-declining-balance method. Since its depreciation rate is twice of that of straight-line method, the double-declining-balance method is also known as the 200% declining balance method. The economic life of various equipment is determined in accordance with its actual life span. This Study uses the double-declining-balance method and applies Class-II depreciation for economic analysis.


JICA West JEC 8-24

Fig. 8.5-1 Effect of accelerated depreciation

Price Gap (Accelerated Depreciation)

11.9 11.9 11.9 11.9 11.9

6.07.0

8.0

9.010.0

11.012.0

13.0

Straightline

(100%)

Base(200%)

250% 300% 400%

Accelerated Depreciation (%)

Sellin

g P

rice

(C$/

kWh)

Selling Price Benchmark Price

Table 8.5-2 Depreciation schedule（Law No.36/2008）

Class Useful Life(years)

Declining Balance

Straight Line

Remarks

Class I 4 50% 25% Class II 8 25% 12.5% Geothermal PP Class III 16 12.5% 6.25% Class IV 20 10% 5% Building Permanent 5% Building Non-Permanent 10%

The Study Team has run the calculation on a case where a further accelerated

depreciation is applied in addition to the current depreciation. Fig. 8.5-1 shows the selling price of geothermal power with a 250%, 300%, 400% declining balance method instead of the standard 200%. A 200% declining balance gives a price of 11.9 USD Cents/kWh, while 400% also gives 11.9 USD Cents/kWh. It can be said that the accelerated depreciation has no impact on the selling price. This is because the depreciation is treated as an expenditure in accounting, but this expenditure does not necessitate actual cash outflow. (b) Investment Allowance

Next, the Study Team measured the effect of a 30% Investment Allowance. Fig. 8.5-2 shows the selling prices with the current 30% allowance（5%, 6 years）, 0%（no allowance）, 40%（5%, 8years）, 50%（5%, 10years）and 60%（5%, 12years. A 0% allowance results in a selling price of 12.4 USD Cents/kWh. This shows that the current allowance has a significant 0.5 USD Cents/kWh price reduction effect. If this allowance is expanded to 60%, the price will


JICA West JEC 8-25

Price Gap (Investment Allowance)

11.9 11.8 11.7 11.612.4

6.0

7.0

8.0

9.0

10.0

11.0

12.0

13.0

NoAllowance

Base (30%6yrs)

40%(8yrs) 50%(10yrs) 60%(12yrs)

Deductable Years

Sel

ling

Pric

e (C

$/kW

h)


Price Gap (Investment Allowance:w/o annual 5% restriction)

11.9 11.8 11.6 11.5 11.4

6.0

7.0

8.0

9.0

10.0

11.0

12.0

13.0

30% (5%6yrs)

30% 40% 50% 60%

Deductable Years

Sellin

g Pr

ice

(C$/

kWh)


be 11.6 USD Cents/kWh. As can be seen, this allowance has a significant impact, but since the annual deduction is limited to 5%, an extension of the deduction period proves to have limited effect. Fig. 8.5-2 Investment allowance effect Fig. 8.5-3 Investment allowance effect

（5% annual deduction）（without annual restriction）

The Study Team has calculated the cases where the 5% annual restriction has been removed. Fig. 8.5-3 shows the selling price with a 30%, 40%, 50% and 60% total allowance without the 5% annual restriction. Without this annual restriction, a 30% allowance gives a price of 11.8 USD Cent/kWh, and a 60% allowance gives 11.4 USD Cent/kWh. (c) Reduced Tax Rate

As seen in Chapter 7, the 11.9 UDS Cents/kWh selling price of geothermal power includes as much as 2.1 USD Cents/kWh（17.6%）of tax（Fig.8.5-4）. This amount is 1.6 USD Cents/kWh higher than that for coal-fired power. This is one of the reasons for the high selling price of geothermal power. We have seen that the effect of the Investment Allowance is significant, but its effect is limited as long as the tax deduction is based on taxable income. To avoid this problem, the Study Team has considered the case where tax rate itself is reduced as an incentive. Fig. 8.5-5 shows the selling prices of geothermal power with tax rate of 25%, 20%, 15%, 10% and 5%. The evaluation period is 15 years for this calculation. The results show that a 5% tax rate gives a price of 10.9 USD Cents/kWh, which is 1.0 USD Cents/kWh less than the no-incentive case. Even after this sizable tax cut, as shown in Fig. 8.5-6, geothermal power generation still pays the government 1.2 USD Cents/kWh including royalties. This is still 0.7 USD Cents/kWh more than or 2.6 times the tax paid on coal-fired power.


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0.0

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10.0

12.0

14.0


Bre

akdo

wno

fSel

lingP

rice（

c$/k

Wh）





Corporate Tax rate 25%Dividend tax rate 10%

Price Gap

11.9 11.6 11.4 11.1 10.9 10.8

6.0

7.0

8.0

9.0

10.0

11.0

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Base(25%)

20.0% 15.0% 10.0% 5.0% 0.0%

Tax rate for 15 years (%)

Sel

ling

Pric

e (C

$/kW

h)


＜Proposal of Tax Incentive＞ The 11.9 USD Cents/kWh selling price of geothermal power includes 2.1 USD

Cents/kWh of tax, but the price gap with coal-fired power is 3.7 USD Cents/kWh, so the tax incentive alone is not enough to bridge this price gap. Fig. 8.5-4 shows that the benchmark coal-fired power plant only pays 0.5 USD Cents/kWh in tax, while geothermal power generation pays 1.6 USD Cents/kWh more. Tax reduction can have a significant impact on the selling price and must be implemented.

Fig. 8.5-4 Tax on geothermal and coal-fired IPP business Fig. 8.5-5 Effect of tax incentives （at 25% tax rate）

A 30% Investment Allowance and Accelerated Depreciation are already in place as tax incentives. This reduces the selling price of geothermal power by 0.5 USD Cents/kWh. This incentive has proven very effective and should be continued. However, since the tax burden on geothermal power generation is still heavy, further tax incentives should be considered.

Here the Study Team proposes a tax rate reduction to 5% for 15 years as an additional incentive. This will bring down the selling price by a further 1.0 USD Cents/kWh. This scenario reduces tax revenues to the government during the period. This lost tax revenue is considered as the cost of the incentive, and it is evaluated as 0.9 USD Cents/kWh of present value in the commissioning year, when calculated with a 12% discount rate. This incentive cost brings about a 1.0 USD Cents/kWh price reduction effect. Since a 60 MW geothermal power plant generates approximately 445 GWh per annum, the reduction in annual government tax revenue is about USD 4.5 million a year.


JICA West JEC 8-27

Government Benefit

0.00.51.01.52.02.53.03.54.0

Base(25%)

20.0% 15.0% 10.0% 5.0% 0.0%

Tax rate for 15 years (%)

Be

ne

fit/C

ost

(C

$/k

Wh

)

Tax　Cost Price Gap Cost Government Net Benefit

0.9 1.10.70.5

0.30.0

3.73.4 3.2 2.9 2.62.7

0.20.1 0.1 0.1 0.1 0.2

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0


Brea

kdow

nofS

ellin

gPric

e（c$

/kW

h）



Corporate tax rate 5% ( 1-15 year) 25% (16-30 year)Dividend tax rate 10%



Fig. 8.5-6 Tax on geothermal and coal-fired IPP business Fig. 8.5-7 Effect and cost of tax incentives

（at 5% tax rate for 15 years） 8.6 Fiscal Incentives (Government Expenditure)

In this Section, the term “fiscal incentive” is used in a narrow sense and refers to direct government expenditure. Government can provide subsidies for renewable energy developers and reduce their up-front investment burden to promote renewable energies. Also the government can carry out some activities itself to promote renewable energies, such as a nation-wide survey of the renewable energy inventory. Many countries provide this kind of fiscal incentive, and the examples of Denmark and Japan are widely known.

In Denmark, between 1978 and 1989, subsidies were provided for the installation of wind power plants. The rate of subsidy was 30% at first, and decreased gradually to 10% towards the end. Thereafter in 1992, the government started to provide production subsidies of 0.10 Dkk/kWh (1.6 USD Cents/kWh at the 1992 exchange rate) to wind power producers. Furthermore, when the wind power producer was a private one, it received an additional production subsidy of 0.17 Dkk/kWh (4.4 USD Cents/kWh) 8.

In Japan, in order to promote solar power generation, subsidies have been given since 1994 to homeowners who install a solar power system on the roofs of their houses. The subsidies contributed to reducing the installation cost of solar power systems, resulting in an expansion of the market and a reduction in the production cost of solar panels. Between 1994

8 EIA Report Non-hydraulic renewable energies promotion policy in USA and major countries (Feb., 2005).


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and 2002 this system subsidized 115,000 installations, for a total solar power capacity of 421MW. In 2005 this subsidy system expired. However, the Aso Taro administration revived this subsidy system in late 2008 to promote solar energy use and to contribute to GHG reduction.

In Denmark, incentives drove a rapid increase in wind power generation, and 21% of

Denmark’s power is now supplied by wind power, the highest ratio in the world. Also, the manufacturers of wind power generating equipment in Denmark grew with the support of these subsidies until in 2003 about 1/2 of the world total wind power equipment capacity of 40,000 MW was made in Denmark. In Japan, photovoltaic (PV) systems spread very quickly and the total equipment capacity expanded from 19 MW in 1992 to 635 MW in 2002, achieving the largest solar power capacity in the world for those days. The cost of generation from PV systems fell rapidly from 260 JPY/kWh (2.41 USD Cents/kWh) to 49 JPY/kWh (0.41 USD Cents/kWh) in 2002.

(Source) EIA Report （Source）New Energy Foundation, Japan

Fig. 8.6-1 Effect of fiscal incentives in Denmark and Japan

＜Construction Subsidy＞

In Japan, 20% of the construction costs of a geothermal power plant are subsidized with a view to promoting geothermal energy development. Taking this as an example, the Study Team has calculated the effect of construction subsidies. Fig. 8.6-2 shows the selling prices of geothermal power with a 10% to 50% construction subsidy. Without the subsidy, the selling price is 11.9 USD Cents/kWh, whereas a 50% subsidy brings the price down to 8.7 USD Cents/kWh. Therefore, in order to bring down the selling price of geothermal power to match that of the benchmark coal-fired power, a 50% construction subsidy is required.

Fig. 8.6-3 shows the effect of a 5% tax rate for 15 years. If a construction subsidy is

PV System Unit Price PV System Capacity (Total)

System Unit Price per 1

PV System Capacity (Total)

PV System Capacity supported

Japan’s PV Capacity


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Price Gap (tax=5% for 15 years)

11.9

10.39.7

9.08.4

6.0

7.0

8.0

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10% 20% 30% 40%

Construction Subsidy (%)

Sel

ling

Pric

e (C

$/kW

h)


Price Gap (tax=25%)

11.911.2

10.69.9

9.38.7

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10% 20% 30% 40% 50%


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ling

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e (C

$/kW

h)


applied in addition to this tax incentive, a 40% subsidy is required to match benchmark. However, a 40% or 50% subsidy for construction costs is a large subsidy and may not be realistic.

Fig. 8.6-2 Subsidy effect (at 30% tax) Fig. 8.6-3 Subsidy effect （at 5% tax rate for 15 years）

＜Governmental Survey for Promotion＞

As discussed before, in order to reduce the risks of the geothermal IPP business, the government should carry out surveys in the early stages. In Japan, government carries out early-stage surveys as “Geothermal Development Promotion Survey”. The Study Team has studied the possible effects of this kind of initial governmental survey (including a surface survey and an exploratory drilling survey) in Indonesia.

If the government carries out the initial survey, a private developer can purchase the results to enjoy risk reduction and a shorter development period. This will help promote development significantly (Fig. 8.6-4). If the developer can purchase the research results on an installment plan, this support ends up having a similar effect to loan assistance by the government during the survey period. Furthermore, if the payment for the survey results can be postponed until commercial operation begins, the developer will enjoy greater financial liberty. In the following scenario, the government conducts a surface survey and an exploratory drilling survey and the developer purchases the results after the inception of commercial operation at


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Effect of Governmental Geothermal Development Promotion Survey

Development Stage Activity Government Private Company

Paymentfor Promotion Survey Resultsto Government by installments

Surface Survey Stage

Resource Confirmation Stage

Construction Stage

Development Stage(Reservoir Evaluation Stage)

Operation Stage

Development Process of 60 MW Model Case

Surface survey (Geology, Geochemical,Geophysics MT, etc)

To Find steam (Approximately 10%)Drilling 2 wells →　1 well success

To confirm 40% of steam,Drilling 3 wells →　2 well success

To obtain 100% steam,Drilling 8 wells →　6 well success

Operation & Maintenance

Geothermal Development Promotion Survey

Construction

Operation(Repayment)

Surface Survey

Reservoir Evaluation

ResourceConfirmation

Risk Reduction

Initial InvestmentReduction

Lead TimeReduction

Conversion of initialinvestment to costexpenditure

GeothermalDevelopmentPromotion

Survey

Drilling5 wells

Exploration

Geothermal Development Promotion Survey Unit price Q'ty Price1.Reconnaissance & Exploration (m$) (m$) Surface Survey (Reconnsaince＋Prefeasibility) 2.0 1 2.0

Land and rights, Road Access Improvement 1.0 1 1.0 Exploration (Drillings of Commercial Size Test Wells ) 5.0 2 10.0 Sub Total 13.02. Confirmation

Business design & Feasibility study & EIS 2.5 1 2.5 Drillings of Test Wells (Production Wells) 5.0 3 15.0 Drillings of Test Wells (Reinjection Wells) 2.5 1 2.5 Sub Total 20.03. Technical Management (Consultation) 2.0 1 2.0 Total 35.0

USD 35 million on a 10-year installment plan with a 6.5% interest rate. Table 8.6-1 shows the scale and specifications of the governmental initial survey assumed here .

Fig. 8.6-4 Effect of initial governmental survey

Table 8.6-1 Scale and specification of initial governmental survey

Fig. 8.6-5 shows the selling prices of geothermal power with a 5% tax rate for 15 years and an additional initial governmental survey. Without any incentives, the price is 11.9 USD Cent/kWh, but declines to 8.5 USD Cents/kWh with the tax incentive and the initial


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Price Gap (Gov't Promotion Survey)

11.9

10.9

8.5

6.0

7.0

8.0

9.0

10.0

11.0

12.0

13.0

Base Tax 5% (15yr) Tax5%(15yr) &Promotion Svy.


Sel

ling

Pric

e (C

$/kW

h)


Government Benefit (Gov't Promotion Survey)

0.80.9

1.33.7

2.7 0.3

0.1 0.21.4

0.0

1.0

2.0

3.0

4.0

5.0

Base Tax 5% (15yr) Tax5%(15yr) &Promotion Svy.


Bene

fit/C

ost (

C$/

kWh)

Survey Cost Tax　Cost Price Gap Cost Government Net Benefit

governmental survey9. This price is very close to the benchmark price and these incentives are deemed very effective. ＜Proposal of Fiscal Incentive＞

As discussed above, an initial governmental survey has a significant effect in reducing the selling price of geothermal power. This scheme also helps reduce the business risks in the early development stage, which private developers hate to take. Therefore, it is deemed that this scheme will facilitate private participation in geothermal energy development. Implementation of this initial survey scheme should be seriously considered.

The combination of this survey scheme with a tax incentive is expected to reduce the selling price of geothermal power by 3.4 USD Cents/kWh, while the costs for the initial governmental survey are estimated at 0.8 USD Cents/kWh and the government’s expense for the tax incentive is estimated at 1.3 USD Cents/kWh. As the result, the total incentive cost to the government is 2.1 USD Cents/kWh. The remaining reduction of 1.3 USD Cents/kWh arises from the leverage effect referred to in Section 8.2, which is deemed to represent an increase in the net benefit to the government (Fig.8.6-6). For reference purposes, the cost of the initial governmental survey for a 60 MW geothermal power plant is estimated to be around USD 35 million, as shown in Table 8.6-1.

Fig. 8.6-5 Effect of government survey Fig. 8.6-6 Effect and benefit of governmental survey

9 The selling price is calculated by assuming β=1.5 since the government takes some initial risks in its survey.


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8.7 Financial Incentives

Financial incentives are provided in the form of low-interest loans from governmental banking institutions to renewable energy developers in order to reduce their up-front investment burden and promote renewable energies. Many countries have adopted such a financial incentive scheme, and the examples of Japan and Germany are widely known. In Japan, the Development Bank of Japan finances private companies at a low interest rate for renewable energy projects and energy-saving projects. This financing is limited to 40% of the construction cost, but the financing conditions, such as interest rate, period of finance and others, are decided individually. In the case of renewable energy projects, the finance period is usually 13-15 years and the interest rate is lower than the market rate and is fixed during this finance period. In Germany, the German Reconstruction Bank (Deutche Wiederbau Bank; KfW) provides loans at a fixed lower-than-market interest rate for a maximum of 20 years. Since the capital market is well developed in the US, governmental financing is relatively negligible, but on the level of state governments, a similar system of low-interest financing has been reported for wind power generation in Minnesota State.

This kind of low-interest financing system exists to provide financing which

commercial banks cannot provide to (i) fields with high business risks, (ii) fields where it takes long time to recover returns, or (iii) fields on which the government places a priority. This financing is (a) long-term, (b) provides a fixed interest rate, and (c) provides a low interest rate. Renewable energy development projects are characterized by all of conditions (i) – (iii), and this kind of financing system has a big advantage for developers who need initial investment money. The system aims at encouraging them to realize the goals of governmental policy. ＜Financial Assistance＞

In Japan, a governmental financial institute promotes geothermal power generation projects through low-interest loans. The Study Team has studied the effect of low-interest loans as financial incentives. Fig. 8.7-2 assumed a 6.5% to 3.5% interest-rate loan for 70% of project costs. At the market interest rate, the selling price of geothermal power is 11.9 USD Cent/kWh, but a 3.5% interest rate pushes it down to 11.0 USD Cents/kWh. ＜Low-Interest Loans for Initial Research and Construction＞ Commercial banks tend to avoid participating in geothermal power projects from the exploratory drilling stage due to the high risks of that stage. So investors have to cover these expenditures from their own equity. However, if a low-interest loan is made available by governmental banks in the early stage, the selling price will be reduced to 9.9 USD Cents/kWh, as shown in Fig. 8.7-1.


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Price Gap

11.9 11.7 11.6 11.4 11.3 11.1 11.0

6.0

7.0

8.0

9.0

10.0

11.0

12.0

13.0

Base(6.5%)

6.0% 5.5% 5.0% 4.5% 4.0% 3.5%

Construction Loan Interest Rate (%)

Sel

ling

Pric

e (C

$/kW

h)


Price Gap

11.9

10.8 10.6 10.4 10.3 10.1 9.9

6.0

7.0

8.0

9.0

10.0

11.0

12.0

13.0

Base(6.5%)

6.0% 5.5% 5.0% 4.5% 4.0% 3.5%

Construction & Confirmation Loan Interest Rate (%)S

ellin

g P

rice

(C$/

kWh)


Fig. 8.7-1 Effect of low-interest loans Fig. 8.7-2 Effect of low-interest loans for construction for construction & confirmation

＜Proposal of Financial incentive>

Since the up-front investment for a renewable energy project is large, many countries assist renewable energy development with low-interest loans from governmental banks. Indonesia does not have any governmental financial institutes, so establishment of these institutes may be necessary. When this governmental financing covers not only construction costs, but also the early stage development costs, it has a very large effect.

If a 3.5% interest-rate loan is provided for the construction and the confirmation stage,

the selling price of geothermal power is estimated to fall by 2.0 USD Cents/kWh. On the other hand, the cost to the governmental bank is estimated to be 0.7 USD Cents/kWh, and the reduction of tax revenue, 0.5 USD Cents/kWh. As a result, the total incentive cost to the government is 1.2 USD Cents/kWh. The balance of 0.8 USD Cents/kWh arises from the multiplier effect referred to in Section 8.2, which is deemed to be an increase in the government’s net benefit (Fig.8.7-3). For reference purposes, the loan for a 60 MW geothermal power plant amounts some USD 102 million for the construction stage and USD 20 million for the confirmation survey stage.


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Government Benefit

0.1 0.2 0.4 0.5 0.6 0.70.4 0.4 0.4 0.4 0.5 0.5

3.7 2.6 2.4 2.2 2.1 1.9 1.7

0.10.7 0.7 0.8 0.8 0.8 0.8

0.0

1.0

2.0

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6.0% 5.5% 5.0% 4.5% 4.0% 3.5%

Construction & Confirmation Loan Interest Rate (%)

Ben

efit/

Cos

t (C

$/kW

h)

Interest Cost Tax　CostPrice Gap Cost Government Net Benefit

Fig. 8.7-3 Effect and benefit of low-interest loans

CHAPTER 9

PROPOSAL OF SHORT-TERM

INCENTIVES TO PROMOTE

GEOTHERMAL DEVELOPMENT


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PRELIMINARY

SURVEY

EXPLORATION

EXPLOITATION

ELECTRICITY GENERATION

GEOTHERMALENERGY

RESOURCES

GEOTHERMALENERGY

UTILIZATION

BYCENTRAL ORREGIONALGOVERNMENT


ELECT.BUS.PERMIT

TENDERING

BYCENTRALGOVERNMENTOR COMPANY

(LAW NO. 27/2003)

COMMITTED ENERGY SALES

Private IPP

CHAPTER 9 PROPOSAL OF SHORT-TERM INCENTIVES TO PROMOTE GEOTHERMAL DEVELOPMENT

Based on the discussion of fiscal incentive effects in Chapter 8, comprehensive

short-term incentives are proposed as follows. 9.1 Geothermal Development Process in Indonesia

After the surface survey is finished, the geothermal development process of Indonesia

recruits a private company to continue the development by tender, as shown in Fig. 9.1-1. However, since private companies are very sensitive to any business risk, there are some questions as to how many private companies are interested in participation in geothermal development from this early stage. The Study Team conducted some interviews with several companies in Indonesia and Japan which had expressed interest in geothermal development in Indonesia. One question asked was "Will your company participate in geothermal development from the Green Field stage (a field where an underground survey has not yet been undertaken) in Indonesia?” Some companies replied, "We want to participate and to challenge the risks of geothermal development. We have enough experience and ability”. However, most Japanese companies answered, “We are interested in geothermal development in Indonesia, but we will not participate from the Green Field stage. It is too risky for us.” Therefore, the elaboration of a number of short-term incentives has been undertaken in the following categories: (i) incentives for “Green Field” development, (ii) measures to change “Green Field” to “Brown Field”, and (iii) measures for “risk-free participation”.

Fig. 9.1-1 Geothermal development process in Indonesia


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9.2 Incentives for “Green Field” Development < Preferential Tax Treatment>

The first proposal of an incentive for “Green Field” development is a tax incentive. The geothermal power generation business pays an extremely large amount of tax and royalties compared with the coal-fired thermal power generation business, as described in Section 8.5. Therefore, a reduction in tax will attract a lot of attention from investors. Also such a reduction will be taken as a sign of the sincere desire of the Indonesian government to work seriously on geothermal development. Therefore, a "preferential corporate tax rate of 5% for 15 years”, as discussed in Section 8.5, is the first incentive we propose. With a 5% corporate tax rate, the effective tax rate becomes 14.5%, when the 10% of dividend withholding tax is factored in1.

<Incentive #1 for “Green Field” development > (Adoption of preferential tax treatment )

- Preferential tax treatment is applied to the geothermal IPP business. - A 5% corporate tax rate is applied to the geothermal power generation business

for 15 years after commercial operation starts.

< Feed-in Tariff System>

However, this incentive alone is insufficient to persuade private companies to participate in “Green Field” development. It is necessary to offer a company an additional reward to face the big risk of “Green Field” development. Therefore, a Feed-in Tariff (FIT) system is proposed as the additional incentive. Since the FIT system secures a long purchase period for geothermal power, investors can design their own geothermal energy development plans with a certain confidence. If the FIT is appropriately designed, a big effect can be expected, such as that seen in Germany. Therefore, the following “FIT system” is proposed.

<Incentive #2 for “Green Field” development > (Adoption of Feed-in Tariff system)

- The government compels PT PLN to purchase electric power from geothermal

IPPs at the following Feed-in Tariffs. (a) Geothermal power plants with more than a 20 MW capacity

(i) For a fixed price 10.9 USD Cents/kWh (15 years)

1 The effective tax rate: 5%+(100%-5%)*10%=14.5%. It is 32.5% when the corporate tax rate is the base rate of 25%.


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(ii) For a two-stage price 11.8 USD Cents/kWh (1-8 years)

7.4 USD Cents/kWh (9-15 years) (b) Geothermal power plant with a capacity of 20 MW or less

(i) For a fixed price 17.0 USD Cents/kWh (15 years)

(ii) For a two-stage price 19.0 USD Cents/kWh (1-8 years) 12.0 USD Cents/kWh (9-15 years)

- The choice between the fixed price and the two-stage price is left to the developer. - The purchase cost of geothermal power is borne by PT PLN, and PT PLN should

transfer its cost to consumers. However, in light of the current financial deficit of PT PLN, the government will provide a subsidy to compensate for the difference between the geothermal power purchase price and the coal-fired power purchase price, (i.e. FIT – Coal-fired power purchase price). In this case, the geothermal premium, which is the benefit of fuel cost reduction achieved by using geothermal energy instead of using high-cost fuel, should be subtracted from the subsidy.

- The FIT is set in real terms, and therefore, a mechanism to adjust the price to meet changes in the economic situation such as inflation should be introduced.

- The FIT in Rupiah terms should be dollar-pegged in order to avoid the developer’s exchange rate risk.

- To reflect changes in the economic situation, the FIT should be regularly reviewed.

These two incentives will be effective in promoting the participation of private

companies in “Green Field” geothermal development. <Incentives for Existing IPP Companies>

In this report, “Green Field” means a field where an underground survey has not yet been undertaken. These Green Fields will be developed by the private IPP companies who will be decided through tendering process for each field. (These private IPP companies are referred to New IPP companies, when necessary, in this report.) On the other hand, there are some private IPP companies who already have a right to develop a certain geothermal field in the Pertamina’s Working Area under Joint Operation Contract with Pertamina. (These private companies are referred to Existing IPP companies.) These existing IPP companies have started geothermal development in 1990s but many of them have stopped their activities because of the sudden changes in the purchase prices after the Asian Economic Crisis as described in Chapter 3. However, the geothermal resource potentials of these fields are estimated as very large. In order to expand geothermal capacity in Indonesia, it is imperative to revitalize the development by the


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existing IPP companies. With taking resource development risks, these companies have started development from the Green Field stage in each field. Therefore, the incentives for them should be consistent with the incentives for the Green Field development by new IPP companies. Namely the same incentives of preferential tax treatment and Feed-in Tariff system should also be applied to the development by existing IPP companies. <Improvements in Current Tender System >

In the Green Field development, a developer for each field will be decided by tendering process. Since the enactment of the Geothermal Law, three tenders have been carried out to date. At this juncture, the Study Team points out several problems that need to be amended in the current tender system. As already mentioned in Section 3.5, some problems have been reported in the current tender system. The first problem is that tender evaluation is done on the basis of the electricity price or the steam price offered in a bid. This method is stipulated in the Article 23 of the Government Regulation of Geothermal Operation, No.59/2007. However, the tender for a field is made only on the basis of the results of a surface survey of that field. It is impossible to estimate the future electricity selling price or the steam selling price for a field in such an early stage of development. Therefore, it is very difficult for serious geothermal energy developers to participate in the tender because they cannot estimate the electricity or steam selling price. In this respect, current tender practices constitute an extremely mysterious system. There is a strong desire to see this system amended to a new system in which bidding for the purchase price of the Geothermal Energy Business Permit (IUP) is the basis of evaluation.

The second problem is that the prequalification (PQ) of bidders seems to have been

rather loose in the past. The bidding system includes a prequalification evaluation. However, in view of the results of the bidding in September 2008, it is clear that there are some bidders who have no experience in exploration, development or construction of a geothermal power plant. Once such inexperienced bidders are accepted, there is a fear that such bidders will be unable to sustain the financial burden of a substantial and risky up-front investment and will abandon development within the limited period of 5 years, which may result in an overall delay in the development of geothermal power in the country. The prequalification of bidders should be done strictly according to criteria specified in advance.

The third problem is the handling of PT PLN. PT PLN has taken positive actions to

develop geothermal power to substitute for high-cost diesel and expand the use of renewable energy in remote areas. And yet, in spite of its investment in geothermal exploration, PT PLN itself cannot participate in bidding for geothermal fields because PT PLN is also the buyer of the power. This creates a possibility that PT PLN might have to abandon its geothermal fields without recovering its investment, if such sites should be included in the government Work Areas and made subject to public bidding. Therefore, in the bidding for Work Areas where PT


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PRELIMINARY

SURVEY

EXPLORATION

EXPLOITATION


GEOTHERMALENERGY

RESOURCES

GEOTHERMALENERGY

UTILIZATION



ELECT.BUS.PERMIT

TENDERING


Private IPP

Incentives from Green FieldTax Incentive

Feed in Tariff

PLN has invested substantially in exploration, a concession may be granted without a bidding process in view of prior development activity.

The fourth problem is that each private company can only be granted with one Work Area. This is stipulated in Article 28 of the relevant regulation. When a private company wants to work in more than two work areas, the company has to establish a separate new company for each work area. However, establishing a new company involves time and costs. Moreover, the development of multiple areas can help to reduce the development risks, as shown in Fig. 6.3-13 of Section 6.3. It is necessary to revise this regulation.

< Necessary improvements in the current tender system >

- It is necessary to change the current tender bid evaluation system based on the offered electricity price or steam price into a new system of evaluating bidding the Geothermal Energy Business Permit.

- The prequalification of bidders should be done strictly according to criteria set forth in advance.

- Work Areas should be conceded to PT PLN without a bidding process where PT PLN has invested substantially in exploration.

It is necessary to amend the current restriction limiting one company to one Work Area, and to enable private companies to work in two or more Work Areas.

Fig. 9.2-1 Incentives to promote geothermal “Green Field” development


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9.3 Measures to Change “Green Field” to “Brown Field”

Preliminary surveying and exploration surveying by the government are necessary to transform a “Green Field” into a “Brown Field”. Currently, the Indonesian government issues a Geothermal Energy Business Permit (IUP) to a private company through a tender based on the surface survey results alone. However, this represents a considerably early stage of development, and there are not a lot of tender participants. Therefore, if the government carries out exploration surveying in promising fields and discloses the underground information in detail, more applicants will participate in the tender. Here, a “Geothermal Development Promotion Survey” carried out by the government to transform “Green Fields” into “Brown Fields" is proposed as one of measures to change “Green Field” to “Brown Field.”

<Measures to change “Green Field” into “Brown Field” > (Adoption of a government “Geothermal Development Promotion Survey”)

- In order to increase the number of private companies in the geothermal IPP

business, the Indonesian government will carry out a comprehensive “Geothermal Development Promotion Survey” in promising geothermal fields.

- The “Geothermal Development Promotion Survey” will include a surface survey (reconnaissance), steam existence confirmation survey (exploration), reservoir capacity evaluation (confirmation), and so on. The survey will also include the drilling of several exploration-wells.

- When the survey results are promising, the government will specify the area as a Work Area for geothermal development, and invite tenders to select a private company to carry out the development.

- Bidding in the tender will be for the purchase of the survey results. The current system of bidding centered around the electricity price or the steam price should be abolished.

- The government sells the survey results to the highest bidder. The payment can be divided into installments, but interest will accrue during the repayment period.

For successful development after the governmental “Geothermal Development Promotion Survey”, the following incentives should be applied.

<Incentives for the development of “Brown Field” after governmental survey> (Adoption of FIT system and preferential tax treatment )

- The government compels PT PLN to purchase electric power from the


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PRELIMINARY

SURVEY

EXPLORATION

EXPLOITATION


GEOTHERMALENERGY

RESOURCES

GEOTHERMALENERGY

UTILIZATION



ELECT.BUS.PERMIT

TENDERING


Incentives tobridge Green Fieldand Brown Field

Private IPP

Tax Incentive

Feed in Tariff

Promotion Survey

geothermal IPPs at the Feed-in Tariff. - The Feed-in Tariff is to be calculated field by field from the results of the

Geothermal Development Promotion Survey. - The preferential tax treatment mentioned in Section 9.2 should also be applied

to the geothermal IPP business from the Brown Field stage.

The number of private companies which participate in geothermal development will

increase further if such a comprehensive governmental survey is implemented. The government should introduce such a survey as soon as possible. Official development assistance money from multilateral or bilateral donors can be utilized to finance this survey.

Fig. 9.3-1 Measures to change “Green Field” to “Brown Field” 9.4 Measures for Risk-free Participation

The largest risk of the coal-fired IPP business is the rise of coal prices in the future. However, if the coal price rises for a coal-fired IPP business, the business operator can transfer the cost increase to PT PLN through the agreement of a so-called "Pass Through" condition. That means the coal-fired IPP business is a substantially risk-free business. If the geothermal IPP business can be transformed into a risk-free business like this, a considerable number of private companies will show their interest in participating in geothermal IPP projects.

In the 1980s, an interesting method was devised to attract private companies to geothermal development in the Philippines. In that country, the Philippine National Oil


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9-8

CONSUMERELECTRICITY

Electricity

NPC (Electric Power co.)PNOC-EDC

Energy Sales Contract

STEAM FIELDDEVELOPMENT

Power GenerationSTEAM

Electricity

BOT Contract

Private Company

NPC

Company (PNOC) Energy Development Corporation (EDC), which is a state-run enterprise, had been in charge of geothermal development. However, it tried to draw private capital into the geothermal power sector because PNOC-EDC’s own funds were limited. As private companies were not willing to accept geothermal resource risks, PNOC-EDC offered to provide steam without charge and to purchase electricity for 10 years, with the power plant to be transferred to PNOC-EDC without compensation after 10 years. Through these conditions, PNOC-EDC mitigated the two big risks of steam supply and power purchase. As a result, the geothermal power business became nothing more than an energy conversion business (a business to convert steam to electric power) that was risk-free. Because of this policy, many private companies participated in this geothermal energy conversion business in the 1990s, and geothermal development in the Philippines has advanced rapidly. The advantage of this method is that the risky geothermal power business is divided into two parts: a risk-free power generation part and a still risky steam development part. PNOC-EDC took on the risky part, but it was a state-run enterprise and could afford to take risks which private companies could not. In addition, while PNOC-EDC was devoted to steam development, it accumulated the experience necessary to develop fields more economically. PNOC-EDC also could distribute its risk by developing multiple fields, by the method referred to in Fig. 6.3-13 (4).

Unfortunately, the future of the Philippine electric power sector is opaque due to the

recent privatization of the sector. As a result, private companies are prudent about investing in the Philippines electric power sector now. However, the method which had been adopted in the Phillipines is a remarkable method of reducing private sector business risk, and constitutes one type of Public-Private Partnership in geothermal development. Fortunately, Indonesia has Pertamina Geothermal Energy (PGE), which assumes responsibility for geothermal development in the country. PGE has 15 geothermal Work Areas now, and works on the geothermal development there by itself. Currently the government is trying to develop other fields outside the PGE areas through private companies. However, PGE’s fields are very promising fields. The development of these fields is also very important for Indonesia and needs to be expedited.

Fig. 9.4-1 Public-Private Partnership in geothermal development in the Philippines


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PRELIMINARY

SURVEY

EXPLORATION

EXPLOITATION


GEOTHERMALENERGY

RESOURCES

GEOTHERMALENERGY

UTILIZATION



ELECT.BUS.PERMIT


Incentives for Public Private Partnership

PertaminaPertamina PertaminaPrivate IPP

Pertamina Tax Incentive

Feed in Tariff

Support toPERTAMINA

To attract more private companies into the geothermal power business in Indonesia, the following type of “Public-Private-Partnership” is recommended.

<Measures for risk-free participation > (Adoption of the Public-Private Partnership)

- A type of development should be considered in which PGE supplies the steam, and private companies take charge of power generation in PGE’s work areas.

- The government should assist PGE’s steam development by supplying capital. Concretely, the government should provide financial support through low-interest funds or ODA capital assistance.

- Sales of steam between PGE and a private company should be exempt of VAT.

If such a program is adopted, the number of applicants for participation in the

geothermal power business will become extremely large.

Fig. 9.4-2 Measures for risk-free participation

CHAPTER 10

EVALUATION OF A LONG-TERM

COAL-FIRED IPP PROJECT


JICA West JEC 10-1

CHAPTER 10 EVALUATION OF A LONG-TERM COAL-FIRED IPP PROJECT

10.1 Long-term Outlook for Coal Demand and Supply and Coal Prices

Coal is Indonesia’s most abundant fuel source and is a key element in the Government of Indonesia’s energy diversification program. In terms of calorific value, Indonesia has more potential energy reserves in the form of coal than in oil and gas. It is the nation’s most abundant fossil energy source and the cost of generating electricity from it is low. Statistics issued by the Directorate of Coal in 2005 indicate that Indonesia has about 61.3 billion metric tons (MT) of coal resources, of which 6.8 billion MT can be considered as commercially exploitable reserves. Major coal resource areas are Kalimantan and Sumatra, with estimated reserves of 32.2 billion MT and 28.7 billion MT, respectively1. Coal deposits in Sumatra are located in the areas surrounding Tanjung Enim, South Sumatra, Ombilin in West Sumatra and Cerenti in Riau province. In Kalimantan, the mining areas are spread out in the eastern and southern part of the island.

Indonesia’s coal deposits are relatively young, with the majority ranked as lignite (59%),

sub-bituminous (27%), and bituminous (14%). The quality of coal mined in Indonesia is generally steam coal, except in Ombilin. The steam coal has heat values ranging between 5,000 and 7,000 kcal/kg, with low ash and sulfur content (below 1%). Kalimantan has higher quality coal deposits, both in terms of heat value and low sulfur content. Indonesian coal production reached 215 million MT in 2007, where 166 million MT for export and 49 million MT for domestic consumption, and continues to rise. Production is forecasted to reach 240 million MT in 2010 and 370 million MT in 2025. Seventy-three percent of coal production is now being exported, and the balance is consumed domestically. With increasing coal production, domestic demand has also continued to rise, with power plants and the cement industry being the major consumers, accounting respectively for 74 percent and 13 percent of total demand. The state electricity utility utilized 25.7 million MT of coal in 2005 to fuel its 5,460 MW of coal-fired power plants in Suralaya (West Java), Paiton (East Java) and in other areas.

Fig.10.1-1 shows Indonesian coal production, consumption and exports and the forecast

through 2025 as provided by the Ministry of Energy and Mineral Resources. Fig.10.1-2 presents domestic coal consumption growth by type of industry. The forecast assumed a consumption growth of 7 % per annum for electricity generally and 12% for industrial uses.

Coal prices have historically been lower and more stable than oil and gas prices, and

despite the growth of index and derivative-based sales in recent years, this has typically

1 MEMR,Recent Developments in Indoensia’s Mining Industry Situation and Policy (Information to IEA), Feb. 2008


JICA West JEC 10-2

remained the case. However, in the years since 2004 international steam coal prices have suddenly surged. The average price of coal imported by OECD countries jumped from USD 42 per ton to USD 73 per ton in 2007 (in 2007 dollars) and soared to well over USD 100 per ton in the first half of 2008. Rising industrial production and electricity demand in developing countries, especially in China, have boosted coal use. Higher gas prices have also encouraged some power stations and industrial end-users to switch to coal and to invest in new coal-fired equipment. These factors have added to the upward pressure on coal demand and prices. According to IEA Energy Outlook 2008, coal prices are likely to settle at around USD 120 per ton (6,000 kcal/kg coal base) in real terms in 2010. Thereafter, prices are assumed to remain flat through to 2015. As new mining and transportation capacity will become available after 2015, IAE forecasts that coal prices will then fall slightly to USD 110 per ton in 2030. However, movements in coal prices and the range of those movements are likely to depend on the balance of upward and downward pressures on the price. Upward pressures include shrinking exportable coal stocks, and tightened coal supply and demand triggered by electric power programs and the depletion of resources, while the downward pressures include developing exportable coal mines, enhancing coal mining productivity and falling oil prices. Therefore, in this Study, it is assumed that the upward and downward pressures will offset each other and the coal price will remain at a constant level of USD 90 per ton (5,300kcal/kg coal base) through 2025. In this connection, the PT PLN also forecasts a constant coal price of USD 90 per ton (5,300 kcal/kg coal base) through 2018 in its latest power development plan (RUPTL).

Fig 10.1-1 Indonesian coal production and consumption Fig. 10.1-2 Indonesian domestic coal consumption

by Industry

10.2 Long-term Forecast of Coal-fired Power Plant Construction Cost2

2 The Study Team is indebted to Dr. Nakata Masao, Associated Professor in Faculty of Economics, Kyushu University, for the estimation of the future unit construction costs in this chapter and Chapter 11.


JICA West JEC 10-3

This Chapter attempts to forecast the future selling price of electricity from the benchmark coal-fired IPP. The Financial Model introduced in Chapter 5 is used in the forecast to take into consideration coal prices, construction costs, and plant efficiency and capacity factors. For construction costs, the Study Team has reviewed the construction costs of coal-fired plants in Japan and applied the trends uncovered to an estimation of future construction costs of coal-fired plants in Indonesia through the steps laid out below. The reason for applying Japanese construction trends to Indonesia is that private IPPs are likely to construct reliable power plants manufactured in the industrial countries. (1) Calculation of the real-term unit construction cost by adjusting the nominal unit construction

cost in line with the Corporate Goods Price Index (CGPI). (2) Construction of a multiple regression equation to estimate the real-term unit construction cost

and determine its coefficients (3) Testing of the coefficients and confirmation of the result (4) Estimation of present and future unit construction cost using the multiple regression equation

In step (1), the real-term unit construction costs were calculated by adjusting the nominal unit construction costs in line with the CGPI (standard year is 2000).

Table 10.2-1 Unit construction cost of coal-fired power plants in Japan

Operation Year

CapacityUnit Construction Cost (Nominal)

Unit Construction Cost (Real-term)

CGPI

（2000＝100）【General】

(MW) (‘000JPY/kW) (‘000JPY/kW) （2000avg＝

100）

Power Plant Name

Y_START CAPA_MW NC_KW RC_KW P_WCPI

Niihama-nishi 1962 75 50.9 103.3 49.3

Saijo 1965 156 55.6 109.2 50.9

Simonoseki 1967 175 47.9 89.7 53.4

Takehara 1967 250 54.8 102.7 53.4

Naie 1968 175 53.2 98.8 53.8

Takasago 1968 250 45.2 84.1 53.8

Takasago 1969 250 45.2 81.6 55.4

Naie 1970 175 35.3 62.4 56.6

Saijo 1970 250 32.6 57.6 56.6

Nakotsu 1970 250 42.8 75.6 56.6

Tobata 1971 156 35.3 62.7 56.2

Sagawa 1977 125 157.9 167.1 94.5

Sagawa 1980 125 170.4 148.2 115.0


JICA West JEC 10-4

Tomatokoshin 1980 350 207.1 180.0 115.0

Matsushima 1981 500 215.9 187.4 115.2

Matsushima 1981 500 106.1 92.1 115.2

Takehara 1983 700 227.1 198.1 114.7

Nakotsu 1983 600 165.5 144.4 114.7

Nakotsu 1983 600 165.5 144.4 114.7

Tomatokoshin 1985 600 222.6 197.0 113.0

Shinonoda 1986 500 282.6 264.1 107.0

Ishikawa 1986 156 373.1 348.6 107.0

Shinonoda 1987 500 145.4 138.2 105.2

Ishikawa 1987 156 373.1 354.7 105.2

Matsuura 1989 700 282.9 263.3 107.4

Matsuura 1990 1000 277.0 254.8 108.7

Kounan 1991 700 261.3 239.4 109.2

Suruga 1991 500 302.0 276.7 109.2

Kounan 1992 700 261.3 241.8 108.1

Noshiro 1993 600 297.7 280.4 106.2

Kounan 1993 700 261.3 246.1 106.2

Noshiro 1994 600 214.3 204.6 104.7

Gusikawa 1994 156 431.8 412.2 104.7

Shinchi 1994 1000 402.9 384.7 104.7

Nanaoota 1995 500 402.0 387.9 103.6

Reihoku 1995 700 428.6 413.5 103.6

Gushikawa 1995 156 431.8 416.6 103.6

Shinchi 1995 1000 233.0 224.8 103.6

Haramachi 1997 1000 458.7 444.8 103.1

Matsuura 1997 1000 252.4 244.8 103.1

Haramachi 1998 1000 229.8 227.8 100.9

Nanaoota 1998 700 231.4 229.4 100.9

Mikuma 1998 1000 380.0 376.7 100.9

Suruga 2000 700 257.1 258.3 99.5

Tachibanawan 2000 700 364.3 366.0 99.5

Tachibanawan 2000 1050 325.5 327.0 99.5

Tachibanawan 2000 1050 325.5 327.0 99.5

Kounan 2001 1000 258.4 266.2 97.1

Karita 2001 360 272.2 280.4 97.1

Kounan 2002 1000 300.5 314.7 95.5

Kinbu 2002 220 381.3 399.4 95.5


JICA West JEC 10-5

0

50

100

150

200

250

300

350

400

450

500

1960 1965 1970 1975 1980 1985 1990 1995 2000 2005

Year

Coa

l Con

stru

ctio

n U

nit C

ost (

'000

JPY/

kW)

Isogo 2002 600 325.0 340.4 95.5

Hitachinaka 2003 1000 261.5 275.4 95.0

Reihoku 2003 700 258.6 272.3 95.0

Kinbu 2003 220 381.3 401.6 95.0

Maizuru 2004 900 438.2 454.5 96.4

(Source) Unit construction cost (nominal): MITI, METI, Annual Report on Power Development in Japan (annual)

CGPI: Bank of Japan, Corporate Goods Price Index

These historical data for real-term unit construction costs show an increasing trend, as

seen in the following figure.

Fig. 10.2-1 Real-term unit construction cost of coal-fired power plants in Japan

In step (2), an equation to estimate the unit construction cost of a coal-fired power plant is constructed in the form of a multiple regression equation bringing together the cost elements which explain the unit construction cost.

24321 jjjjj PWPWRPCRWRUCC ⋅+⋅+⋅+⋅= γγγγ

jjjjj DFDNDSSY εγγγγ +⋅+⋅+⋅+−⋅+ 8765 )1959( (10.1)

Table 10.2-2 Independent variables of estimation equation

RUCC Real-term unit construction cost［1000 JPY／kW ］

RW Real wage rate （Wage index of construction workers／Domestic corporate goods price index (all commodities））［Standardized as 1.00 in the year 2000］


JICA West JEC 10-6

RPC Relative price of capital goods（Domestic corporate goods price index (capital goods)／Domestic corporate goods price index (all commodities)）［Standardized as 1.00 in the year of 2000］

PW Capacity［kW ］

SY Commissioning year

DS Dummy for de-SOx equipment ［with=1, without=0］

DN Dummy for de-NOx equipment ［with=1, without=0］

DF Dummy for Unit-1 ［Unit=1, Others=0］

(Note) Elements in square brackets indicate the unit of each variable

This estimation model assumes that the greater the following factors are, the higher the

unit construction cost will be: (i) the cost of construction labor, (ii) the price of construction materials for power plants and (iii) the capacity of the power plant. In addition, the variable of squared output is added to the set of independent variables considering that the unit construction cost becomes small as the output becomes large (a scale merit effect) but this effect gradually reduces as the output becomes large (the marginal effect of the scale merit reduces). Moreover, the commissioning year of the power plant is also added to the variables set, because it is expected that the unit construction cost will become cheaper with the accumulation of experience and/or technological improvement in power plant construction. This effect is the so-called "Learning effect.” (To standardize the commissioning year, 1961 is deducted from the year so that this variable is set at one (1) for the oldest Niihama-nishi power plant.) Moreover, to account for the factors of de-SOx equipment installation, de-NOx equipment installation, and whether the plant is unit-1 or not, dummy variables are also added.

In step (3), each coefficient of equation (10.1) was estimated by the Ordinary Least Squares method (OLS estimation) using the E-View (ver.6.0) statistical program3 and based on the data in Table 10.2-2. Table 10.2-3 Results of estimation (Sample number: 55)

Coefficient Cost Elements Model -I Model -II 541.1 574.1 γ1 RW Real wage rate

（ 2.36** ）（ 2.63** ） 10.5

γ2 RPC Relative price of capital goods （ 0.71 ）

-----

3 E-Views (ver. 6.0) of Quantitative Micro Software Co.


JICA West JEC 10-7

0

100

200

300

400

500

0 100 200 300 400 500

Original Cost ('000JPY/kW)

Est

imat

ed C

ost (

RU

CC

) (

'000

JPY/

kW)

r 2̂=0.843

-0.35 -0.32 γ3 PW Capacity of plant （-3.40***）（-3.84***）

0.00020 0.00018 γ4 PW2 PW squared （ 2.45** ）（ 2.74***）

-3.59 -4.37 γ5 SY

Commissioning year （1960＝”1”）（-0.64 ）（-0.82 ）

41.4 44.8 γ6 DS Dummy for de-SOx （ 2.19** ）（ 2.28** ）

-19.7 -19.8 γ7 DN Dummy for de-NOx （-1.23 ）（-1.22 ）

64.4 65.7 γ8 DF Dummy for Unit- 1 （ 5.08***）（ 5.35***）

Adjusted R squared 0.840 0.843

(Note) Regarding the statistical significance of coefficients of variables;

1）*** indicates that with a 1％ level of statistical significance the coefficient is “not equal to

zero”; ** indicates a 5％ level and * indicates 10％.

2）Items given in round brackets are t-statistics calculated based on the heteroskedasticity consistent

covariance matrix (White (1980)).

The estimated result for each coefficient is shown as Model-I in Table 10.2-3. After the coefficient of the relative price of capital goods (γ2) was found to be statistically not significant in Model-I, a revised estimation equation which omitted this variable was evaluated again by OLS estimation. The result is shown as Model-II. In Model-II, the coefficient of commissioning year (γ5) and dummy for de-NOx (γ7) are still statistically insignificant.

Fig. 10.2-2 Comparison of estimation and original data


JICA West JEC 10-8

OperationYear

Construction Workers

WageIndex

CorporateGoods

Price Index(General)

(2000=100)

CorporateGoods

Price Index(CapitalGoods)

(2000=100)

Wage rate(real term)(2000=1.00

)

RelativeCapitalGoodsPrice

(2000=1.00)

OperationYear

Flue GasDesulfurizat

ionEquipment

(with=1)

Flue GasDenitrogeni

zationEquipment

(with=1)

Unit 1Index

（Unit 1=1)

W_CONS P_WCPI P_INV RW RPC PW PW^2 SY DS DN DF

a b c d e=b/c f=d/c ｇｈ i j k l

β 574.1 -0.32 0.00018 0.00 44.8 0.00 65.7

101.2 103.3 85.3 0.980 0.826 600 360000 47 1 1 1

562.4 -194.5 66.2 0.0 44.8 0.0 65.7 544.6 (1.000)

130 105 90 1.200 0.857 1000 1000000 65 1 1 1

688.9 -324.2 184.0 0.0 44.8 0.0 65.7 659.2 (1.210)

ESTIMATION

2007

2025

INDEX

Estimated ConstructionUnit Cost (real term)

('000JPY/kW)

RUCG_coal

m

Capacity（MW)

Fig. 10.2-2 shows a comparison of the Model-II estimated unit construction cost and the original data. Adjusted R-Squared (the adjusted coefficient of determination for degree of freedom) is 0.843.

In step (4), using Model-II, the present and future unit construction cost of coal-fired plants is forecast (Table 10.2-4). The present unit construction cost as of 2007 is calculated as 544,600 JPY/kW (price in 2000 JPY), where the real wage rate is 0.980 (2000=1.00), the power plant capacity is 600 MW, with de-SOx equipment and a Unit-1 plant. The future unit construction cost as of 2025 is calculated as 659,200 JPY/kW, where the real wage rate in 2025 is presumed to be 1.20 (2000=1.00) and the power plant output is 1,000 MW. Other assumed factors are the same as for 2007. A comparison of these two unit construction costs suggests that the rate of increase in unit construction cost is about 20% between 2007 and 2025.

Table 10.2-4 Forecast of unit construction cost of coal-fired plant in 2007 and 2025 10.3 Long-term Forecast of Selling Price of Coal-Fired Power Plant

The approximately 20% construction cost increase by 2025 is applied to Indonesia’s

case together with consideration of improved plant efficiency and capacity increase to calculate the selling prices of electricity shown below. The coal price is assumed to remain at USD 90 per ton until 2025, as explained previously. The calculation was done by using same Price Model used in Chapter 5. Note that each variation factor was applied only after 2017, since we assume that the years until 2016 constitute the short-term and that the long-term effects appear between 2017 and 2025.

As shown above, due to construction cost increases, the selling price of electricity is

expected to show a slight upward trend.


JICA West JEC 10-9

Selling Price

6.0

6.5

7.0

7.5

8.0

8.5

9.0

9.5

10.0

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

Year

Sellin

g P

rice

(C$/

kWh)

Selling Price

Year Construction Unit Cost Capacity Efficienc

yConstructio

n CostConstruction unit cost

SellingPrice

$/kW MW % m$ $/kW C$/kWh2008 100% 600 38.0% 726 1,210 8.22009 100% 600 38.0% 726 1,210 8.22010 100% 600 38.0% 726 1,210 8.22011 100% 600 38.0% 726 1,210 8.22012 100% 600 38.0% 726 1,210 8.22013 100% 600 38.0% 726 1,210 8.22014 100% 600 38.0% 726 1,210 8.22015 100% 600 38.0% 726 1,210 8.22016 100% 600 38.0% 726 1,210 8.22017 102% 644 38.3% 794 1,232 8.22018 104% 689 38.7% 864 1,254 8.22019 107% 733 39.0% 937 1,277 8.32020 109% 778 39.3% 1,011 1,300 8.32021 111% 822 39.7% 1,088 1,324 8.32022 113% 867 40.0% 1,168 1,347 8.32023 116% 911 40.3% 1,249 1,371 8.42024 118% 956 40.7% 1,333 1,395 8.42025 120% 1,000 41.0% 1,419 1,419 8.4

Table 10.3-1 Long-term selling price of coal-fired power

Fig. 10.3-1 Long-term selling price of coal-fired power

CHAPTER 11

EVALUATION OF A LONG-TERM

GEOTHERMAL IPP PROJECT


JICA West JEC 11-1

OperationYear Capacity

AverageProductionWell Depth

SteamPipelineLength

Development Style

Construction Unit Cost(Nominal)

Construction Unit Cost(Real-term)

(MW) (m) (m) ('000JPY/kW) ('000JPY/kW)Matsukawa 1966 23.5 1,249 2,400 Joint 111 212Ootake 1967 12.5 474 900 Total 123 230Oonume 1974 9.5 1,582 820 Joint 250 293Onikoube 1975 12.5 288 1,150 Total 388 444Hacchoubaru Unit-1 1977 55.0 1,029 1,050 Total 263 278Kakkonda Unit-1 1978 50.0 1,343 2,585 Joint 158 168Suginoi 1981 3.0 394 420 Total 233 202Mori 1982 50.0 1,915 4,316 Joint 205 177Kirishima Kokusai Hotel 1984 0.1 160 250 Total 500 435Hacchoubaru Unit-2 1990 55.0 1,682 2,945 Total 509 468Uenotai 1994 28.8 1,687 1,398 Joint 323 308Sumikawa 1995 50.0 2,028 1,528 Joint 327 316Yanaizu Nishiyama 1995 65.0 2,338 2,137 Joint 277 267Yamakawa 1995 30.0 1,989 339 Joint 333 321Kakkonda Unit-2 1996 30.0 2,069 3,354 Joint 495 485Takigami 1996 25.0 2,200 3,910 Joint 468 458Oogiri 1996 30.0 1,308 1,172 Joint 370 362Kokonoe 1998 1.0 - 305 Total 150 149Hachijoujima 1999 3.3 1,305 37 Total - -(Remarks) *1 *2 *3(Source) *4 *4 *5 *6 *4 *7, *81. Average production well depth is as of the first year of operation.2. Joint development is a project undertaken by a steam developer and an electric power company. Total project is a project undertaken by an electric power company alone or an owner of the plant alone. 3. Nominal cost is adjusted to 2000 JPY price according to the Corporate Goods Price Index. Source of CGPI is Bank of Japan, Statistic Bureau. 4. Current situation of geothermal development (2007), Japan Thermal and Nuclear Power Engineering Society, 20075. Geothermal Power Plant Catalogue (2000), Japan Geothermal Association, 20006. Ministry of Economy, Trade and Industry, http://www.enecho.meti.go.jp/topics/ground/index.html7. Iikura Jou (1996), Current situation and Challenges of Geothermal Development , Geothermal, Vol.33 No.2, 19968. New Energy and Industrial Technology Development Organization, www.nedo.go.jp/nedata/17fy/09/g/0009g001.html

Power Plant Name

CHAPTER 11 EVALUATION OF A LONG-TERM GEOTHERMAL IPP PROJECT

11.1 Long-term Forecast of Geothermal Power Plant Construction Costs

Prior to the evaluation of a long-term geothermal IPP project, long-term geothermal

power plant construction costs should be forecast. This forecast is carried out through Multiple Regression Analysis using data obtained from Japanese geothermal power plant statistics, the same methodology employed in Chapter 10. An estimation equation for the long-term unit construction cost of a geothermal plant is derived in the form of a multiple regression equation from unit construction cost data, and the future construction cost was estimated with the estimation equation.

Table 11.1-1 Unit construction cost of geothermal power plants in Japan


JICA West JEC 11-2

0

100

200

300

400

500

600

0 100 200 300 400 500 600

Actual Cost ('000 JPY/kW)

Estim

atio

n C

ost (

RU

CG

) ('0

00 J

PY

/kW

)

r 2̂=0.920

0

100

200

300

400

500

600

1960 1965 1970 1975 1980 1985 1990 1995 2000

Year

Geo

ther

mal

Con

stru

ctio

n U

nit C

ost

('000

JPY

/kW

)

Fig. 11.1-1 Real-term unit construction cost of geothermal power plants in Japan (2000 JPY)

Fig. 11.1-2 Comparison of estimation and original data

Table 11.1-1 shows the main specifications and the unit construction cost of geothermal power plants in Japan. The real-term unit construction cost is derived from the nominal unit construction cost by using the CGPI. Fig. 11.1-1 shows the transition of the real-term unit construction cost (price in 2000 JPY) of geothermal power plants in Japan.

As an estimation model of real-term unit construction cost, the following estimation

equation is assumed.

jjjjj DPTLPPRPCRWRUCG ⋅+⋅+⋅+⋅= 4321 ββββ

jjjjj DISYCTPW εββββ +⋅+−⋅+⋅+⋅+ 8765 )1965( （11.1）

Table 11.1-2 Independent variables of estimation equation

RUCG Real-term unit construction cost ［1000 JPY/kW ］

RW Real wage rate （Wage index of construction workers／Domestic corporate goods price index (all commodities））［Standardized as 1.00 in the year 2000］

RPC Relative price of capital goods（Domestic corporate goods price index (capital goods)／Domestic corporate goods price index (all commodities)）［Standardized as 1.00 in the year of 2000］

LPP The length of steam pipe line［ｍ］

DPT The average depth of production wells at inception of commercial operation［ｍ］

PW Capacity ［kW ］

CT Construction period［years］

SY Commissioning year ［year］


JICA West JEC 11-3

DI Dummy variable for project type ［”1” is for a Total project, “0” is for a Joint project ］

(Note) Elements in square brackets indicate the unit of each variable

As in Chapter 10, this estimation model assumes that the greater the following factors

are, the higher the unit construction cost will be: (i) the cost of construction labor, (ii) the price of construction materials for power plants and (iii) the length of steam pipe, (iv) the depth of production wells, and (v) the capacity of the power plant. Moreover, the commissioning year of power plant is added to the set of independent variables to examine the learning effect. (Similarly to Chapter 10, 1965 is deducted so that this variable is set at one (1) for the oldest Matsukawa power plant.) If the learning effect is operative in geothermal power plant construction, the coefficient of this variable (β7) will take a negative value. Moreover, to consider the difference between Joint Projects and Total Projects, a dummy variable is also added.

Each coefficient of this equation was estimated by the Ordinary Least Squares method

based on the data in Table 11.1-1. This estimation was done using data for 17 of the plants in the table, since some of the Kokonoe and Hachijoujima power plant data is missing. The estimation was done using E-Views (ver6.0) as well as results from Chapter 10. The estimated result for each coefficient is shown as Model-I in Table 11.1-3. In this process, a dummy variable is used to control the large difference between the original data and the estimation result for Suginoi and Ootake power plants. After the variable of relative price of capital goods (RPC) was found to be statistically insignificant in Model-I, a revised estimation equation which omitted this variable was evaluated again by the OLS method. The results are shown as Model-II.

Table 11.1-3 Results of estimation （Sample number：17） Coefficients Independent variables Model - I Model –II

840.5 513.4 β1 RW Real wage rate （ 3.53** ）（ 2.90** ）

-62.8 β2 RPC Relative price of capital goods （ 1.55 ）

-----

0.018 0.017 β3 LPP Length of steam pipeline （ 3.44***）（ 2.49** ）

0.104 0.089 β4 DPT Average depth of production wells （ 3.11** ）（ 3.99***）

-4.78 -4.52 β5 PW Capacity of plant （-9.95***）（-10.9***）

36.5 35.1 β6 CT Construction period （ 3.90***）（ 3.27***）

-17.9 -8.89 β7 SY Commissioning year （1966＝”1”）（ 2.67** ）（ 2.14* ）

β8 DI 251.0 226.6


JICA West JEC 11-4

OperationYear

Wage rate(real term)

(2000=1.00)

Construction Period(Years)

OperationYear

Capacity（MW)

ProductionWell

AverageDepth（ｍ）

SteamPipelineLength

(m)

TotalProjectIndex（TotalPJ=1)

AdjustmentDummy

RW Y_CONS SY PW DEPTH PIPE D_INTG DO

β 513.4 35.1 -8.89 -4.52 0.089 0.017 226.6 -179.9

0.980 6 42 60 2,000 8,000 0 0

503.0 210.5 -373.5 -271.2 177.3 133.3 0.0 0.0 379.4 (1.00)

1.200 6 60 60 2,000 8,000 0 0

616.1 210.5 -533.5 -271.2 177.3 133.3 0.0 0.0 332.4 (0.88)

INDEX

2007

2025

Estimated ConstructionUnit Cost (real term)

('000JPY/kW)

RUCG_geothermal

ESTIMATION

Dummy for project type （ 7.23***）（ 10.6***）

-176.9 -179.8 β9 DO Dummy for abnormal data （-6.82***）（-6.24***）

Adjusted R squared 0.921 0.920

(Note) Regarding the statistical significance of coefficients of variables;

1）*** indicates that with a 1％ level of statistical significance the coefficient is “not equal to

zero”; ** indicates a 5％ level and * indicates 10％.

2）Items given in round brackets are t-statistics calculated based on the heteroskedasticity consistent

covariance matrix (White (1980)).

Model-II shows that the coefficient of the commissioning year variable (β7) is negative and statistically significant. This means that the learning effect applies to the unit construction cost of geothermal power plant. A comparison of the estimated geothermal unit construction costs for Model-II and the original unit construction costs is shown in Fig. 11.1-2. The Adjusted R-Squared (the adjusted coefficient of determination for degree of freedom) of Model-II is 0.920.

Using Model-II, the present unit construction cost of a geothermal plant and the future unit construction cost is forecast (Table 11.1-4). The present unit construction cost as of 2007 is calculated as 379,000 JPY/kW (price in 2000 JPY), where the real wage rate is 0.980 (2000=1.00), the power plant capacity is 60 MW, the average depth of production wells is 2,000 meters, the steam pipe line length is 8,000 meters, and the project type is a joint project. The future unit construction cost as of 2025 is calculated as 332,000 JPY/kW, where the real wage rate in 2025 is presumed to be 1.20 (2000=1.00) and other specifications (the power plant output, the average depth of production wells, the steam pipe line length, and the type of project) are the same as the 2007 case. The comparison of these two unit construction costs suggests that the unit construction cost will decrease by about 10% between 2007 and 2025. This price decrease is attributed to the operations of the learning effect in the construction of geothermal power plants.

Table 11.1-4 Forecast of unit construction cost of a geothermal plant in 2007 and 2025


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11.2 Long-term Forecast of Selling Price of Geothermal Power Plant

According to E.A. DeMeo and J.F. Galdo（1997）1, geothermal power generation technology is still under development, and therefore the following technological progress can be expected in the future. <Reservoir exploration and analysis technologies>

Substantial improvements in geophysical sensors and in data processing can be expected to occur over a long interval. Also, advances in computer modeling of geochemical systems and rock-water interactions will provide substantial new information about underground conditions and long-term production processes.

<Drilling technology>

Technologies in this field will continue to progress. The pace here will depend mainly on the pace of geothermal development during the next 10 years, and the degree to which the 500-fold larger market for equipment for drilling oil and gas wells in harder rock at higher temperature improves technologies that then will spill over to improve geothermal operations.

In addition, system studies are in progress for drilling technologies that could substantially reduce the costs of both removing rock and maintaining the integrity of the wellbore during drilling and production (i.e., alternatives to conventional casing). Such systems would be applicable to geothermal drilling under adverse conditions.

<Power plant technology>

Current flash power plant technology, which is usually applied in many geothermal reservoirs, is substantially mature, but analyses indicate that a number of cost-effective design modifications are possible. Binary power plant technology, which is a relatively new technology and allows cooler geothermal reservoir to be used than flash power plant technology, is somewhat less mature, offering more opportunity for optimization.

Based on these improvements, the following cost reductions can be expected:

<Average cost per well> Over the middle term, improved diamond compact bits and control of mud circulation

are expected. Over the long term, costs should drop markedly through radical improvements in drilling technology now being pursued for oil and gas wells.

<Wildcat exploration success rate>

Currently, on average, five deep wells need to be drilled to discover a new geothermal 1 E.A. DeMeo, J.F.Galdo (1997), Renewable Energy Technology Characterizations, DOE/EPRI, 1997 http://www.nrel.gov/docs/gen/fy98/24496.pdf


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Fig. 0

3-D designHP blade

New HP blade profile

High performanceLP blade

0

2

4

6

1998 1999 2000 2001

Eff

icie

nc

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power-capable field. In the near-term (e.g., 10 years), most improvements in this average will come from improved interpretations of local geology through cross-comparison with the geology of other geothermal fields. These improvements will contribute to a better modeling of reservoir structure, heat sources and groundwater circulation. In the long-term, sophisticated improvements in geophysical methods, such as Magnetotelluric (MT) method and Controlled Source Audiofrequency Magnetotelluric (CSAMT) method, will make drilling targets (large water-filled fractures) relatively visible.

（Source）UNOCAL Co. （Source）Fuji Electric Co.

Fig 11.2-1 Days per well at Salak Geothermal PP Fig.11.2-2 Improvement in geothermal steam turbine efficiency

(Source) IPCC Forth Assessment Report, Climate Change 2007,

Fig.11.2-3 Learning effect in solar and wind power


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Weak CostReduction

Case

Strong CostReduction

Case2005 2010 2020 2030 2020/2005 2030/2005

a. Average cost per well '000 $ 1,639 0.80 0.75 0.60 0.50 0.750 0.625

b. Wildcat dry hole ratio ratio 0.80 0.95 0.90 0.80 0.70 0.842 0.737

c. Flow per production well ton/h 304 1.12 1.20 1.30 1.40 1.16 1.25

d. Plant net effectiveness kW/ton/h 26.4 1.09 1.10 1.10 1.10 1.01 1.01

e. Field piping system $/kW 47 0.80 0.70 0.60 0.50 0.750 0.625(Source) E.A. DeMeo, J.F.Galdo (1997), Renewable Energy Technology Characterizations , DOE/EPRI, 1997 www.nrel.gov/docs/gen/fy98/24496.pdf

Performance or Cost Multiplier(relative to 1997 value)Technology Factor or Indicator Units 1997

Value

<Flow per production well> The combined impacts of improved reservoir engineering and improved drilling

technology will reduce formation damage near the wellbore. Improved reservoir engineering will increase the chance to encounter high permeability reservoirs. <Plant net effectiveness>

The progress of reservoir engineering is enabling detail reservoir analysis which also allows plant engineers to design more appropriate plant capacity. Such improvement in the matching of power plant capacity and reservoir conditions will enhance plant net effectiveness.

There are a lot of other materials in addition to DeMeo and Galdo’s work which

support possible cost reductions in geothermal power generation in the future. For example, Ken Williamson (2000)2 reports that the average drilling days per well decreased sharply from 75 days for units 1 & 2 to 27 days - less than one-third of the original time - during 1995 and 1997 when Units 3 to 6 were developed at the Salak geothermal power plant. This remarkable cost reduction can be attributed to the strong learning effect operating in the drilling of production wells. Moreover, some technological improvements have been attained in geothermal steam turbine performance since the 1990's, and turbine efficiency has been increased by about 3% in the past ten years, according to a geothermal power plant manufacturer (Fig. 11.2-2). Such technological progress can be expected to continue in the future. In addition, a learning effect of 8% in geothermal power generation is expected, given the learning effect curve for solar power and wind power reported in a study of renewable energy development in EU countries3.

According to E.A. DeMeo and J.F.Galdo (1997), the cost reductions for geothermal power generation shown in Table 11.2-1 can be expected as a result of this technological progress.

Table 11.2-1 Major technology improvements expected for flash-system geothermal power plants

2 Ken Williamson, UNOCAL, Geothermal Power, Workshop on Sustainable Energy Systems, Nov.29, 2000, Atlanta, USA 3 Mario Ragwitz et al (2007), Assessment and Optimization of Renewable Energy Support Schemes in the European Electricity Market, Intelligent Energy, 2007


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Technology Factor or Indicator Current BaseWeak CostReduction

Case

Strong CostReduction

Case1. Power plant construction cost 1.0 0.9 0.92. Drilling cost per well 1.0 0.750 0.6253. Field piping system construction cost 1.0 0.750 0.6254. Success rate of exploratory wells 50% 50% 70%5. Efficiency of power plant 1.0 1.05 1.106. Flow per production well 1.0 1.16 1.25

In this study, the long-term selling price of geothermal IPP power was calculated based

on the unit construction cost forecast obtained in the previous section and the technological improvements show in Table 11.2-1 for the following two cases.

Case-1 Weak cost reduction case: technological improvements progress at a modest pace and

cost reduction in the future is weak. Progress equivalent to the 2020 level in Table 11.2-1 is expected in 2025.

Case-2 Strong cost reduction case: technological improvements progress at a considerably high pace and cost reduction in the future is strong. Progress equivalent to the 2030 level in Table 11.2-1 is expected in 2025.

Concrete expected values for each case were assumed, as shown in Table 11.2-2.

Table 11.2-2 Forecast of future cost reduction

Based on these assumptions, a long-term selling price for geothermal energy until 2025 was calculated and is shown in Table 11.2-3 (weak cost reduction case) and Table 11.2-4 (strong cost reduction case) and in Fig. 11.2-1. The selling price in 2025 in the weak cost reduction case was 9.7 USD Cents/kWh versus 8.2 USD Cents/kWh for the strong cost reduction case. It is expected that the selling price in 2025 in the strong cost reduction case will be less than the 8.4 USD Cents/kWh selling price for coal-fired power in 2025.


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YearPlantCostFactor

DrillingCostFactor

FieldPipingCost

SuccessRate

Flow perProductio

n WellEfficiency

Geothermal

Selling

Construction unit

cost% C$/kWh $/kW

2008 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112009 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112010 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112011 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112012 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112013 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112014 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112015 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112016 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112017 0.99 0.972 0.972 50% 1.02 101% 11.7 2,9522018 0.98 0.944 0.944 50% 1.04 101% 11.4 2,8932019 0.97 0.917 0.917 50% 1.05 102% 11.3 2,8742020 0.96 0.889 0.889 50% 1.07 102% 10.9 2,7352021 0.94 0.861 0.861 50% 1.09 103% 10.6 2,6772022 0.93 0.833 0.833 50% 1.11 103% 10.4 2,6192023 0.92 0.806 0.806 50% 1.12 104% 10.2 2,5612024 0.91 0.778 0.778 50% 1.14 104% 9.9 2,5032025 0.90 0.750 0.750 50% 1.16 105% 9.7 2,445

Table 11.2-3 Long-term selling price

(Weak cost reduction case)


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0.0

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rice

(C$/

kWh)

Coal Selling Price

Geothermal Selling Price

Strong CostReduction Case

Weak CostReduction Case

YearPlantCostFactor

DrillingCostFactor

FieldPipingCost

SuccessRate

Flow perProductio

n WellEfficiency

Geothermal

SellingPrice

Construction unit

cost

% C$/kWh $/kW

2008 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112009 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112010 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112011 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112012 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112013 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112014 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112015 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112016 1.00 1.000 1.000 50% 1.00 100% 11.9 3,0112017 0.99 0.958 0.958 52% 1.03 101% 11.6 2,9292018 0.98 0.917 0.917 54% 1.06 102% 11.1 2,8072019 0.97 0.875 0.875 57% 1.08 103% 10.8 2,7272020 0.96 0.833 0.833 59% 1.11 104% 10.5 2,6472021 0.94 0.792 0.792 61% 1.14 106% 10.2 2,5672022 0.93 0.750 0.750 63% 1.17 107% 9.8 2,4872023 0.92 0.708 0.708 66% 1.19 108% 9.2 2,2812024 0.91 0.667 0.667 68% 1.22 109% 8.4 2,1502025 0.90 0.625 0.625 70% 1.25 110% 8.2 2,081

Table 11.2-4 Long-term selling price (Strong cost reduction case)

Fig.11.2-4 Long-term selling price of geothermal power

Table 11.2-5 Long-term selling price of geothermal power

Case Selling price of geothermal power

(2025)

Selling price of coal-fired power

(2025)

Price gap （2025）

Weak cost reduction case

9.7 USD Cents/kWh 1.3 USD Cents/kWh

Strong cost reduction case

8.2 USD Cents/kWh

8.4 USD Cents/kWh

△0.2 USD Cents/kWh

CHAPTER 12

LONG-TERM INCENTIVES TO

PROMOTE GEOTHERMAL

DEVELOPMENT


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CHAPTER 12 LONG-TERM INCENTIVES TO PROMOTE GEOTHERMAL DEVELOPMENT

This chapter discusses long-term incentives to promote geothermal development

without substantial governmental cost-sharing. Three typical incentives, (i) the Clean Development Mechanism (CDM), (ii) Carbon Tax, and (iii) Localization of geothermal technology, are discussed.

12.1 Clean Development Mechanism (CDM)

The Clean Development Mechanism (CDM) is one of the schemes adopted in the Kyoto Protocol (one of three so-called Kyoto Mechanisms), and is designed to reduce greenhouse gas (GHG) emissions through cooperation between developed and developing countries. The CDM allows project-based GHG reductions in developing countries (Non-Annex 1 countries) to be transformed into Certified Emission Reductions (CERs), which, in turn, are available to industrialized countries (Annex 1 countries) for use as credits against their own Kyoto emission control commitments. The CDM was introduced to generate both cost-effective GHG reductions for Annex 1 countries and sustainable development benefits for host developing countries. Indonesia ratified the United Nations Framework Convention on Climate Change (UNFCCC) in August 1994, and signed the Kyoto Protocol in July 1998. As a result, Indonesia is eligible to use this CDM to reduce GHG emissions in the energy sector, ensuring its sustainable social and economic development.

Once a project is approved as a CDM project, the owner of the project can obtain

revenue by selling the CERs during the operation stage. For a project which needs a large upfront investment, like a geothermal project, the use of CERs is a great support for project financing. Therefore, the CDM is a new financial resource, an opportunity to create better technology, and a tool for achieving sustainable development for developing countries, while providing access to to relatively inexpensive CERs for industrialized countries. As emission reductions have the same global effect irrespective of their

(Source) Institute for Global Environmental Strategies

Fig. 12.1-1 Scheme of CDM


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geographical origin, the CDM provides a cost-effective way of addressing the adverse effects of global warming. This scheme is one of the realistic options to assist in financing geothermal projects which do not need substantial governmental cost sharing. Indonesia has started efforts to implement the CDM locally, with the progress described below.

<The CDM Development Process> The process for developing CDM projects and obtaining CERs is as follows:

(1) Planning a CDM project activity CDM project participants plan a CDM project activity. There are several eligibility conditions for CDM projects. For example, project participants should use the approved methodology for CDM application. Therefore project participants should consider those conditions from the planning stage.

(2) Making a Project Design Document Project participants draft a Project Design Document (PDD) for the CDM project activity. The PDD is a key document, presenting information on the essential technical and organizational aspects of the project for the validation, registration, and verification process. The PDD should also include information on the applied baseline methodology and the monitoring methodology for the project.

(3) Obtaining approval from each party involved Project participants shall get written approvals from the Designated National Authority (DNA) of each country involved, including the host country. Although the detailed approval procedure differs from country to country, approval from the host country at least should be obtained before a request for registration.

(4) Validation Validation is the evaluation of whether the project activity is in line with the requirements of the CDM. This validation is carried out by a Designated Operational Entity (DOE) on the basis of the PDD information and according to the established procedure for validation.

(5) Registration Registration is a formal acceptance of the validated project as a CDM project. Registration is done by the CDM executive board (EB). Project participants pay a registration fee at the registration stage.

(6) Monitoring CDM project activity

(1) Planning a CDM project activity

(2) Making project design document(PDD)

(3) Obtaining approval from eachparty involved

(4) Validation

(5) Registration

(7) Verification and certification

(6) Monitoring CDM project activity

(8) Issuance of CERs

(9) Distribution of CERs

Fig.12.1-2 Procedure of CDM


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After the project starts operation, Project participants collect all relevant data necessary for calculating the GHG emission reductions of the project activity, in accordance with the monitoring plan specified in the PDD.

(7) Verification and Certification Verification consists of a periodic independent review and ex-post determination of the monitored GHG emission reductions. Verification is carried out by a Designated Operational Entity (DOE) in accordance with the established procedures for verification. Certification is the written assurance of the DOE that the project has achieved the verified reductions in GHG emissions.

(8) Issuance of CERs The EB will issue Certified Emission Reductions (CERs) equal to the verified amount of GHG emission reductions. There is a formal procedure for the issuance of CERs. Project participants should select one of the following two options: (i) CERs with a maximum validity of 7 years with the possibility of two renewals at most, or (ii) non-renewable CERs with a maximum validity of 10 years. The issuance of CERs, in accordance with the distribution agreement, is effected only when the Share of Proceeds to cover administrative expenses (SOP-Admin) has been received. 2% of the value of issued CERs will be deducted and added to the Share of Proceeds fund created to assist developing countries that are particularly vulnerable to the adverse effects of climate change to meet the costs of adaptation (SOP-Adaptation).

(9) Distribution of CERs CERs will be distributed to Project participants. Decisions as to further distribution of CERs will be taken exclusively by Project participants.

<Indonesia CDM Institutional Arrangements>

Indonesia signed the UNFCCC in June 1992 and ratified it in August 1994 into Law No. 26 of 1994. Under this global framework, Indonesia is committed to fully implement the Convention as one of the non-Annex I parties, based on the “common but differentiated responsibilities” principle. In July 1998, Indonesia signed the Kyoto Protocol and the House of Representatives approved the ratification with Law No. 17 of 2004.

In 2005, Ministry of Environment Regulation No. 206 of 2005 designated the National Commission for CDM (Komite Nasional Mekanisme Pembangunan Bersih (KNMPB)) as the Designated National Authority (DNA). The commission consists of permanent and non-permanent members. The permanent members are the Minister of Energy and Mineral Resources, the Minister of Forestry, the Minister of Transportation and Communication, the Minister of Industry and Trade, and the Minister of Agriculture, while the non-permanent members are comprised of representatives from NGOs, experts, the relevant business association (KADIN) and local government associations. The Ministry of Environment, as the


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national focal point of the UNFCCC, coordinates the committee. The Indonesian DNA has the power to approve proposed CDM projects based on national sustainability criteria and is responsible for tracking the progress of CDM projects submitted to the CDM Executive Board. The DNA is expected to facilitate communication between investors, proponents and other relevant parties, to build capacity, and to disseminate information regarding CER potential and markets.

Under the current system, there are essentially three (3) levels of institution involved in the CDM in Indonesia: local, national and international institutions. Local institutions ensure the eligibility of the proposed project, considering such factors as land, social impact and stakeholders’ involvement. The national institutions are the DNA and the CDM Working Group of Relevant Ministries, which is clearly guided by Ministry of Environment Decree No. 206/2005. International institutions deal with issues following on from approval at the national level. (Source) IGES CDM Information “Indonesia” (2009）

In July 2008, Presidential Regulation Number 46 of 2008 established Dewan Nasional

Perubahan Iklim (DNPI) or the National Council on Climate Change. The Council is chaired by the President and is composed of ministers and the head of the Meteorological Office. The tasks of DNPI include the formulation of national policy, strategies, programs and activities related to climate change, the coordination of activities related to climate change (adaptation, mitigation, technology transfer, and financing), the formulation of policy on mechanisms and procedures for carbon trading, the evaluation and monitoring of the implementation of policies related to climate change, and the strengthening of Indonesia’s position promoting greater accountability for climate change among the developed countries. The DNPI is assisted by six (6) working groups overseeing adaptation, mitigation, technology transfer, financing, post Kyoto 2012 policy, and changes in forestry and land use. < CDM National Approval Process and the role of the DNA1>

(1) A project proponent submits an application document to the National Commission of CDM consisting of the following: • National Approval Application Form;

1 Institute for Global Environmental Strategies (IGES), CDM Information “Indonesia” (2009)

Table 12.1-1 Status of Indonesia

in Kyoto Protocol

Signature of Climate ChangeConvention 5 June 1992

Ratification of ClimateChange Convention 23 August 1994

Signature of Kyoto Protocol 13 July 1998

Ratification of Kyoto Protocol 3 December 2004

Establishment of DNA 21 July 2005


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• Project Design Document (PDD); • EIA report (where required); • Notes of public consultation; and • other supporting documents to justify the project

(2) The National Commission posts the Project Proposal on its website to invite comments from the public and stakeholders.

(3) The National Commission starts the approval procedure. If required, the National Commission assigns a group of experts to perform an additional evaluation of the project proposal to get a second opinion.

(4) The National Commission assigns members of the Technical Team to evaluate the project proposal based on Sustainable Development Criteria and Indicators. The whole process of technical team evaluation is completed within 21 days.

(5) The Technical Team submits their Evaluation Report on the project proposal to the National Commission. The Technical Team's Evaluation Report is then posted on the National Commission website.

(6) The National Commission decided whether the project will be given approval or not, based on the results of the project evaluation report and stakeholders’ comments. If there is any significant difference of opinion between the stakeholders who are in favor of and those who are against the project proposal, the National Commission may hold a special stakeholder forum. At the special stakeholder forum, the National Commission presents the controversial project proposal and compiles comments from participants in the special stakeholder forum meeting.

(7) If the National Commission cannot give its approval because of incomplete data in the project proposal, the project proponent is given 3 months’ time to prepare and resubmit a revised project proposal to the National Commission. The revised project proposal documents are processed in the standard way. A revised application may be submitted only once for any given proposal.

(8) The National Commission sends a letter of approval to the project proponent.


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(Source) Made by the Study Team

Fig. 12.1-3 Indonesia DNA Validation Process <Current Status of CDM Projects in Indonesia>

Since its establishment in July 2005, the Indonesian DNA has approved a total of 90 projects (as of February 2009). Twenty three (23) of the 90 projects have been registered by the CDM Executive Board (EB) as approved. In addition, there are 10 projects at the validation stage, consisting of one project pending approval, 5 projects to be recommended for approval and 4 projects undergoing evaluation. These projects vary from biomass utilization projects to methane recovery & utilization projects and renewable energy projects. Included in the list of 23 projects that have been registered by the CDM EB as approved is the development of the Darajat III geothermal power plant. Also, in the DNA’s list of approved projects are Kamojang (West Java) and Sibayak (North Sumatra) geothermal power plants (the two IPP projects that were postponed following monetary crisis in 1998) and Lahendong II (North Sulawesi). The


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other geothermal project in the list is Wayang Windu II, which is under evaluation.2

＜Effect of CDM＞

The selling price of geothermal energy is currently higher than the selling price of coal-fired energy in Indonesia. Accordingly, PT PLN plans to develop power sources mainly based on coal-fired power plants. Therefore, the Study Team assumes that the construction of coal-fired power plants provides the baseline for the Business as Usual (BAU) scenario, and that it is highly likely for geothermal projects to be approved as CDM projects due to the existence of financial barriers to investment.

When a geothermal power plant substitutes for a coal-fired power plant of the same

capacity, emissions will be reduced by 0.944 kg of CO2 per each 1 kWh generated (refer to Section 7.5). Accordingly, if the geothermal plant project is approved as a CDM project, the value of the CO2 reduction achieved by the geothermal plant amounts to 0.944 USD Cents/kWh, if the price of CERs is 10 USD per 1 ton of CO2. However, the geothermal project developer cannot obtain this whole amount during the operation of the plant, partly because the CERs are only effective for 7 years (with a maximum of two renewals) or 10 years (without renewal) and partly because there are some deductions of CDM administration expenses (SOP-Admin) and a 2% deduction of Share of Proceeds for adaptations (SOP-Adaptation) from the sales of CERs. This Study calculated the effect of CDM on the selling price of geothermal power based on the assumptions that (i) the CERs are effective for 10 years and (ii) 5% is deducted from the total sales for SOP-Admin and SOP-Adaptation.

The selling price of geothermal energy is 11.9 USD Cents/KWh when it is not a CDM

project, but it falls to 11.1 USD Cents/kWh for a CDM project when the CERs are worth 10 USD/ton. If the CER price increases to 20 USD/ton, 30 USD/ton or 40 USD/ton, the selling

2 National Commission for CDM, Status of CDM Projects in Indonesia, http://dna-cdm.menlh.go.id/en/database/, February 2009

8.99.7

10.411.1

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8.2

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10 $/ton 20 $/ton 30 $/ton 40 $/ton

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e (c

$/kW

h)

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Geothermal Power Plant Selling Price

Fig.12.1-4 CDM effect （2012-2016）


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0.0

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2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Year

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($/k

Wh)

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CO2 Price 10$/ton

CO2 Price 20$/ton

CO2 Price 30$/ton

Coal PP Selling Price

0.0

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2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

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/kW

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Without CDM

CO2 Price 10 $/ton

CO2 Price 20 $/ton

CO2 Price 30 $/ton

Coal PP Selling Price

price decreases accordingly to 10.4 USD Cents/kWh, 9.7 USD Cents/kWh and 8.9 USD Cents/kWh (Fig. 12.1-4). This shows that there is a selling price reduction effect of approximately 0.8 USD Cents/kWh per 10 USD/ton of CER price. Over the long-term, the price gap between geothermal and coal-fired power will disappear sometime in the 2020s, if the geothermal project is carried out as a CDM project (Fig. 12.1-5 and Fig. 12.1-6).

Fig.12.1-5 Long-term CDM effect Fig.12.1-6 Long-term CDM

effect （Weak Cost Reduction Case）（Strong Cost Reduction Case）

<Issues in the Implementation of CDM>

The governance structure and institutional design of the CDM will be fundamental to its success as an instrument for achieving reductions in GHG emissions and in promoting sustainable development. Also, given different interests and concerns among the parties, the implementation of CDM projects in Indonesia will face challenges. The following discusses some of the issues and challenges that lie ahead for Indonesia’s CDM projects.

(i) Difficulties in designing a CDM project (Technical difficulties in baseline methodology)

One of the most difficult issues in the CDM has been, and continues to be, the setting of the baseline – the level of GHG emissions that would have occurred without implementation of the project. Baseline rules and also CER prices have a crucial impact on the attractiveness of CDM projects to geothermal developers. With an appropriately designed baseline, which provides a large amount of CERs and high CER prices, geothermal projects can cover a significant share of investment costs through CER sales. Given this fact, the setting of a baseline is a critical issue in designing CDM projects in terms of determining incentives for investors.


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Despite the clarity of its concept, the methodologies used in baseline setting are technically difficult. There are a number of approaches to determining a baseline, from static to dynamic baselines, and from project-level to sectoral and national-level baselines. The project-based method may include a single project or multiple projects. A single project baseline is set by looking at each project in detail, and considering the technology features and the difference in GHG emissions before and after implementation. While the single-project baseline method is potentially the most accurate, it is time-consuming and costly, and is thereby only appropriate for large CDM projects.

To cope with this difficulty, it would be convenient to set a national standard in advance which is computed according to the average level of technology and end-use efficiency within each country. Given the large and diverse country that it is, it may be difficult for Indonesia to establish a national standard. However, it is required for the convenience of the CDM project designer that a national standard be set which reflects the wide variation in environmental performance across Indonesian industry. (ii) The lack of necessary data for baseline methodology and monitoring methodology

The baseline methodology will need to conform to the approaches outlined in the Marrakech Accords3. Project participants will select from among the following approaches to baseline setting the one deemed most appropriate for their project activity, taking into account guidance from the Executive Board, and justifying the appropriateness of their choice:

(a) Baseline based on existing actual or historical emissions, as applicable; or (b) Baseline based on emissions from a technology that represents an economically

attractive course of action, taking into account barriers to investment; or (c) Baseline based on the average emissions of similar project activities undertaken in the

previous five years in similar social, economic, environmental and technological circumstances; and whose performance is among the top 20 percent of their category.

Any proposed CDM project therefore has to use an approved baseline and monitoring

methodology to be validated, approved and registered. Baseline Methodology will set steps to determine the baseline within certain applicability conditions, while monitoring methodology will set specific steps to determine monitoring parameters, quality assurance, and equipment to be used, in order to obtain data to calculate the emission reductions. (If a project developer cannot find an approved methodology that fits his/her particular case, the project developer may submit a new methodology to the Methodologies Panel, but this requires a great deal of work and time.)

Another obstacle facing CDM in Indonesia is the lack of data for baseline definition. 3 The Marrakesh Accord was adopted at COP7 as an agreed document specifying the operating rules of the Kyoto Protocol and its mechanisms.


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The necessary data is obtained by PT PLN and much of it is not disclosed. In this situation, project developers who do not have access to data would incur high transaction costs to collect it by themselves. This discourages the developers from developing CDM projects and reduces the benefits of CDM. To cope with this problem, the government should set up all institutions necessary to facilitate CDM project development in electricity supply and energy efficiency improvement. Presently, the Indonesian DNA has the right to approve the determination of baseline emissions, but who has to compute these emissions and to fund the computation cost is unclear. For example, in the first determination of baseline emission for the Jawa–Bali–Madura (JAMALI) system, the majority of the calculations have been carried out by Amoseas, which has a keen interest in seeking CDM approval for the Darajat III geothermal project. To our knowledge, no computations have been carried out to date for projects outside of the JAMALI system. Also, it is important that such determinations of baseline emissions should be updated periodically. However, the current system, in which each private company bears the full burden of computing baseline emissions in this way will simply not work. Some public institution for this purpose is necessary. (iii) Unclear CER distribution rule

Another issue in the implementation of CDM is the question of who has the right to the CER value, which in current geothermal contracting is not standardized. For example, in the case of Darajat III, the developer has the right to all of the CER value, but that is apparently not the case with the Kamojang contract, where the right is retained by PT. PLN. Since the developer is the one who has full control in monitoring the CER parameters in the operation of a geothermal field, it is appropriate for all of the right to CER value to devolve to the developer.

In summary, a “national support system for the CDM” needs to be established. This should include (but not be limited to) collecting information and determining policies, and consideration of organization, finance and technologies. The central government should make use of such support systems to lead and supervise CDM negotiation and implementation. In addition, the country needs to establish a comprehensive system for the monitoring of GHG emissions, in order to determine the distribution of Indonesian GHG emissions. <Risks and Uncertainties Accompanying the CDM Scheme>

The successful operation of the CDM scheme is predicated to a large extent on the entry into force of the Kyoto Protocol and the implementation of the CDM in accordance with the Kyoto Protocol guidelines. Also, the market for CERs is yet to be fully developed, and the risks associated with these relate to their price and the demand for them. CDM projects already processed under the CDM scheme are at risk in case of non-enforcement or if the price of CERs collapses. Also, a CDM project is subject to country risks due to political or economical instability in the host country. These risks include fluctuation of exchange rates, leading to financial risks for the CDM project. The country risks are implicitly dealt with as volatility in


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revenue from CDM projects. Fluctuation of CER prices can also change the asset value of CERs.

CER prices have recently been on a downward slide since peaking at €29 in mid-2008 on the back of the large spike in oil prices, which ended when the global credit crisis hit financial markets and fears of world recession were realized. The price has halved just in the first six weeks of 2009. Market analysts have been revising their forecasts for carbon prices for this year downward, and there is some possibility of seeing benchmark prices no higher than €10 to €12 for the rest of 2009. A number of related factors are weighing heavily on carbon markets currently, combining to drive a plummeting of demand and an increase in supply, with the inevitable downward pressure on prices.

These CER risks are borne by the CDM project owners, and could be eliminated or reduced if the owners entered into a prior arrangement to sell their CER credits or part of their CER credits in a futures market. However, this could be a disadvantage to CER sellers in the case of higher future CER prices. The project proponents have to weigh the trade-off between risk and certainty in their decision-making.

Another risk at the project level arises if a specific project fails to qualify as a CDM project. In this case, the party that bears the CDM development costs faces the risk.

The final and maybe the largest challenge facing the CDM scheme at present is that no political consensus has been reached on the framework to reduce greenhouse gases after 2012. If the basic framework of the Kyoto Protocol should change drastically, the value of CERs might vanish after 2012. For this reason, the future value of CERs is quite uncertain, creating serious risk for CDM project developers (Post-2012 Risk). <Conclusion concerning CDM incentives>

In conclusion, the CDM scheme can be summarized as follows: CDM provides an extremely strong incentive for geothermal projects. Although utilization of CDM requires its costs, the benefits of CDM greatly surpass the costs because geothermal projects can create a large volume of CERs. However, it is not appropriate to depend on this scheme alone, since both the future of this scheme and of CER prices is not clear at this moment.

12.2 Carbon Tax

The carbon tax is one of the measures developed to address the global warming issue

and is a tax imposed on fossil fuels based on their carbon content. The tax works as an economic disincentive by raising fossil fuel prices so that carbon dioxide emissions from their combustion are reduced. At the same time, it works as a generator of funds for the government


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chest to address the global warming issue. The carbon tax is a kind of so-called environmental tax that is part of a system that aims to impose a surcharge on hitherto free uses of the environment, e.g. as a dumping ground for CO2 emissions.

Carbon tax is charged on fossil fuels such as coal, crude oil, natural gas and petroleum

products (gasoline, kerosene, heavy oil and so on). In European countries, several taxes have been imposed on energy to address the global warming issue. Some of them are imposed on the basis not only of the carbon content but also the energy quality and quantity. In this Study, carbon tax is broadly defined as taxation which is imposed on carbon dioxide emissions and/or fossil fuel consumption with the purpose of mitigating global warming. < The Concept of the Carbon Tax >

The carbon tax is a kind of environmental tax. According to the basic concepts of micro-economics, market equilibrium is established at the intersection of the demand curve and the supply curve (A in Fig. 12.2-1). At this point, the price, Po, of a commodity and the amount of supply, Qo, is determined. But costs arising from environmental pollution are usually not included in the supplier’s cost. Thus, in addition to the price which consumers pay, the society has to pay the additional cost of environmental pollution. The aim of the environmental tax is to eliminate this additional payment by society, by forcing suppliers to include this cost in the product price. That is to say that the tax shifts the supply curve upward by the environmental pollution cost (the new curve is called the social supply curve), creating a new equilibrium point, B. The new price, P1, and the new supply quantity, Q1, that are thereby determined represent a socially desirable price and quantity. Here, the added environmental pollution cost corresponds to the environmental tax.

With the

environmental tax added to the supply curve of commodity, the price of the commodity rises and the quantity supplied decreases. Accordingly, consumers and suppliers (enterprises) suffer opportunity losses (△ABC) due to the introduction of environmental tax. However, the tax increases the benefit to the whole society because of the elimination of the environmental pollution cost

Fig.12.2-1 Mechanism of environmental tax

(Source) Mitsui knowledge Industry Co.

Y X

Private company'sSupply Curve

Social Supply CurveDemand Curve

Environmental Cost

P1

P0

Q1 Q0

AC

B

Quantity

Price


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(QoXYQ1), which is bigger than the opportunity losses introduced by the environmental tax. The environmental tax can also be understood as tool for realizing the “Polluter Pays”

principle. In 1972, OECD established the principle that the polluter should pay all the prevention and mitigation costs of pollution and that the cost should be added to the price of related commodities and services. This principle is called the “Polluter Pays” principle. In order to implement this principle, polluters are required to carry out environmental protection measures according to the relevant regulations and the burden of the cost of these measures is to fall on the polluters themselves. The environmental tax is an example of this. < Carbon Tax in Other Countries >

There are eight (8) countries now in Europe that have introduced a carbon tax as an environmental tax: Finland, Denmark, Sweden, Norway, Holland, the United Kingdom, Germany and Italy. In Finland, Denmark and Sweden, the tax is applied according to the carbon content of the fuel, and in other countries the tax is applied according to the calorific amount involved or the quantity base (not by carbon content). Outside of Europe, a carbon tax was introduced in Boulder city in the United States in 2006. In Canada as well, the province of British Columbia announced the introduction of a carbon tax in February 2008. In Japan, the Ministry of Environment had intensively considered the introduction of this tax in 2004 and 2005, but has not yet enacted.

In 1990, Finland was the first country in the world to introduce a Carbon Tax. In

Finland, an energy tax had been imposed on liquid fuel, some other specified fuels and electricity. In April 1989, the Commission on Environment and Economy proposed a carbon tax. Based on this proposal, the government worked out a Carbon Tax bill, and the parliament enacted the carbon tax in January 1990. This Carbon Tax was incorporated into the energy tax as a surtax. The objective of this taxation is to suppress CO2 emissions, and the tax is imposed on heavy oil, coal, natural gas and electricity according to their carbon content. The tax rate is about USD 30 per 1 ton of CO2 emissions, but it is reduced to about USD 15 for natural gas. The use for the tax revenue is not specified4.

Denmark had added petroleum, electricity and gas to the list of the Energy Tax for

monetary reasons in 1970s. In response to the rise of environmental awareness among the public, the country announced its “Energy 2000” policy in 1990, and established a target of 20% CO2 reduction from 1988 levels by 2005. The Danish government then reformed the taxation system to attain this target and introduced a CO2 Tax for domestic use in 1992 and for industrial use in 1993 on the top of the Energy Tax (with a tax rate of 100DKK per 1 ton of CO2

5). Behind the 4 The Institute of Energy and Economics, Japan “A Study on the Data related to Global Warming Issues” , Ministry of Economy, Trade and Industry (2005) 5 Danish Krone (1 DKK=0.175USD (as of February 2009))


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introduction of this tax, lay the important intention to secure a new governmental income source to cope with the income tax reduction that was designed to alleviate the unemployment rate. The CO2 Tax thus has the dual objective of raising revenue and reducing carbon dioxide emissions. The tax revenue is intended for general purpose use. In 2008, the CO2 Tax rate was about USD 20 per 1 ton of CO2 emissions6.

In Sweden, three kinds of tax, namely the Energy Tax, the CO2 Tax, and the Sulfur Tax,

are imposed on energy products. Among these, the CO2 tax is levied on the carbon content of each fuel. The current tax rate is about 100Euro/ton-CO2. There are many tax deduction schemes in the industrial sector and, therefore, the main taxpayers are the transportation sector and the district heating business sector. Sweden introduced the CO2 tax in the context of taxation reform in 1991. The tax rate of that year was 250SEK/ton-CO2. The Sulfur Tax was introduced simultaneously in that year for the purpose of discouraging fossil fuel consumption. Behind the introduction of these taxes, was the intention to reduce the income tax rate and to increase the proportion of indirect tax. With the introduction of the CO2 tax, the income tax rate was reduced to 30%. The objective of the CO2 tax is to reinforce indirect tax revenue and to address the issue of global warming. These tax revenues have been incorporated into the public general revenue7.

In Holland, fifteen traditional earmarked taxes were consolidated into the Mineral Oil

Tax to secure revenue for environmental protection in 1988. In 1992, in addition to the Mineral Oil Tax, the General Fuel Tax was introduced, and this is based on the carbon content and the energy quantity of the fuel. In response to a 2004 EU Directive concerning energy taxes, the Dutch government integrated the General Fuel Tax into the Mineral Oil Tax. These tax revenues are used for general purposes.

A Climate Change Levy has been imposed in the United Kingdom. The UK government started seriously considering the global warming issue after the third Conference of Parties (COP3) of UNFCC in Kyoto in 1997. In the following year, 1998, the Lord Marshal of the British Industry Federation compiled a report entitled “Economic Instruments and the Business Use of Energy” (known as the "Marshal report") with the support of Ministry of Finance. The report suggested a mixed policy on carbon tax, an agreement concerning climate change, and emissions trading. Following this suggestion, the UK government introduced the Climate Change Levy in the industrial sector and the commercial sector in 2001. The purpose of this taxation is to reduce GHG emissions by 12.5%, which complies with the numerical goal of the Kyoto Protocol. The tax is levied on fuels which had been exempted from the previously

6 The Institute of Energy and Economics, Japan “A Study on the Data related to Global Warming Issues” , Ministry of Economy, trade and Industry (2005) 7 The Institute of Energy and Economics, Japan “A Study on the Data related to Global Warming Issues” , Ministry of Economy, trade and Industry (2005)


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existing Hydrocarbon Tax, such as coal, natural gas, LPG, and electricity consumed in the industrial and commercial sectors. The tax rate per one ton of CO2 is about USD 10 for coal and about USD 17 for natural gas. The tax revenue is used to reduce social insurance premium payments, to fund energy security measures and the promotion of renewable energy, and so on8.

In 2003, the EU issued the “EU Council Directive on Restructuring the Community Framework for the Taxation of Energy Products and Electricity (2003/96/EC of 27 October 2003). In this directive, the minimum EU tax rate for energy products is stipulated. This does not refer to a carbon tax or CO2 tax, but does recommend taxation not only of mineral oils but also of coal, gas, and electricity, which had previously been free of EU tax obligation. This directive is a clear step by the EU towards harmonizing energy consumption and environmental protection.

The energy taxation history of European countries is shown in Table 12.2-1, the

energy tax rates of Japan and European counties are found in Table 12.2-2, and the tax rates per 1 ton of CO2 emissions are in Table 12.2-3.

8 Infromation about Holland and the UK is derived from Central Environment Council, “On the Economics Analysis on Environment Taxes,” Ministry of Environment, Japan (August, 2005）


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U.K. 1993-99 Tax rate of existing Energy Tax was raised.A tax rate of Hydrocarbon Oil Duty (gasoline, diesel, heavy oil, etc.) was raised morethan the inflation rate every year. (escalator system)

2001 A new tax was introduced on energies which had been free from existing EnergyA new Climate Change Tax was introduced on coal, natural gas and electricity.

Germany 1999 Tax rate of existing Energy Tax was raised. A new tax was introduced on energieswhich had been free from existing Energy Tax.A tax rate of Mineral Oil Tax (gasoline, diesel, heavy oil, etc.) was raised.A new Electricity Tax was introduced on electricity.

2006 The range of Energy tax was expanded.Coal was newly taxed. Mineral Oil Tax was reorganized as Energy Tax.

France 2007 A new tax was introduced on energies which had been free from existing EnergyA new Coal Tax was newly introduced on coal which had been free from Oil

Holland 1992 A new tax was added to existing Energy TaxA new General Fuel Tax was introduced based on carbon contents and heat value inaddition to Mineral Oil Tax.Coal was newly taxed.

2004 General Fuel Tax was reorganized into Energy Tax.General Fuel Tax on gasoline, diesel, and heavy oil was reorganized into Energy Tax.General Fuel Tax on coal was changed into Coal Tax.

Finland 1990 A new Additional Tax was added to existing Energy Tax based on the fuel carbonA new Additional Tax was added to existing Energy Tax based on the fuel carbonNatural gas tax rate was set as half of other energies.Tax rate was revised based on carbon content and energy value in 1994.Tax rate was revised based on carbon content alone in 1997.

Denmark 1992 A new Carbon-dioxide Tax was introduced onto existing Energy Tax based on thefuel carbon content.A new Carbon-dioxide Tax was introduced onto existing Energy Tax (Mineral Oil Tax,Coal Tax, natural Gas Tax etc.) based on the fuel carbon content.

Table 12.2-1 Energy taxation history of European countries

（Source）Materials presented by the Special Technical Committee on “Green taxes and their Economics Analysis”,

the Central Environment Council, Ministry of Environment, Japan (August, 2005)


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(As of 2008, July)Gasoline Diesel Heavy Oil Coal Natural Gas Electricity（USD/kL) （USD/kL) （USD/kL) （USD/ton) （USD/ton) （USD/MWh)

Japan 526.79 322.08 19.25 6.60 10.19 3.54Gasoline Tax Diesel Tax

507.55 302.83Oil & Coal Tax Oil & Coal Tax Oil & Coal Tax Oil & Coal Tax Oil & Coal Tax Power Plant Dev. Tax

19.25 19.25 19.25 6.60 10.19 3.54

UK 997.55 997.55 184.06 24.62 55.09 9.04Hydrocarbon Oil Duty Hydrocarbon Oil Duty Hydrocarbon Oil Duty Climate Change levy Climate Change levy Climate Change levy

997.55 997.55 184.06 24.62 55.09 9.04

Germany 994.06 714.43 37.26 13.30 58.40 18.68Energy　Tax Energy　Tax Energy　Tax Energy　Tax Energy　Tax Electricity Tax

994.06 714.43 37.26 13.30 58.40 18.68

France 921.79 650.66 25.28 13.40 31.60 -Oil Consumption Tax Oil Consumption Tax Oil Consumption Tax Coal　Tax N' Gas Cons. Tax

921.79 650.66 25.28 13.40 31.60 0.00

Holland 1046.51 633.40 633.40 19.62 363.11-18.49 114.22-0.76Mineral Oil Tax Mineral Oil Tax Mineral Oil Tax Coal Tax Energy tax Energy Tax

1046.51 633.40 633.40 19.62 363.11-18.49 114.22-0.76

Finland 952.36 552.83 91.60 76.70 49.06 3.99Liquid Fuel tax Liquid Fuel tax Liquid Fuel tax ectricity & Specific Fuel tectricity & Specific Fuel tElectricity & Specific Fuel tax

Base tax Base tax Base tax Base tax Base tax Base tax 869.43 465.85 - - - -

Additional Duty (CO2 taxAdditional Duty (CO2 taxAdditional Duty (CO2 taxAdditional Duty (CO2 taxAdditional Duty (CO2 tax Additional Duty (CO2 tax)72.64 81.70 87.74 74.91 47.08 3.80

Strategic Storage tax Strategic Storage tax Strategic Storage tax Strategic Storage tax Strategic Storage tax Strategic Storage tax10.28 5.28 3.87 1.79 1.98 0.20

Denmark 846.60 630.28 445.57 346.70 716.79 138.74Mineral Oil Tax Mineral Oil Tax Mineral Oil Tax Coal tax Natural Gas Tax Electricity Tax

800.75 579.72 391.60 301.42 653.40 120.02CO2 tax CO2 tax CO2 tax CO2 tax CO2 tax CO2 tax45.75 50.57 53.87 45.28 63.40 18.72

EU Direction 545.28 458.68 20.47 6.04 14.34 0.76(Source) Ministry of Environment, Japan (Note) Exchange rate : 1 USD=106 JPY, 1UK Pound=210JPY, 1Euro=161JPY, 1 Denmark Krone = 0.208 USD

Table 12.2-2 Energy tax tariffs in Japan and European countries


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(As of 2008, July)Gasoline Diesel Heavy Oil Coal Natural Gas（USD) （USD) （USD) （USD) （USD)

Japan 226.91 122.96 7.10 2.75 3.77Gasoline Tax Diesel Tax

218.61 115.61 0.00 0.00 0.00Oil & Coal Tax Oil & Coal Tax Oil & Coal Tax Oil & Coal Tax Oil & Coal Tax

8.29 7.35 7.10 2.75 3.77

UK 429.65 380.83 67.92 10.22 17.17Hydrocarbon Oil Duty Hydrocarbon Oil Duty Hydrocarbon Oil Duty Climate Change levy Climate Change levy

429.65 380.83 67.92 10.22 17.17

Germany 428.19 272.78 13.75 5.54 18.21Energy　Tax Energy　Tax Energy　Tax Energy　Tax Energy　Tax

428.19 272.78 13.75 5.54 18.21

France 397.05 248.42 9.33 5.55 9.85Oil Consumption Tax Oil Consumption Tax Oil Consumption Tax Coal　Tax N' Gas Cons. Tax

397.05 248.42 9.33 5.55 9.85

Holland 450.75 241.81 233.75 8.16 113.23-5.75Mineral Oil Tax Mineral Oil Tax Mineral Oil Tax Coal Tax Energy tax

450.75 241.81 233.75 8.16 113.23-5.75

Finland 410.20 211.08 33.80 31.84 15.30Liquid Fuel tax Liquid Fuel tax Liquid Fuel tax ectricity & Specific Fuel tectricity & Specific Fuel t

Base tax Base tax Base tax Base tax Base tax 374.47 177.85 - - -

Additional Duty (CO2 taxAdditional Duty (CO2 taxAdditional Duty (CO2 taxAdditional Duty (CO2 taxAdditional Duty (CO2 tax)31.27 31.20 32.39 31.09 14.69

Strategic Storage tax Strategic Storage tax Strategic Storage tax Strategic Storage tax Strategic Storage tax4.45 2.03 1.42 0.75 0.61

Denmark 364.63 240.62 164.42 143.92 223.51Mineral Oil Tax Mineral Oil Tax Mineral Oil Tax Coal tax Natural Gas Tax

344.92 221.32 144.53 125.12 203.75CO2 tax CO2 tax CO2 tax CO2 tax CO2 tax19.71 19.29 19.90 18.80 19.75

EU Direction 234.87 175.12 7.57 2.52 4.47(Source) Ministry of Environment, Japan (Note) Exchange rate : 1 USD=106 JPY, 1UK Pound=210JPY, 1Euro=161JPY, 1 Denmark Krone = 0.208 USD

Table 12.2-3 Energy tax rate per 1 ton of CO2 emission in Japan and European countries


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Short -term

Long -term

(as of 1995） (1year) (7-8 year) (year) (year)Industry 0.4841 -0.054 -0.534 0-13 5.1 1978-2003Household 0.1460 -0.252 -0.380 0-10 3.5 1978-2003Commercial 0.1228 -0.144 -0.390 0-12 4.9 1978-2003Passenger transportation 0.1545 -0.097 -0.435 0-13 5.3 1978-2003Cargo transportation 0.0925 -0.097 -0.393 0-14 5.0 1979-2003Total 1.0000 -0.105 -0.467(Source) Central Environmental Council, Discussion paper (2005, Aug), Ministry of Environment, Japan

SectorRespons

e timeAverage

lag Study period

Price ElasticityWeight

<Function of Carbon Tax> The carbon tax is reported to have various functions, such as its price disincentive

function, its function in generating revenue and its function in communicating the government’s seriousness in dealing with climate change. The price disincentive function operates by increasing fuel prices and discouraging their use. This function will improve energy efficiency and reduce carbon dioxide emissions. The revenue generating function increases tax revenue for the government that can be earmarked to address the global warming issue. Finally, the communication function operates to encourage citizens to recognize the importance of the global warming issue and to begin to address their role it.

Regarding the price disincentive function, which is deemed to be the most important,

several investigations of the price elasticity of energy consumption show that a rise in energy prices suppresses energy consumption. Table 12.2-4 refers to a study9 on the price elasticity of energy consumption in Japan and shows that a 1% energy price increase leads to a 0.1% decrease in energy consumption within one year and to a 0.5% decrease within 7-8 years in all sectors. This implies that the tax suppresses energy consumption over the short-term mainly by curbing fuel use, and over the long-term by encouraging the use of high-efficiency energy-saving equipment.

Table 12.2-4 Price elasticity of energy consumption in Japan

Regarding the revenue generating function, environment-related tax revenues in

Denmark and Holland are equivalent to about 4-5% of GDP and account for about 10% of total tax revenue according to OECD statistics. The average environment-related tax revenue for the OECD countries is 1.8% of GDP and accounts for 5.8% of the total tax revenue.

9 Materials presented by the Special Technical Committee on “Green taxes and their Economics Analysis”, the Central Environment Council, Ministry of Environment, Japan (August, 2005)


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Table 12.2-5 Environment-related tax revenues

<Carbon Tax Design> In designing a carbon tax scheme, there are several factors to consider, such as tax objectives, taxable fuels, taxation points (taxpayers), tax rates, tax relief measures, tax usage, the CO2 emissions reduction effect, the impact on the domestic economy, the relationship with existing energy taxes, and so on. It is important to consider taxation points, for example, because although it is easy and efficient for tax collectors to collect the tax at the outlets of factories/warehouses (taxing producers/importers of fuels), it is more effective for reducing CO2 emission to tax at the sales points (taxing consumers). Some issues requiring discussion in designing a carbon tax are shown in Table 12.2-6. In this section, a carbon tax scheme is designed as an example: the taxation objective is to reduce CO2 emissions, the taxable fuels are coal, oil and natural gas, and the taxation point is at the outlet of factories/warehouses. Regarding tax revenue, two cases are discussed; in the first a carbon tax is introduced on top of the existing tax system (additional tax case), and in the other a carbon tax is introduced, but corporate income tax is reduced by a certain amount so that the total governmental tax revenue is the same, thereby eliminating any additional tax burden on the economy (tax-revenue neutral case) (Table 12.2-6).

Carbon tax rates vary considerably, being 31.09 USD/ton-CO2 in Finland, 18.80 USD/ton-CO2 in Denmark, and 6.55 USD/ton-CO2 in a tentative plan of the Japanese Ministry of Environment (Table 12.2-7). The impact of this rate on the price of coal (with a 6,400 kcal/kg calorific value base) raises the price of coal by 74.9 USD/ton-coal in Finland, 45.3 USD/ton-coal in Denmark, and 18.0 USD/ton-coal in the plan of the Japanese Ministry of Environment. Considering this range of rates, the tax rate is set at 20 USD/ton-CO2 in this Study. This tax is imposed on coal, oil and natural gas. The tax rate for each fuel is calculated from the

(as of 2004)Percent of

GDPPercent of tax

revenue(%） (%)

Denmark 4.8 9.8Holland 3.6 9.5Finland 3.3 7.4Italy 3.0 7.2U.K. 2.6 7.3Germany 2.5 7.3France 2.1 4.9Japan 1.7 6.4Canada 1.2 3.7U.S.A. 0.9 3.5OECD average 1.8 5.8(Source) Ministry of Environment, Japan


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USD/ton CO2 USD/ ton Coal RemarksJapan (MOE proposal) 6.55 18 2,400 JPY/ton-carbon, 6,500kcal/kg baseFinland 31.09 74.91 (Source) Japan Ministry of EnvironmentDenmark 18.80 45.28 - ditto -

carbon dioxide emissions for each fuel and is 44.8 USD/ton for coal, 1.18 USD/MMBTU for natural gas, and 9.0 USD/barrel for oil. This tax rate increases current fuel prices by 49.8% for coal, 19.7% for natural gas, and 9.0% for oil (Table 12.2-8).

Indonesia consumed 46,672 KTOE of coal, 38,352 KTOE of natural gas, and 58,306

KTOE of oil in 200610. Based on this consumption, the carbon tax revenue is estimated as 84,151 billion IDR. This amount corresponds to 39.4% of income tax revenue (corporate income tax and personal income tax combined), which was 213,698 billion IDR in 2006. As such, a huge increase in tax revenue is anticipated.

Table 12.2-6 Factors to consider in designing carbon tax

Factors Discussions Tax designed in this Study Objectives To address the global warming issue? or

To increase governmental tax revenue? To address the global warming issue

Taxable fuels Fossil fuels (Primary energy) only? or Is electricity (secondary energy) taxed?

Fossil fuels only

Taxation points （Taxpayer）

The outlets of factories/warehouses (Producers/importers of fuels)? or Sales points (Consumers)?

Taxing outlets of factories/warehouses is easy and efficient

Tax rates High tax rate? or Low tax rate?

20 USD/CO2-ton (this is the rate in Denmark)

Tax relief Do some industrial sectors, SMEs and/or low-income citizens that may suffer severely receive any tax relief or not?

Two cases are discussed. - Additional tax case - Tax-revenue neutral case

Use of tax revenue

For general use, or earmarked for global warming issue?

For general use

Tax revenue neutral

Additional tax? or Tax-revenue neutral?

Two cases are discussed. - Additional tax case - Tax-revenue neutral case

Table 12.2-7 Carbon tax rate

10 According to the Institute of Energy and Economics, Japan, “Energy Matrix” data.


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11.9

11.011.5

10.4

8.28.8 9.3

9.9

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

NoCarbon

Tax

5 $/ton 10 $/ton 15 $/ton 20 $/ton 25 $/ton 30 $/ton

Carbon Tax

Sellin

g Pr

ice

(c$/

kWh)

Coal Power Plant Selling Price (Bench Mark)

Geothermal Power Plant Selling Price

Fuel Unit Coal N' gas Oil Remarks / Data SourceBasic Fuel Price $/ton $/MMBTU $/bbl

90 6.0 100 aFuel Heat Value kcal/kg kcal/BTU kcal/L

5,300 0.252 9,200 b Unit Fuel Price US$/Gcal 17.0 23.8 68.4 c

CO2 Emission Factor kg CO2/GJ 101.0 56.1 73.3 d 2006 IPCC guideline ditto kg CO2/kWh 0.957 0.421 0.695 e - ditto -

CO2 Tax $/CO2-ton 20 20 20 f Assumption ditto $/Gcal 8.46 4.70 6.14 g = f*d/(238.8kcal/MJ) ditto $/TOE 84.6 47.0 61.4 h 1 TOE=10^7 kcal

$/ton $/MMBTU $/bbl ditto $/unit 44.8 1.18 9.0 I = g*bCO2 Tax / Fuel Price % 49.8% 19.7% 9.0% j = i/a (g/c)

Domestic FuelConsumption (2006) KTOE 46,672 38,352 58,306

k IEEJ Energy BalanceMatrix

CO2 Tax million $ 3,948 1,802 3,579 l ditto billion IDR 35,611 16,254 32,286 m 1 USD=9020 IDRCO2 Tax total billion IDR n sum of mIncome Tax revenue(2006) billion IDR 0 Statistical Year Book 2008

CO2 tax ratio p = n/o

84,151

213,69839.4%

Table12.2-8 Design of carbon tax and estimated tax revenue <Effect of Carbon Tax>

When the above-mentioned carbon tax is introduced, the coal price will increase by 49.8%, reaching 134.8 USD/ton. This will increase the selling price of coal-fired electricity to 10.4 USD Cents/kWh. Fig. 12.2-2 shows the simulation results of the effect of various rates of carbon tax on the selling price of coal-fired electricity. When the carbon tax rate is USD 10 per 1 ton of CO2, the selling price of coal-fired plant rises to 9.3 USD Cents/kWh, which is 1.1 USD Cents/kWh higher than the no-tax case. This shows that each 10 USD of carbon tax on 1 ton of CO2 has the effect of adding 1.1 USD Cents/kWh to the selling price of coal-fired energy. From the standpoint of geothermal energy promotion, a carbon tax of 30 USD/ton-CO2 is preferable, since it largely eliminates the price gap between geothermal and coal-fired power. When this strong a carbon tax is imposed, the price gap will disappear and geothermal energy development will be activated automatically. Fig. 12.2-3 shows the

Fig. 12.2-2 Effect of carbon tax （2012-2016）


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0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

Year

Sel

ling

Pric

e (c

$/kW

h)

Geothermal PP Selling Price (Weak Cost Reduction Case)

Geothermal PP Selling Price (Strong Cost Reduction Case)

Coal PP Selling Price (No Carbon Tax)

Coal PP Selling Price (10$/ton Carbon Tax)

Coal PP Selling Price (20$/ton Carbon Tax)

long-term influence of the carbon tax on the selling price of coal-fired electricity.

Fig. 12.2-3 Long-term effect of carbon tax

<Influence of Carbon Tax >

This section discusses the influence of above-mentioned carbon tax on the Indonesian national economy once it is introduced. It is easily understood that the carbon tax will cause an increase in fuel prices and that these price increases will spread to all commodity prices through inter-industry relationships. This price hike infection is analyzed by using the Input-Output Table (47 sectors), as in Chapter 7. The price analysis uses the relations in the vertical direction (column) of the Input-Output Table. Specifically, the following equation can be formed for the column of each industry.

pvpAd =+ (12.1) Where,

ｐ：A row vector comprised of each price (pj) of the j-th industry (a row vector of 47 columns)

Ad：Domestic input coefficients (matrix of 47 rows and 47 columns) v ：A row vector comprised of each value-added ratio of the j-th industry. (a row

vector of 47 columns)

From the formula (12.1), p can be obtained as follows. (I is an unit matrix.)

1)( −−= dAIvp (12.2)

Therefore, when a carbon tax is imposed, the new price structure can be obtained by


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multiplying the new value-added ratio vector to the inverse matrix of (I-Ad)-1 (Leontiev’s inverse matrix) from the left side. As the carbon tax is assumed to be levied on the fossil fuel producers , the carbon tax is levied only on the coal and mineral ore mining sector (sector number 24) and the crude oil, natural gas and geothermal mining sector (25). The coal and mineral ore mining sector pay 25.8% more tax than now, and the crude oil, natural gas and geothermal sector pay 22.7% more tax following the introduction of the carbon tax. The new value-added ratio vector is obtained by changing the components for these two sectors in the current value-added ratio vector.

Table 12.2-9 shows the changes in the value-added ratio for each industry when the

carbon tax is imposed and the price increases for each industry which is affected by the tax11. The industries which are greatly affected are the coal and mineral ore mining sector (24) and the crude oil, natural gas and geothermal mining sector (25), on which the carbon tax is directly levied. The price increase for the coal and mineral ore mining sector is 28.7%, and that for the crude oil, natural gas and geothermal mining sector is 25.9%. Affected by these price increases, the prices of a manufacturer in the nonferrous basic metal sector (46) increase by 17.5%. This is followed by the 13.1% increase for a manufacturer of fertilizer and pesticides (39), the 10.3% increase for a petroleum refinery (41) and the 9.9% increase for a manufacturer of chemicals (40). The price increase for the electric, gas and water supply sector (51) is 8.2%. It is learned that the basic material industries, which have a large energy consumption, are seriously affected and the prices of their commodities increase considerably (Fig. 12.2-4). As a result, the producer price index, which aggregates all industrial prices in consideration of each industry’s production weight, is calculated to rise by 5.2%. The consumer price index, which aggregates all industrial prices in consideration of each industry’s sales weight, is calculated to increase by 1.7%.

Next, in order to minimize the influence of the carbon tax, another case is analyzed

where the carbon tax is imposed on one hand but income tax is reduced on the other, so that the total tax revenue of the government remains same. As already mentioned, the revenue from income tax in Indonesia in 2006 was 213,698 billion IDR, and the revenue from the carbon tax, if it had been applied in 2006, would correspond to 39.4% of the income tax revenue of that year. Therefore, the tax-revenue neutral case is analyzed on the basis of the income tax of each industry sector being reduced by an equal 39.4%, while the carbon tax is levied in the same way as for the previous case (the carbon tax is levied only on the coal and mineral ore mining sector and the crude oil, natural gas and geothermal mining sector.) With this tax adjustment, a new value-added ratio vector is obtained, as shown in Table 12.2-10. Based on this new vector, a new price structure is calculated from formula (12.2), and the results are shown in Table 12.2-10 and Fig. 12.2-5. In the new price structure, prices increase for fifteen industries, such as coal and mineral ore mining (24), crude oil, natural gas and geothermal mining (25), the manufacture

11 For convenience of display, the value-added ratio vector is shown as a column vector, but is actually a raw vector.


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of nonferrous basic materials (46), the manufacture of fertilizer and pesticide (39), electricity, gas and water supply (51) and so on, while prices decrease for other sectors due to the reduction in the income tax. As a result, the producer price index rises by 2.2% while the consumer price index drops by 1.2%.

<Conclusions concerning the Carbon Tax> It is forecast that the carbon tax will have a serious impact on the national economy. If

the tax is designed to be neutral in terms of total governmental tax revenue, this impact will be reduced to some extent. However, the residual impact can be observed on the national economy is by no means small. This study’s conclusion concerning the carbon tax scheme can be summarized as follows: it is an extremely strong incentive for geothermal projects, but it has serious effect on the national economy and therefore should be considered carefully.


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NO. Sector

valueaddedratio(diff.)

PriceIncrease Rank

1 Agriculture 1.1% 302 Livestock 0.4% 443 Forest 0.5% 43

23 Fishery 0.5% 4224 Coal and metal ore mining 0.2588 28.7% 125 Crude oil, natural gas and geothermal mining 0.2274 25.9% 226 Other mining and quarrying 0.8% 3727 Manufacture of food processing and preserving 0.8% 3928 Manufacture of oil and fat 0.6% 4129 Rice milling 0.9% 3530 Manufacture of flour, all kinds 0.8% 3631 Sugar factory 1.2% 2932 Manufacture of other food products 1.0% 3233 Manufacture of beverages 1.2% 2634 Manufacture of cigarettes 0.8% 3835 Yarn spinning 3.8% 1336 Manufacture of textile, wearing apparel and leather 2.2% 2137 Manufacture of bamboo, wood and rattan products 1.4% 2438 Manufacture of paper, paper products and cardboard 2.3% 2039 Manufacture of fertilizer and pesticide 13.1% 440 Manufacture of chemicals 9.9% 641 Petroleum refinery 10.3% 542 Manufacture of rubber and plastic wares 4.8% 1143 Manufacture of non metallic mineral products 2.7% 1644 Manufacture of cement 8.5% 845 Manufacture of basic iron and steel 9.0% 746 Manufacture of nonferrous basic metal 17.5% 347 Manufacture of fabricated metal products 4.8% 1048 Manufacture of machine, electrical machinery and apparatus 2.4% 1949 Manufacture of transport equipment and its repair 1.7% 2250 Manufacture of other products not elsewhere classified 4.3% 1251 Electricity, gas and water supply 8.2% 952 Construction 2.7% 1753 Trade 0.7% 4054 Restaurant and hotel 0.9% 3455 Railway transport 2.7% 1856 Road transport 3.4% 1457 Water transport 2.9% 1558 Air transport 1.0% 3359 Services allied to transport 0.4% 4760 Communication 0.4% 4561 Financial intermediaries 0.4% 4662 Real estate and business service 1.0% 3163 Generaｌ government and defense 1.3% 2564 Social and community, services 1.2% 2865 Other services 1.2% 2766 Unspecified sector 1.4% 23

Table 12.2-9 Carbon tax impact on the value-added ratio and prices for each industry


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0% 5% 10% 15% 20% 25% 30%

Agriculture

Livestock

Forest

Fishery

Coal and metal ore mining

Crude oil, natural gas and geothermal mining

Other mining and quarrying

Manufacture of food processing and preserving

Manufacture of oil and fat

Rice milling

Manufacture of flour, all kinds

Sugar factory

Manufacture of other food products

Manufacture of beverages

Manufacture of cigarettes

Yarn spinning

Manufacture of textile, wearing apparel and leather

Manufacture of bamboo, wood and rattan products

Manufacture of paper, paper products and cardboard

Manufacture of fertilizer and pesticide

Manufacture of chemicals

Petroleum refinery

Manufacture of rubber and plastic wares

Manufacture of non metallic mineral products

Manufacture of cement

Manufacture of basic iron and steel

Manufacture of nonferrous basic metal

Manufacture of fabricated metal products

Manufacture of machine, electrical machinery and apparatus

Manufacture of transport equipment and its repair

Manufacture of other products not elsewhere classified

Electricity, gas and water supply

Construction

Trade

Restaurant and hotel

Railway transport

Road transport

Water transport

Air transport

Services allied to transport

Communication

Financial intermediaries

Real estate and business service

Generaｌ government and defense

Social and community, services

Other services

Unspecified sector

Price Increase (%)

Fig. 12.2-4 Carbon tax impact on prices for each industry


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NO. Sector

valueaddedratio(diff.)

PriceIncrease Rank

1 Agriculture -0.0249 -2.1% 362 Livestock -0.0176 -2.7% 463 Forest -0.0250 -2.5% 43

23 Fishery -0.0260 -2.6% 4524 Coal and metal ore mining 0.2369 25.8% 125 Crude oil, natural gas and geothermal mining 0.2008 22.8% 226 Other mining and quarrying -0.0229 -2.1% 3527 Manufacture of food processing and preserving -0.0092 -2.2% 3928 Manufacture of oil and fat -0.0108 -2.5% 4229 Rice milling -0.0062 -2.2% 3830 Manufacture of flour, all kinds -0.0089 -2.3% 4131 Sugar factory -0.0072 -1.8% 3132 Manufacture of other food products -0.0092 -2.0% 3333 Manufacture of beverages -0.0081 -1.5% 2434 Manufacture of cigarettes -0.0072 -1.0% 2235 Yarn spinning -0.0084 0.9% 1336 Manufacture of textile, wearing apparel and leather -0.0108 -0.7% 2137 Manufacture of bamboo, wood and rattan products -0.0120 -1.5% 2538 Manufacture of paper, paper products and cardboard -0.0106 -0.7% 2039 Manufacture of fertilizer and pesticide -0.0144 9.6% 440 Manufacture of chemicals -0.0075 7.1% 541 Petroleum refinery -0.0243 6.6% 642 Manufacture of rubber and plastic wares -0.0076 1.9% 1143 Manufacture of non metallic mineral products -0.0120 0.0% 1744 Manufacture of cement -0.0108 5.7% 845 Manufacture of basic iron and steel -0.0067 6.1% 746 Manufacture of nonferrous basic metal -0.0061 14.6% 347 Manufacture of fabricated metal products -0.0106 2.0% 1048 Manufacture of machine, electrical machinery and apparatus -0.0086 -0.4% 1949 Manufacture of transport equipment and its repair -0.0114 -1.1% 2350 Manufacture of other products not elsewhere classified -0.0092 1.4% 1251 Electricity, gas and water supply -0.0083 5.1% 952 Construction -0.0104 -0.2% 1853 Trade -0.0172 -2.2% 3754 Restaurant and hotel -0.0160 -2.0% 3455 Railway transport -0.0078 0.0% 1656 Road transport -0.0066 0.5% 1457 Water transport -0.0069 0.1% 1558 Air transport -0.0142 -1.7% 2859 Services allied to transport -0.0198 -2.2% 4060 Communication -0.0205 -2.7% 4761 Financial intermediaries -0.0232 -2.6% 4462 Real estate and business service -0.0165 -1.9% 3263 Generaｌ government and defense -0.0163 -1.6% 2664 Social and community, services -0.0160 -1.7% 3065 Other services -0.0142 -1.7% 2766 Unspecified sector -0.0172 -1.7% 29

Table 12.2-10 Carbon tax impact on the value-added ratio and prices for each industry (Tax revenue-neutral case)


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-5% 0% 5% 10% 15% 20% 25% 30%

Agriculture

Livestock

Forest

Fishery

Coal and metal ore mining

Crude oil, natural gas and geothermal mining


Manufacture of food processing and preserving

Manufacture of oil and fat

Rice milling

Manufacture of flour, all kinds

Sugar factory

Manufacture of other food products


Manufacture of cigarettes

Yarn spinning

Manufacture of textile, wearing apparel and leather

Manufacture of bamboo, wood and rattan products

Manufacture of paper, paper products and cardboard

Manufacture of fertilizer and pesticide

Manufacture of chemicals

Petroleum refinery

Manufacture of rubber and plastic wares

Manufacture of non metallic mineral products


Manufacture of basic iron and steel

Manufacture of nonferrous basic metal

Manufacture of fabricated metal products

Manufacture of machine, electrical machinery and apparatus

Manufacture of transport equipment and its repair

Manufacture of other products not elsewhere classified

Electricity, gas and water supply

Construction

Trade

Restaurant and hotel

Railway transport

Road transport

Water transport

Air transport

Services allied to transport

Communication

Financial intermediaries


Generaｌ government and defense

Social and community, services

Other services

Unspecified sector

Price Increase (%)

Fig. 12.2-5 Carbon tax impact on prices for each industry (Tax revenue-neutral case)


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1 2 25 36 41 48 49 52 53 55 61 62 65

Agriculture,Forestry &Fisheryindustry

Nationalproduction ratio

100%

50%

0%

Miningindustry

Natural resourcerelated industry

Capitalintensiveindustry

Mechanicalprocessingindustry Service industry

Production share of each industry sector (No. is industry sector's number.)

12.3 Localization of Geothermal Technology This section discusses the localization of geothermal technology as a third method to

promote long-term geothermal development in addition to the CDM and the carbon tax scheme. The economic structure of Indonesia is reported to be steadily industrializing, in spite of the economic crisis of the late 1990s12. However, the national production ratio, or the local content ratio, of each industry calculated from the Input-Output table of 2005 shows that most of these ratios for the agriculture, forestry and fishery industry, natural resource-related industry, and the service industry roughly exceed 90%, but many of the ratios seen in the mining industry, such as crude oil, natural gas and geothermal mining (sector number 25), in capital-intensive industries, such as chemical manufacturing (40), petroleum refining (41) and steel manufacturing (45), and in the mechanical processing industry, such as machine and electric machine manufacturing (48) and transport equipment manufacturing (49) still remain in the range of 60-80%. The average of national production ratios for all industry in Indonesia is 87.1%. It is necessary for Indonesia to increase these ratios further to enhance its industrial structure.

(Note) National production ratio = Domestic production amount / (Domestic production amount + Import amount)

（Source）Adapted from Indonesia Input Output Table (2005) by Study Team

Fig.12.3-1 National production ratio for each industry in Indonesia (2005)

12 Satoh Yuri, Economic Restructuring of Indonesia, Asia Economic Research Institute (2004)


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The national production ratio specifies the amount of production in an industry that is

attributable to domestic companies, and is an index of the degree of the “Localization of Technology”. In this Study, the term “Localization of Technology” includes:

1) The transfer of technology and/or knowledge to host-country citizens and its localization, 2) Building the capacity of local companies, 3) Creation of local jobs, and 4) Development and growth of the local economy.

<Experience and Lessons Learned in Technology Localization Efforts in the Oil Production Industry in Indonesia>

First, let us review the experience and lessons learned in the effort to increase technology localization in the oil production industry, which is similar in many respects to the geothermal industry. In Indonesia, local content policies and rules are contained in a variety of different documents, beginning with what was merely a provision in the first petroleum contracts after independence, namely Contracts of Works (CoW) between the state companies (PERMINA, PERTAMIN and PERMIGAN) and the International Oil Companies (IOCs, namely subsidiaries of Exxon/Mobil, Chevron/Texaco, Shell and Pan-American Oil Company). The local content requirements in the CoWs contain a detailed clause specifically dealing with promotion of the national interest (Article 16) and employment and training of nationals (Article 18).

For example, under Article 16 of the standard CoW, the company agrees that in its

operations it will at all times give full consideration to the welfare of the people of Indonesia and to the economic development of the nation, and that it will cooperate with the Government in promoting the growth and development of the Indonesian economy and social structure by assisting in making available information and technical data relating to its enterprise. For the purpose of its operations, as well as for the personal use of employees, the company agrees to give priority to the utilization of goods produced domestically, as long as conditions of design, quality, price and delivery date are equal,. Likewise, under Article 18 the company agrees to ensure priority employment for adequately qualified national personnel at all levels of its organization and to train such personnel to enable them to qualify for any position relating to petroleum operations. These two provisions were later adopted in subsequent petroleum contracts, in the form of the Production Sharing Contract.

In the documents mentioned above, “local content” refers to the development of local

skills, technological transfer, and use of local manpower and local manufacturing. It has become an increasingly important issue that could support Indonesia’s effort to upgrade her manpower capacity, with results that benefit the government, private companies and the


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Indonesia’s economy. However, in spite of this early start, the implementation of this mission has been a mix of successes and failures. The national petroleum service industry has grown relatively slowly in Indonesia as compared to relative newcomers such as Norway, the United Kingdom and Malaysia.

Prompted by the mixed results to that date and guided by a People Congress' Decree,

in the third Five Year Development Plan (1979 – 1984), the Government of Indonesia decided to promote increased use of domestic facilities, services and supplies. The commitment to stimulate and increase local content was expressed in various policies and regulations. One of them is KEPPRES 14A (Presidential Decree 14A) on providing preferential treatment to economically weak groups in procuring products and services. To ensure compliance with the decree, the Government established a bid review procedure. A procurement review team was formed in the State Secretary’s Office & the Ministry to review the awarding of contracts. In the process of review, the team made it a practice to negotiate with winning bidders for even lower prices.

PD14A was originally intended to apply to government agencies and state-owned

companies, but it was later applied to oil company capital purchases as well as the purchase of services. The Government and PERTAMINA justified these policies and procedures on national development grounds. In general, the Production Sharing Contractors did not object to the promotion itself of domestic facilities, supplies, etc., but more to the procedures that they were required to follow. The layers of approvals and sequences of negotiations for lower prices have contributed to substantial delays in the award of contracts, which has in turn affected drilling programs, exploration efforts, and capital development programs.

As a result, the total exploration and development expenditures of the PS Contractors

continued to decline. One long-term effect was the reduction of Indonesia's ability to maintain its high production when crude prices plunged in the late 1980’s. Recognizing the adverse impact, the government responded by providing additional economic incentives, including streamlining the approval system. This included revising the delegation of authority and raising the permissible level of expenditure of the PSC for procurement of non-domestic materials and services, while preserving management control by PERTAMINA through budgeting and auditing processes.

In a further response to demands from industry, streamlining of the approval process

continued through subsequent decrees, including the Presidential Decree that was issued in February 2000 (Presidential Decree No. 18/2000). Under this decree, the permissible level of expenditure of the PSC for foreign procurement was again raised and the requirement to obtain approval from the State Secretary and Ministry was abolished. Therefore final approval in awarding contracts now lies essentially with PERTAMINA and the contractors themselves.


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In response to these Presidential Decrees, many domestic service companies were

established in the 1970s and 1980s. Many have successfully taken the opportunities opened up by the government policy, but the overall results are still below expectations, particularly in the field of high or specialized technology. Many of the service supply companies are merely serving as local outlets for global distribution and marketing networks. As a result, in 2000 Indonesia has managed to achieve about 25% local content, while other countries such as Malaysia, Brazil and Mexico have performed much better. (Table 12.3-1)

Table 12.3-1 Local content in supplies to upstream oil and gas activity

Country Local Content (in 2000) GDP per Capita

Brazil 70% US$ 4,280

Malaysia 70% US$ 5,759

Mexico 100% US$ 7,180

Nigeria 5% (increased to 30% in 2007) US$ 803

Indonesia 25% (increased to 35% in 2007) US$ 1,203

(Source: PEN Consultant Co.)

The local content regulation is a double-edged sword. It provides local suppliers with a

good business opportunity, but on the other hand, it discourages international investors if the regulations are implemented inappropriately. The experience of many countries shows that inappropriately enforced local content policy may impede economic growth; these include consuming wealth rather than creating value, creating delays, risk of permanent protectionism, and corruption and red tape. In addition, as the world is now more open and competitive, new international regulatory bodies have acquired influence over decisions, as shown by the fact that “local content” has become an issue in world trade talks. More holistic and careful thought is required to strike the right balance between national and international ownership of projects. <Example of Localization of Technology in the Motorcycle Industry>

Next, let us review the example of localization of technology in motorcycle industry, which has been deemed a success story. In many South Asian countries including Indonesia, the manufacture of motorcycles and four-wheel vehicles is thriving now, with successful localization of technology and localization of production. Let's consider the localization process in the motorcycle industry. A Japanese study 13 describes the advancing localization of

13 Mishima Kouhei, “A study on procurement patterns of Japanese motorcycle manufacturers in Thailand,


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technology in Thailand and Indonesia in the following terms: The first stage of localization was the stage of Complete Knock-Down (CKD)

production, which is thought to have started in 1967 in Thailand and in 1978 in Indonesia, when Honda Co. began production in both countries. The roughly ten years from that point are considered as the first-stage period, which continued until regulations mandating local procurement became stronger. Production in this first-stage period was about 100,000 units in Thailand and 300,000 in Indonesia. Almost all the parts were imported at this stage, and the manufacturers were specialized in the final assembly of CDK kits. A limited number of parts-suppliers invested in both countries to supply simple and heavy parts such as tires or batteries.

In the second-stage period, manufacturers began to produce some parts in their

factories which had previously been imported, and increased the local content ratio. The roughly ten years from around 1978 to the second half of the 1980s corresponded to this stage in both Thailand and Indonesia. Production in this period was about 300,000 units in each of the two countries. The local content ratio was about 70%. However, the rise in local content was mainly due to an increase in in-house production by the manufacturers and was not due to an increase in the number of parts suppliers.

The third stage was a stage in which the main parts-suppliers such as engine parts

makers began to build their factories in the two countries. The period from around 1990 until the Asian economic crisis of 1997 corresponded to this stage in Thailand and in Indonesia. The number of local parts suppliers increased during this stage. Production in this stage rose to about 500,000 units in each country, and the local content ratio increased to about 90%. As the number of local parts suppliers increased, the import of knock-down kits almost disappeared.

The fourth stage is a stage in which a lot of suppliers of almost all types of parts are

willing to invest locally. Production exceeds 1 million units in each country, and the local content ratio has come to exceed 90%. This is the stage in which not only parts manufacturers but also their subcontractors (the secondary suppliers) have begun to invest locally. As a result, an extremely thick layer of suppliers has been formed. On the other hand, differences in QCD (Quality/Cost/Delivery) have disappeared, and severe cost competition prevails. In Thailand, the industry has reached this stage. A rich cluster of suppliers has been formed, and has become a source of further cost competition. Indonesia is just entering this stage now.

In Thailand, the industry is now advancing to the final stage of technology

localization , i.e. the localization of research and development activity. Strong cost competition

Indonesia and Vietnam”, Vietnam Development Forum (2004)


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is driving research and development activities in Thailand. A great fall in the price of products of 30% or more has been achieved in Thailand since around 2000 as localization has matured. These falling prices were realized not only by the intensification of competition, but also by the emergence of a greater number of suppliers. Since the cost of materials occupies a large portion of their production costs, the parts makers responded to falling prices by raising the productive efficiency of machines and workers. This effort spillled over into the improvement of production management. Moreover, Value Engineering (VE) proposals were made, and a variety of new devices was invented to satisfy local market requirements. For instance, the width of tires was reduced and this decreased the amount of raw material necessary for their construction. Here we can see the same business model that is common in Japan whereby cost reductions are achieved through cooperation between a final product maker (assembler) and parts makers (suppliers) to jointly develop products and manage their quality from the design stage. This is the effect of the accumulation of industries. In this way, the localization of technology and the accumulation of industry can lead to a cycle of in which “establishment of mass production technology” leads to “establishment of production ability with stable quality” leads to “cost reduction with maintenance of quality”. This stage is expected to be reached sooner or later in Indonesia, where the localization of technology is advancing.

Table 12.3-2 Process of Technology Localization in the motorcycle industry in Thailand and Indonesia

Localization Stage Thailand Indonesia The 1st stage: Complete Knock-Down production

Period: 1967～1978 Honda stated production in 1967. Import duty for parts was increased in 1978. Production was around 100,000.

Period: 1971～1978 Honda started production in 1971. Local content regulations were strengthened in 1978. Production was around 300,000.

The 2nd stage: Local content increase through in-house production of parts

Period: 1978～second half of 1980sAssemblers started in-house production of some parts. Production was around 300,000. Local content was around 70%.

Period: 1978～second half of 1980s. Assemblers started in-house production of some parts. Production was around 300,000. Local content was around 70%.

The 3rd stage: Advancing investment by main parts makers

Period: around 1990～1997 Main parts makers began to invest The number of parts suppliers increased. Production was around 500,000. Local content was around 90%.

Period: around 1990～1997 Main parts makers began to invest. The number of parts suppliers increased. Production was around 500,000. Local content was around 90%.

The 4th stage: Thailand is now graduating from Indonesia is now entering into this


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Advancing investment by all kinds of suppliers

this stage. Not only parts makers but also their

secondary suppliers began to invest.

A thick suppliers’ layer was formed. Severe competition to reduce costs spread. Production was around 1 million or more. Local content was more than 90%.

stage. Not only parts makers but also their

secondary suppliers begin to invest. Production is around 1 million or more. Local content is more than 90%.

The 5th stage: Localization of R&D

Thailand is entering into this stage. The final stage of localization. Localization of R&D is carried out.

（Source）Adapted from Mishima Kouhei, “A study on procurement patterns of Japanese motorcycle manufacturers in Thailand, Indonesia and Vietnam”, Vietnam Development Forum (2004) <Existence of a Large Domestic Market as Factor for Success in Technology Localization>

What were the factors driving the success of this technology localization in the motorcycle industry in Thailand and Indonesia? It is true that the enforced local content regulations played an important role in the early stage in encouraging foreign manufacturers to purchase necessary parts from local suppliers as an alternative to the CKD production system. However, it was only a trigger of this process. It can be said that the main factor driving the success of technology localization in the industry is the “existence of a large domestic market”. Both countries have a large population; 63 million in Thailand and 200 million in Indonesia. With economic growth, public demand for motorcycles had expanded rapidly. Faced with this large domestic market, the industry took economically rational actions, and the localization of technology advanced. As a result, localization of production advanced and an accumulation of industries formed. It was not the manufacturers alone that responded to this large market. A loan financing industry started to provide loans so that people could easily access the funds to purchase their motorcycles. A second-hand motorcycle sales business also emerged, enabling more people to purchase them at cheaper prices. The appearance of the second-hand motorcycle sales market had the effect of giving the motorcycle commodity the value of property, and forced manufactures to produce high-quality products. As such, not only the central manufacturers but also the surrounding industries initiated new services and created a large motorcycle industry cluster. This growth cycle again led to the emergence of new products and cost reductions. It is true that the strengthened local content regulations played a certain role in this localization, but it was limited to an initial catalytic function only. The effective governmental role was that it maintained a favorable investment environment for the industry


JICA West JEC 12-37

and was able to convince many people in the industry that the domestic market was large enough to tap. <Localization of Geothermal Technology>

The Study Team hopes that the localization of geothermal technology can proceed in a manner similar to the localization of the motorcycle industry in Indonesia. Localization of technology leads to the localization of production and the accumulation of related industries. It is true that geothermal technology is plant technology and is not a perfect analogy with motorcycle technology which is based on mass production and mass consumption. However, the Study Team believes that there is a possibility of a similar process occurring, in which confidence in the large domestic market attracts investment in the market and eventually forms a strong industry cluster. Through this process, it is hoped that cost reductions in geothermal energy production will be achieved, and that further geothermal fields will be developed. However, our hope is not confined to this. The Study Team further hopes that the geothermal industry will grow to be one of the major industries creating economic value for the country. In the future, it is hoped that the competitiveness of the industry will allow it to advance into overseas markets. As mentioned in Chapter 7, geothermal projects procure more goods and services from the local market and therefore contribute to local economic growth more than conventional fossil fuel power plant projects. Fortunately, the domestic geothermal market is believed to be sufficiently large. By tapping into this huge domestic market, the localization of technology is expected to be realized. Once the geothermal industry has accumulated in Indonesia, a reduction in the costs of geothermal energy can be expected. Once the competitiveness of geothermal has been widely recognized, the spontaneous growth of geothermal development can be expected to proceed at an explosive pace.

Geothermal power plants do not use as high-temperature and high-pressure steam as

coal-fired plants. And though it remains technically challenging, the conditions shown in Table 12.3-2 should make it far easier to nationalize geothermal technology than the technology of coal-fired plants. By increasing the resistance to high temperatures and high pressure of the steam pipes, valves, containers and pumps, gradually the localization of geothermal technology will be realized.

Table 12.3-3 Comparison of steam conditions of geothermal and coal-fired plants Items Coal-fired plant Geothermal plant (*)

Output (MW) 300～1,000 0.5～110 Temperature （deg. C.） 538～600 150～170 Pressure（MPa） 24.5 0.5～0.6 Quantity (t/h) 800～2,900 4～77

(Note) * condensing type geothermal plant


JICA West JEC 12-38

0.0

2.0

4.0

6.0

8.0

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12.0

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2008

2009

2010

2011

2012

2013

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2018

2019

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Base Case10% Cost reduction 20% Cost reductionCoal Price

<Effect of Technology Localization>

There is little data reported regarding how much cost reduction is achieved when a certain technology is localized. Therefore, the Study Team provisionally assumed that a 10 – 20% reduction in construction costs can be expected from current conditions, when technology localization is fully achieved in 2025. Fig. 12.3-1 shows the long-term selling price of geothermal power in the weak cost reduction case, and Fig. 12.3-2 shows that for the strong cost reduction case. There is a possibility that the selling price of geothermal power will be competitive with coal-fired plants around 2024-2025, even in the weak cost reduction case.

Fig. 12.3-2 Long-term effect of technology Fig. 12.3-3 Long-term effect of technology localization localization

(Weak cost reduction case) (Strong cost reduction case）

CHAPTER 13

COST AND BENEFIT ANALYSIS OF

GEOTHERMAL DEVELOPMENT

INCENTIVES


JICA West JEC 13-1

StateCompany

ExistingIPP New IPP sub total

2009 935 9352010 935 9352011 1,100 1,1002012 1,100 300 300 600 1,7002013 1,100 600 600 1,200 2,3002014 1,100 900 900 1,800 2,9002015 1,100 900 900 1,800 2,9002016 1,100 900 900 600 2,400 3,5002017 1,100 900 900 600 2,400 3,5002018 1,100 900 1,200 900 3,000 4,1002019 1,100 1,200 1,200 1,200 3,600 4,7002020 1,100 1,500 1,500 1,200 4,200 5,3002021 1,100 1,500 1,800 1,500 4,800 5,9002022 1,100 1,800 1,800 1,800 5,400 6,5002023 1,100 2,100 2,100 2,400 6,600 7,7002024 1,100 2,400 2,400 2,400 7,200 8,3002025 1,100 2,700 2,700 3,000 8,400 9,500

Year Existing(MW)

Additional (MW) Total(MW)

CHAPTER13 COST AND BENEFIT ANALYSIS OF GEOTHRMAL DEVELOPMENT INCENTIVES

This Chapter discusses the feasibility of three (3) kinds of geothermal development

incentives discussed in Chapter 9, i.e., (i) the Feed-in Tariff incentives, (ii) the Tax Reduction and Feed-in Tariff combination incentives, (iii) the Governmental Geothermal Development Promotion Survey (GDPS) and Feed-in Tariff combination incentives. The feasibility is analyzed by comparing the costs and benefits incurred to the government and the society of each incentive.

13.1 Long-term Geothermal Development Forecast (1) Beneficiary projects of the Feed-in Tariff incentives

In order to carry out this analysis, a geothermal development forecast needs to be defined as a study framework. For this purpose, the Study team has referred “Geothermal Road Map” of MEMR, which aims to achieve 9,500MW by 2025, and the JICA Master Plan Study. From these references, the Study Team has assumed a geothermal development forecast in each year by rounding the figures of the JICA Geothermal Master Plan forecast as shown in Table 13.1-1. Therefore in addition to the currently existing 1,100MW, 8,400MW of new projects are expected to come on line from 2012 to 2025 to achieve the 9,500MW target. In this assumption, the Study Team has broke down the new development capacity into possible contributions of three kinds of players, i.e., State Owned Companies (Pertamina and PT PLN), existing IPP companies and new IPP companies as shown in the same table. This breakdown of each player is also assumed based on the JICA Master Plan Study.

Table 13.1-1 Geothermal development forecast


JICA West JEC 13-2

0

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2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Year

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Year

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(Source) Made by the Study Team referring the “Geothermal Road Map” and the “JICA Master Plan Study”

In the case of the Feed-in Tariff incentives, all new development projects done by IPP companies can enjoy these incentives. Therefore the development projects done by the existing IPPs and the new IPPs shown by the orange color and the light yellow color in Fig. 13.1-1 is the beneficiary projects of this incentives case. The total capacity of the beneficiary projects as of 2025 is 5,400MW.

Fig. 13.1-1 Beneficiary projects of the Feed-in Tariff incentives

(2) Beneficiary projects of the Tax Reduction and Feed-in Tariff combination incentives In the case of the Tax Reduction and Feed-in Tariff combination incentives, all new

development projects done by IPP companies can also enjoy these incentives. Therefore the development projects done by the existing IPPs and the new IPPs shown by the orange color and the light yellow color in Fig. 13.1-1 is the beneficiary projects of this incentives case. The total capacity of the beneficiary projects as of 2025 is 5,400MW.

Fig. 13.1-2 Beneficiary projects of the Tax Reduction and Feed-in Tariff combination incentives

Beneficiary

projects of the

Feed-in Tariff

incentives

Beneficiary projects of theTax Reductionand Feed-in Tariffcombination incentives


JICA West JEC 13-3

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Year

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Existing IPP

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(3) Beneficiary projects of the Governmental Geothermal Development Promotion Survey (GDPS) and Feed-in Tariff combination incentives

In the case of the Governmental Geothermal Development Promotion Survey (GDPS) and Feed-in Tariff combination incentives, the government carries out surveys to confirm up to approximately 40% of required steam and changes the Green Field into the Brown Field so that private IPP companies can participate in the development with less resource risks. In this incentives case, the beneficiary projects are those of new IPP companies which are shown in the new IPP column in Table 13.1-1 and are shown by the light yellow color in Fig. 13.1-3. The total capacity of the beneficiary projects as of 2025 is 3,000MW. Other projects are not eligible for these incentives and therefore are omitted from the beneficiary projects of this incentives case because these projects have been already committed by developers. Fig. 13.1-3 Beneficiary projects of the GDPS and Feed-in Tariff combination incentives

13.2 Feed-in Tariff Incentives (1) Costs and Benefits of the Feed-in Tariff Incentives (a) Costs to Government

In case of the Feed-in Tariff incentives, the government obliges PT PLN to purchase power from geothermal IPPs at a price which enables the IPPs to obtain a certain project return (Feed-in Tariff). To accomplish this, the government will have to supply a subsidy to PT PLN to bridge the gap between the Benchmark price and the Feed-in Tariff. Therefore the amount of subsidy required in a given year is the cost of this incentive. The subsidy amount will be the product of the price gap (USD Cents/kWh) and generated energy (kWh) for the year. If the oil

Beneficiary projects

of the GDPS and

Feed-in Tariff

combination

incentives


JICA West JEC 13-4

price is 100 USD/barrel, the selling price of geothermal energy calculated by the Price Model is 11.9 USD Cents/kWh and the Benchmark price is 8.2 USD Cents/kWh. In addition, accounting for the future price variations discussed in Chapter 10 and Chapter 11, the Study Team has attempted to calculate the required subsidy for each year. (b) Benefits to Government

As discussed in Chapter 7, the Government’s benefits are the sum up of (i) the Fuel

Save Benefit to PT PLN, (ii) Government revenue from Fuel Export Value（tax income at a 32.5% tax rate） and (iii) the Tax and Royalties Value. These benefits are as shown in Table 13.2-1, which shows the case when oil price is 100 USD/barrel. To obtain the total amount of benefits accruing in each year, these benefits are multiplied by the amount of energy generated in a given year. Of the items in the table, note that items other than the Tax & Royalties Value will not be affected by long-term selling price variation. On the other hand, the Tax & Royalties Value will be affected by such variation, and this needs to be considered for long-term development.

Table 13.2-1 Benefits and beneficiaries in geothermal development (USD Cents/kWh)

（Assumed Oil Price 100 USD/barrel, CO2 20 USD/ton）

Value Beneficiary

Energy Value

Fuel Cost Reduction

Value

Fuel Export Value

Tax & Royalties

Value

Environmental Value

Total

PLN 8.2 8.2

Government 0.3 1.9 1.6 3.8

Society 3.9 1.9 5.8

Total 8.2 0.3 5.7 1.6 1.9 17.7

(c) Costs to Society

This Chapter discusses the social impact of development in addition to the impact on government. In discussing the social impact, the costs borne by society are assumed to be equal to those borne by government. (d) Benefits to Society

The benefits to be enjoyed by society are the sum of the above-mentioned government

benefits plus (iv) the remainder of the Fuel Export Value（67.5%）and (v) the Environmental Value（CO2 reduction value）.

The above-mentioned connections are as shown in Fig. 13.2-1.


JICA West JEC 13-5

FIT Scheme (Green Field Development)

Costs

Benefits

Financial Evaluation of Government (FIRR)

Benefits

Economic Evaluation (EIRR)

Government

Price Gap Subsidy

PLN Fuel Cost Reduction value

Fuel Export Value (for Gov't)

Fuel Export Value (for Society)

Tax Value

Environmental value

Fig. 13.2-1 Costs and benefits in the Feed-in Tariff incentives case

(2) Evaluation of the Feed-in Tariff incentives As shown in Table 13.2-1, the government’s benefit is 3.8 USD Cents/kWh when the

oil price is 100 USD/barrel. The annual amount of the government’s total benefit can be calculated by multiplying by 3.8 USD Cents/kWh the amount of annual energy generated at 90% of capacity, as assumed in Fig. 13.1-1. By comparing this benefit with the cost (the amount of the subsidy), government fiscal balance can be sought as shown in Table 13.2-2 and Fig. 13.1-2. Note that each project life is assumed to be 30 years, therefore the evaluation period is up to 2054, when projects commissioned in 2025 end their operation. Also note that the oil price during the said period is assumed to remain at the same level.

Table 13.2-2 and Fig. 13.2-2 indicate that there are the government benefits from 2012 to 2054 while the government costs are required from 2012 to 20391. When the oil price is 100 USD/barrel, the total government costs become USD 20,958 million (Net Present Value2 in 2009 USD is USD 3,490 million.). The annual government costs culminate in USD 1,136 million in 2025 (USD 185 million in NPV). On the other hand the annual government benefits of the same year are USD 1,603 million (USD 262 million in NPV) and there are net benefits of USD 467 million (USD 77 million in NPV). Thus the government fiscal balance remains in the black throughout the period when the oil price stays at 100 USD/barrel. The total net benefits of the government fiscal balance during the period turn out to be USD 27,140 million (USD 1,308 million in NPV). Since the balance remains in surplus throughout the period, the FIRR (Financial Internal Rate of Return) of the government fiscal balance is not available.

1 It is because government costs are necessary for 15 years for the projects which operate between 2012 and 2025. 2 Net present value is converted by using a discount rate of 12%. As for 12%, refer to footnote in page 2-8.

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JICA West JEC 13-7

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

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Year

Ann

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0

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10,000

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60 70 80 90 100 110 120 130 140Oil Price ($/bbl)

Net

Pre

sent

Val

ue (m

$)

FIT (Govt Benefit)

FIT (Social Benefit)

Oil Price($/bbl) FIRR

FIT (GovtBenefit) EIRR

FIT (SocialBenefit)

NPV (m$) NPV (m$)60 - -2,190 + 3,43970 - -1,416 + 4,71180 6.4% -637 + 5,98890 17.9% 397 + 7,512

100 + 1,308 + 8,921110 + 2,213 + 10,325120 + 3,251 + 11,852130 + 4,157 + 13,256140 + 5,056 + 14,654

(Note) - : IRR can not be calculated due to too many negative numbers + : IRR can not be calculated due to too many positive numbers.

Next is the comparison of Social Costs and Benefits. Social Benefits remain far above the Social Costs throughout the period and the total amount of Social net benefits is USD 104,989 million (USD 8,921 million in NPV). Similarly to the FIRR, the EIRR (Economic Internal Rate of Return) is not available since the balance remains in the black all the time. As a result, provided that the oil price stays at 100 USD/barrel, the Feed-in Tariff incentives bring significant benefits both to the government and the society.

Table 13.2-3 and Fig. 13.2-3 show the sensitivity of the governmental and the social benefit to oil price variation. When the oil price comes down, the Benchmark price becomes lower while the selling price of geothermal energy is unaffected. Therefore the amount of subsidy will increase. In addition, a reduction in oil price also reduces the government benefits by decreasing the Fuel Export Value. For example, the government benefits turn negative when the oil price falls below 90 USD/barrel, and if it falls further to 60 USD/barrel, the NPV of the government fiscal balance turns to be minus USD 2,190 million. Even in such a case, however, the social benefit remains significant with USD 3,439 million NPV of benefits. Geothermal development is fruitful for the society even when the government has to bear some burden.

Table 13.2-3 Sensitivity analysis of the Feed-in Tariff incentives

Fig. 13.2-3 Sensitivity analysis of the Feed-in Tariff incentives

Fig.13.2-2 Costs and benefits in the Feed-in Tariffincentives case


JICA West JEC 13-8

13.3 Tax Reduction and Feed-in Tariff Combination Incentives (1) Costs and benefits of the Tax Reduction and Feed-in Tariff combination incentives (a) Costs to Government

As stated in Chapter 8, a geothermal project pays bigger tax than a coal-fired project for every kWh. Therefore Tax Reduction incentives should have a significant influence in promoting geothermal development. This section discusses the impact of the Tax Reduction incentives. As discussed in Chapter 9, the proposed Tax Reduction incentives are 5% corporate tax rate for 15 years after commissioning. However, due to the 10% dividend tax, the total tax rate rises to 14.5%. (It is 32.5% when there is no corporate tax reduction). As stated in Chapter 8, this Tax Reduction incentive reduces the geothermal selling price to 10.9 USD Cents/kWh from 11.9 USD/kWh of the normal case. On the other hand, the Tax Reduction incentive deprives the government of tax income. This income reduction can be considered as a cost to government for implementing the Tax Reduction incentives, which is estimated to be 0.9 USD Cents/kWh. Also, the Tax Reduction incentives alone can not lower the geothermal selling price below the Benchmark price. Therefore the government still has to impose the Feed-in Tariff to compensate this remaining price gap and also has to supply the price gap subsidy to PT PLN, which is also a cost to government. In this case, the compensating Feed-in tariff is less than that of the Feed-in Tariff incentives case of the previous section because there are the Tax Reduction incentives3. However, as long as the compensating Feed-in Tariff is necessary, the government should supply the price gap subsidy to PT PLN and this subsidy also becomes a cost to government. (b) Benefits to Government

The government’s benefits in this case are the same as for the case of the Feed-in Tariff incentives, which are the sum of (i) the Fuel Save Benefit of PT PLN, (ii) Government

revenue from the Fuel Export Value（tax income at a 32.5% tax rate）and (iii) the Tax and Royalties Value. The Tax and Royalties Value will decrease due to tax rate reduction, but this reduction is accounted as a cost increase and not accounted as a benefit decrease. (c) Costs to Society

The costs to society in this case are the sum of the lost tax income and the government subsidy. (d) Benefits to Society

Social benefits include, in addition to the above-mentioned government benefits, (iv)

the reminder of the Fuel Export Value (67.5%) and (v) Environmental Value（CO2 reduction value）.

3 As mentioned in Chapter 8 and Chapter 9, Feed-in Tariff is 11.9 USD Cents/kWh when there is no incentives. It is 10.9 USD Cents/kWh when there is the Tax Reduction incentives.


JICA West JEC 13-9

Tax Reduction Scheme (5% Corporate Tax rate for 15 years) (Green Field Development)

Costs

Benefits


Benefits


Government

Reduction of Tax Income




Tax Value

Environmental value

Price Gap Subsidy

These connections are shown as in Fig. 13.3-1.

Fig. 13.3-1 Costs and benefits in the Tax Reduction and Feed-in Tariff combination incentives case

(2) Evaluation of the Tax Reduction and Feed-in Tariff combination incentives The estimated impact of this incentive case is shown as Table 13.3-1 and Fig. 13.3-2.

Likewise as the case of the Feed-in Tariff incentives case, there are the government benefits from 2012 to 2054 while the government costs are required from 2012 to 2039. When the oil price is 100 USD/barrel, the total government costs become USD 20,242 million (USD 3,389 million in NPV). The annual government costs culminate in USD 1,100 million (USD 179 million in NPV) in 2025. On the other hand the government benefits of the same year are USD 1,603 million (USD 262 million in NPV) and there are net benefits of USD 503 million (USD 83 million in NPV). Thus the government fiscal balance remains in the black throughout the period when the oil price stays at 100 USD/barrel. The total net benefits of the government fiscal balance during the period turn out to be USD 27,856 million (USD 1,408 million in NPV). Since the balance remains in surplus throughout the period, the FIRR (Financial Internal Rate of Return) of the government fiscal balance is not available.

Table 13.3-1 also shows the costs and benefits to society. As stated before, the benefits of geothermal energy to the society are significant and the benefits remain far above the costs at all times. During the assessment period, the total amount of the Social net benefits is USD 105,706 million (USD 9,021 million in NPV). Since the balance of society’s net benefits remains in the black throughout the period, the EIRR for this incentive is not available.

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5.7

1.4

1.9

9.3

3,74

73,

747

7920

444,

800

37,8

430.

00.

00.

00

0.0

00

0.3

1.9

1.4

3.5

1,33

61,

336

250

0.3

5.7

1.4

1.9

9.3

3,52

13,

521

6720

454,

800

37,8

430.

00.

00.

00

0.0

00

0.3

1.9

1.4

3.5

1,33

61,

336

230

0.3

5.7

1.4

1.9

9.3

3,52

13,

521

6020

464,

200

33,1

130.

00.

00.

00

0.0

00

0.3

1.9

1.3

3.5

1,15

71,

157

170

0.3

5.7

1.3

1.9

9.3

3,06

93,

069

4620

474,

200

33,1

130.

00.

00.

00

0.0

00

0.3

1.9

1.3

3.5

1,15

71,

157

160

0.3

5.7

1.3

1.9

9.3

3,06

93,

069

4120

483,

600

28,3

820.

00.

00.

00

0.0

00

0.3

1.9

1.3

3.5

983

983

120

0.3

5.7

1.3

1.9

9.2

2,62

22,

622

3220

493,

300

26,0

170.

00.

00.

00

0.0

00

0.3

1.9

1.3

3.4

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897

100

0.3

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2,39

92,

399

2620

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000

23,6

520.

00.

00.

00

0.0

00

0.3

1.9

1.3

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812

812

80

0.3

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1.3

1.9

9.2

2,17

82,

178

2120

512,

400

18,9

220.

00.

00.

00

0.0

00

0.3

1.9

1.2

3.4

645

645

60

0.3

5.7

1.2

1.9

9.2

1,73

81,

738

1520

522,

100

16,5

560.

00.

00.

00

0.0

00

0.3

1.9

1.2

3.4

562

562

40

0.3

5.7

1.2

1.9

9.2

1,51

81,

518

1220

531,

200

9,46

10.

00.

00.

00

0.0

00

0.3

1.9

1.2

3.4

318

318

20

0.3

5.7

1.2

1.9

9.1

864

864

620

5490

07,

096

0.0

0.0

0.0

00.

00

00.

31.

91.

23.

423

823

81

00.

35.

71.

21.

99.

164

764

74

TOTA

L (N

omin

al)

1,34

8,16

413

,368

6,87

420

,242

48,0

9827

,856

－20

,242

125,

948

105,

706

－TO

TAL

(in 2

009

US

D)

131,

840

2,40

398

63,

389

4,79

71,

408

1,40

83,

389

12,4

109,

021

9,02

1

Soci

al B

enef

itsG

ovt C

osts

G

ovt B

enef

itsC

ash

Flow

Soc

ial C

osts

Tabl

e 13

.3-1

Cos

ts a

nd b

enef

its in

the

Tax

Red

uctio

n an

d Fe

ed-in

Tar

iff c

ombi

natio

n in

cent

ives

cas

e


JICA West JEC 13-11

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

2048

2050

2052

2054

Year

Ann

ual C

osts

/Ben

efits

(m

$)

Govt Benefits (m$)

Govt Cost (m$)

-5,000

0

5,000

10,000

15,000

20,000

60 70 80 90 100 110 120 130 140

Oil Price ($/bbl)

Net

Pre

sent

Val

ue (m

$)

Tax Reduction & FIT (Govt Benefit)

Tax Reduction & FIT (Social Benefit)


TaxReduction

& FIT(Govt EIRR

TaxReduction

& FIT(Social

NPV (m$) NPV (m$)60 - -2,089 + 3,53970 - -1,315 + 4,81280 7.0% -536 + 6,08990 20.1% 498 + 7,612

100 + 1,408 + 9,021110 + 2,314 + 10,425120 + 3,343 + 11,944130 + 4,203 + 13,302140 + 4,983 + 14,581


Fig.13.3-2 Costs and benefits in the Tax Reduction and Feed-in Tariff combination incentives case

Table 13.3-2 and Fig. 13.3-3 show the results of sensitivity analysis of the net benefit

to governmental and society to variation in oil prices. If the oil price goes below 80 USD/barrel, the government fiscal balance will be in deficit and the NPV of the government fiscal balance decreases to minus USD 2,089 million for an oil price of 60 USD/barrel. However, society still enjoys USD 3,539 million NPV of benefits even if the oil price decreases to 60 USD/barrel. Therefore the development of geothermal energy clearly brings benefits to society even though it may be a burden to the government.

Table 13.3-2 Sensitivity analysis of the Tax Reduction and Feed-in Tariff combination incentives Fig. 13.3-3 Sensitivity analysis of the Tax

Reduction and Feed-in Tariff combination incentives


JICA West JEC 13-12

Study period No. offields

20102011 2011-2013 102012 2012-2014 02013 2013-2015 52014 2014-2016 52015 2015-2017 02016 2016-2018 5 6002017 2017-2019 5 02018 2018-2020 10 3002019 2019-2021 0 3002020 2020-2022 10 02021 3002022 3002023 6002024 02025 600Total 50 3,000

Year Additional

MW byNew IPP

GDPSExpenditure

Income

Year -5 -4 -3 -2 -1 1 2 3 ・・・・・・・・ 10

Sales of Survey results

Construction Operation

GDPS FundCosts of GDPS

Repayment of Costs of GDPS

・・・・・・・・・

Private Repayment after Operation(10 year-repayment with 6.5%

interest)

Fund

Survey by Gov't

13.4 Geothermal Development Promotion Survey (GDPS) and Feed-in Tariff combination incentives

(1) Scheme of promotion This section discusses the scheme that aims to turn Green Fields into Brown Fields

through a Geothermal Promotion Development Survey (GDPS) by the government. This scheme assumes the establishment of an independent GDPS Fund separate from the government budget. This Fund is intended to promote the initial surveys necessary for projects that are planned after 2016, as shown as the new IPP portion in Table 13.1-1 and in Fig. 13.1-3, by providing funding for survey costs. Namely the beneficiary projects of this Fund are the development of 3,000 MW until 2025 by private IPP companies. Since the capacity of each project is assumed to be 60 MW, the number of the fields where the GDPS is carried out is 50. It is assumed that the GDPS starts in the fifth year in advance to the scheduled commissioning year and lasts for three years. After the GDPS, it is also assumed that a private IPP company takes over the survey and continues the development to construct geothermal plant during two-year period after the takeover. Fig.13.4-1 shows scheme of this GDPS Fund and Table 13.4-1 shows the implementation plan of the GDPS.

Fig.13.4-1 Scheme of the GDPS Fund

The GDPS costs paid by the Fund shall be repaid by the IPP company. The IPP

company shall repay the GDPS costs over a ten-year period after it starts geothermal plant operation with 6.5% of interest rate. As discussed in Chapter 8, if the initial development is carried out by the government, the resource risks of geothermal projects will be significantly

Table 13.4-1 Implementation plan of GDPS


JICA West JEC 13-13

Geothermal Development Promotion Survey (GDPS) Fund Scheme (Brown Field Development)

Expenditure

Income

Financial Evaluation of Fund 10 year-repayment period with 6.5% interest

Costs

Benefits

Financial Evaluation of Government (FIRR)Benefits


Government

Price Gap Subsidy




Tax Value

Environmental value



Fig. 13.4-2 Costs and benefits in the GDPS and Feed-in Tariff combination incentives case

reduced. As a result, IPP companies are willing to take over development even though they have to purchase the GDPS results at a certain price. Also, thanks to the reduced risks, the selling price of the IPP company’s geothermal energy will be reduced as well. However, it is estimated that the selling price of geothermal energy will still be slightly higher than the Benchmark price, and therefore the government will have to impose the Feed-in Tariff to compensate this remaining price gap and also will have to provide a price gap subsidy to PT PLN. This subsidy shall be borne by the government, not by the GDPS Fund. The relation between the GDPS Fund and the government is as shown in Fig. 13.4-2.

(2) Evaluation of GDPS Fund (a）Expenditures from the GDPS Fund

Since the GDPS Fund is assumed to be independent of the government budget, expenditures of the Fund are limited to the DGPS costs involved in confirming adequate steam resources (Fund operation costs are neglected). Therefore the price gap still needs to be bridged through a subsidy to be paid by the government. In this analysis, the GDPS costs are assumed to be disbursed evenly over the first three (3) years of the five (5)-year development period. The costs are assumed to be USD 35 million for a 60 MW project.

(b）Incomes to the GDPS Fund


JICA West JEC 13-14

Income flows to the GDPS Fund from the sales of the survey results in the area where the government has confirmed adequate steam resources. As stated before, a private developer is obliged to repay the DGPS costs over 10 years from the commissioning of its power plant with 6.5% of interest rate. Also note that the other geothermal benefits such as Tax Value and Fuel Export Value do not devolve to the GDPS Fund, since the Fund is independent from the government budget. This means that the revenue of the Fund is immune to variations in the selling price of geothermal energy and in the oil price. The annual cash flow of the Fund under such conditions is as calculated in Table 13.4-2. Fig. 13.4-3 shows annual expenditure and income from and to the Fund and the year-end balance of the Fund. This figure indicates that the Fund should bear the GDPS costs from 2011 to 2022. Since the Fund supports approximately 10 fields in each year, the annual expenditure of the Fund is around USD 117 million in many years and USD 233 million in some years. The total amount of the annual expenditure is calculated as USD 1,750 million (USD 684 million in NPV). On the other hand, the Fund can obtain the income of interest payment from 2014 and can obtain the repayment of the GDPS costs from 2016. The repayment culminates in 2025 and lasts until 2034. As a result, the year-end balance of the Fund becomes the maxim of USD 1,003 million deficits in 2020, but improves afterwards and turns to be surplus in 2027. The year-end balance of the Fund becomes USD 739 million in 2034. The total amount of the repayment to the Fund is USD 2,489 million (USD 496 million in NPV) which is higher than the total expenditure because of the income of the interest payment. However, since the repayment is done in the later year than the expenditure is done, the NPV of the net income is minus USD 187 million. The FIRR of this cash flow of the Fund in the period is calculated to be 4.9%. In order to simplify the analysis, it is assumed that all fields which are surveyed by GDPS are taken over by private IPP companies.

(c）Feasibility of the GDPS Fund Since the FIRR of the Fund is estimated to be 4.9% which is relatively small return,

public money such as governmental fund or Official Development Assistance fund (ODA fund) is necessary to establish the Fund. On the other hand, the total expenditure of the Fund is estimated as USD 1,750 million. To collect this huge fund, private sector’s money should be also considered as a possible financial source of this Fund. To raise money from private sector, the Fund should improve its financial performance to secure its profit which exceeds the yield of long-term government bonds. For this purpose, some measures are necessary such as the increase in sales price of the survey results, the shortening of the repayment period and the increase of the interest rate. Designing these aspects of the Fund requires due caution, however, since these factors affect the motivation for the geothermal development of private developers who will take over the government survey results.


JICA West JEC 13-15

(3) Costs and Benefits of the GDPS and Feed-in Tariff combination incentives （a）Costs to Government

Even with the government’s initial survey (GDPS), the selling price of geothermal energy is estimated to be slightly higher than the Benchmark price for a while. To bridge this price gap, a Feed-in Tariff scheme is necessary to compensate the price gap. At the same time, the government should supply a Feed-in Tariff subsidy to PT PLN. Government costs in this incentive case are the amount of this subsidy. However, the selling price of geothermal energy is evaluated to be much lower in this case because of the government’s survey. Therefore the amount of the subsidy required is smaller than that for Green Field development. When the oil price is 100 USD/barrel, the price gap is estimated to be about 0.7 USD Cents/kWh in 2016, and it will disappear by 2022 due to the cost reductions brought about by increasing efficiency in geothermal development. (b) Benefits to Government

These are the same as in the previous cases: (i)the Fuel Save Benefit accruing to PT

PLN, (ii) Government revenue from the Fuel Export Value (tax income at a 32.5% tax rate）and (iii) the Tax and Royalties value. Note that the Tax and Royalties Value is smaller for Brown Field development than for Green Field development because the lower selling price leads to the lower tax and royalties payments.

(c）Costs to Society Society’s costs in this incentive case are the sum of the subsidy paid by the

government and the promotion survey costs paid by the GDPS Fund.

(d）Benefits to Society Society’s benefits are the sum of the repayment income of the GDPS Fund, the above

mentioned governmental benefits, (iv) the reminder of the Fuel Export Value（67.5%）, and (v) the Environmental Value（CO2 reduction value）.

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

Geo

ther

mal

Ene

rgy

Dev

elop

men

t in

the

Rep

ublic

of I

ndon

esia

Fina

l Rep

ort

JIC

A

Wes

t JEC

13-1

6

-300

-200

-1000

100

200

300

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

Year

Annual Expenditure/Income (m$)

-1,3

00

-800

-300

200

700

1,2

00

Fund Year-end Balance (m$)

GD

PS F

und

Tota

l Exp

endi

ture

(m

$)

GD

PS F

und

Tota

l In

com

e(m

$)

Fund

Year

-end

Bal

ance (

m$)

Geo

ther

mal

Dev

elop

men

t Pro

mot

ion

Surv

ey (G

DPS

) Fun

d

GD

PS C

ost

GD

PS

succ

ess

Inte

rst r

ate

Tax

rate

Fund

FIR

R35

M$

1.0

6.50

%32

.5%

4.91

%

Year

New

Cap

acity

(cum

.)(M

W)

Gen

.by

Bro

wn

Geo

PP

(GW

h)

Gov

t GD

PSC

ost

(m$)

GD

PS

Fund

Tota

lEx

pend

iture

(m$)

Gov

t GD

PS

Rep

aym

ent

(m$)

GD

PS

Fund

Tota

l Inc

ome

(m$)

Fund

Ann

ual

Cas

h Fl

ow(m

$)

Fund

Yea

r-en

dB

alan

ce(m

$)

ab=

a*87

60h*

0.9

fg=

fi

j=i

k=j-g

k (c

um.)

2009

2010

2011

117

117

00

-117

-117

2012

117

117

00

-117

-233

2013

175

175

00

-175

-408

2014

117

117

2323

-94

-502

2015

117

117

2323

-94

-596

2016

600

4,73

011

711

767

67-5

0-6

4620

1760

04,

730

117

117

7676

-41

-687

2018

900

7,09

623

323

390

90-1

43-8

3020

191,

200

9,46

117

517

511

411

4-6

1-8

9120

201,

200

9,46

123

323

312

112

1-1

12-1

,003

2021

1,50

011

,826

117

117

156

156

39-9

6420

221,

800

14,1

9111

711

716

616

650

-914

2023

2,40

018

,922

00

215

215

215

-699

2024

2,40

018

,922

00

206

206

206

-493

2025

3,00

023

,652

00

230

230

230

-263

2026

3,00

023

,652

00

186

186

186

-78

2027

3,00

023

,652

00

176

176

176

9920

283,

000

23,6

520

015

115

115

125

020

293,

000

23,6

520

012

712

712

737

620

303,

000

23,6

520

012

012

012

049

620

313,

000

23,6

520

097

9797

593

2032

3,00

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00

7575

7566

720

333,

000

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520

037

3737

704

2034

3,00

023

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00

3535

3573

920

353,

000

23,6

520

00

00

739

2036

3,00

023

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00

00

073

920

373,

000

23,6

520

00

00

739

2038

3,00

023

,652

00

00

073

920

393,

000

23,6

520

00

00

739

2040

3,00

023

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00

00

073

920

413,

000

23,6

520

00

00

739

2042

3,00

023

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00

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920

433,

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23,6

520

00

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2044

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920

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23,6

520

00

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739

2046

2,40

018

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00

00

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920

472,

400

18,9

220

00

00

739

2048

2,10

016

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00

00

073

920

491,

800

14,1

910

00

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739

2050

1,80

014

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00

00

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920

511,

500

11,8

260

00

00

739

2052

1,20

09,

461

00

00

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920

5360

04,

730

00

00

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920

5460

04,

730

00

00

073

9TO

TAL

(Nom

inal

)70

9,56

01,

750

1,75

02,

489

2,48

973

9TO

TAL

(in 2

009

USD

)59

,931

684

684

496

496

-187

Cas

h Fl

owFu

nd In

com

e Fu

nd E

xpen

ditu

re

Tabl

e 13

.4-2

Expe

nditu

res,

inco

me

and

cash

flow

of t

he G

DPS

Fun

d

Fig.

13.

4-3

Expe

nditu

re, i

ncom

e an

d ye

ar-e

nd b

alan

ce o

f the

GD

PS F

und

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

Geo

ther

mal

Ene

rgy

Dev

elop

men

t in

the

Rep

ublic

of I

ndon

esia

Fina

l Rep

ort

JIC

A

Wes

t JEC

13-1

7

Geo

ther

mal

Dev

elop

men

t Pro

mot

ion

Surv

ey (G

DPS

) Fun

d Sc

hem

e Ev

alua

tion

Cas

h flo

w o

f Gov

ernm

ent F

isca

l Bal

ance

C

ash

flow

of S

ocia

l Ben

efits

Oil

Pric

eG

DPS

Cos

t

GD

PS

succ

ess

rate

Inte

rst r

ate

Tax

rate

FIR

R

Gov

tB

enef

itN

PVEI

RR

Soc

ial

Bene

fitN

PVU

S$10

035

M$

1.0

6.50

%32

.5%

#DIV

/0!

1,61

8m

$43

.2%

4,79

9m

$

Year

New

Cap

acity

(cum

.)(M

W)

Gen

.by

Bro

wn

Geo

PP

(GW

h)

Ave

rage

Brow

n G

eoP

P P

rice

(Cen

t/kW

h)

Coa

l PP

Pric

e(C

ent/k

Wh)

Pric

e G

ap(C

ent/k

Wh)

Pric

e G

apSu

bsid

y (m

$)G

ovt C

ost

(m$)

Fuel

Cos

tR

educ

tion

Ben

efit

(C$/

kWh)

Exp

ort

Ben

efit

for

Gov

t(C

$/kW

h)Ta

x B

enef

it(C

ent/k

Wh)

Tota

lB

enef

its(C

ent/k

Wh)

Gov

tB

enef

its(m

$)

Gov

tB

enef

itsC

ash

Flow

(m$)

Gov

t Cas

hFl

ow (N

PV

)(m

$)

Pric

e G

apS

ubsi

dy(m

$)S

ocia

l Cos

t(m

$)

Fuel

Cos

tR

educ

tion

Bene

fit(C

$/kW

h)

Expo

rtB

enef

it(C

$/kW

h)Ta

x B

enef

it(C

ent/k

Wh)

Env

ironm

ent

Ben

efit

(Cen

t/kW

h)

Tota

lB

enef

its(C

ent/k

Wh)

Soc

ial

Ben

efit

(m$)

Soc

ial N

etB

enef

it(m

$)

Soc

ial N

etB

enef

it (N

PV

)(m

$)

ab=

a*87

60h*

0.9

cd

e=c-

df=

e*b

g=f

hi=

s*0.

325

jk=

h+i+

jl=

k*b

m=l

-fn=

m/(1

+dis

c.ra

te)^

np=

fq=

p+ (g

of

Fund

)r=

hs

t=j

uv=

r+s+

t+u

w=v

*b+

(oof

Fun

d)x=

w-q

y=x/

(1+d

isc.

rate

)^n

2009

2010

2011

117

0-1

17-9

320

1211

70

-117

-83

2013

175

0-1

75-1

1120

1411

723

-94

-53

2015

117

23-9

4-4

820

1660

04,

730

8.9

8.2

0.7

3434

0.3

1.9

0.8

3.0

140

106

4834

150

0.3

5.7

0.8

1.9

8.7

480

330

149

2017

600

4,73

08.

98.

20.

734

340.

31.

90.

83.

014

010

643

3415

00.

35.

70.

81.

98.

748

933

913

720

1890

07,

096

8.8

8.2

0.6

4242

0.3

1.9

0.8

2.9

208

166

6042

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(Nom

inal

)70

9,56

028

128

120

,000

19,7

19－

281

2,03

163

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61,4

32－

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L (in

200

9 U

SD

)59

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1,71

01,

618

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886

95,

667

4,79

94,

799

Gov

t Cos

tsN

et B

enef

itG

ovt B

enef

itsS

ocia

l Ben

efits

Cas

h Fl

owS

ocia

l Cos

ts

Tabl

e 13

.4-3

Cos

ts a

nd b

enef

its in

the

Geo

ther

mal

Dev

elop

men

t Pro

mot

ion

Surv

ey a

nd F

eed-

in T

ariff

com

bina

tion

ince

ntiv

es c

ase


JICA West JEC 13-18

0

100

200

300

400

500

600

700

800

2016

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

2048

2050

2052

2054

Year

Annu

al C

osts

/Ben

efits

(m$)


(4) Evaluation of the GDPS and Feed-in Tariff combination incentives Table 13.4-3 and Fig. 13.4-4 show the results of the calculation of benefits and costs to

government and to society in this incentive case. In this incentives case, the GDPS Fund supports private geothermal development projects as an independent body from the governmental budget. Since the GDPS reduces the resource development risks to a certain extent, the selling price of geothermal becomes lower. As a result, the compensating Feed-in Tariff becomes low, and the government costs of the compensating Feed-in tariff subsidy become small. The period necessary for the subsidy is calculated to be from 2016 to 2022 alone. On the other hand, the benefits to government occur during the operation period of geothermal power plants, i.e. from 2016 until 2054. These benefits bring about large net benefits to government as shown in Table 13.4-3 and Fig. 13.4-4. When the oil price is 100 USD/barrel, the total government costs become USD 281 million (USD 92 million in NPV) while the total government benefits become USD 20,000 million (USD 1,710 million in NPV). As a result, the total government net benefits during the period turn out to be USD 19,719 million (USD 1,618 million in NPV). Since the balance remains in surplus throughout the period, the FIRR (Financial Internal Rate of Return) of the government fiscal balance is not available.

As for the social benefits and costs, the net benefits to society remain in the red until 2015 because the GDPS costs are required from 2011 and there is no significant income until 2015. However, after 2016 when the first projects start operation and begin to repay the survey costs to the Fund, society begins enjoying certain benefits and the balance goes into the black and stays there during the rest of the period. The total amount of society’s net benefits reaches USD 61,432 million (USD 4,799 million in NPV). The EIRR of the social net benefits is 43.2%. As such, where the oil price stays at 100 USD/barrel, the incentives pay off for the government and allow society to reap a considerable benefit. Fig.13.4-4 Costs and benefits in the GDPS and Feed-in Tariff combination incentives case


JICA West JEC 13-19

-5,000

0

5,000

10,000

15,000

20,000

60 70 80 90 100 110 120 130 140

Oil Price ($/bbl)

Net

Pre

sent

Val

ue (m

$)

GDPS (Govt Benefit)

GDPS (Social Benefit)


GDPS(Govt

Benefit) EIRR

GDPS(SocialBenefit)

NPV (m$) NPV (m$)60 21.2% 164 31.5% 2,44270 + 511 34.7% 3,01680 + 856 37.6% 3,58890 + 1,296 40.6% 4,250

100 + 1,618 43.2% 4,799110 + 1,859 45.4% 5,266120 + 2,106 47.2% 5,735130 + 2,275 48.6% 6,131140 + 2,444 49.8% 6,526


Table 13.4-4 and Fig. 13.4-5 show the sensitivity of the Net Present Value of the

benefits to government and society to oil price variations. A decline of oil price leads to lower benefits to government and society, but this incentive case allows the government to enjoy a surplus even when the oil price drops to 60 USD/barrel. This is mainly attributable to the effect of the GDPS Fund in mitigating significant costs and risks. However, when the Fund is established through ODA finance, the Fund itself can stand alone and the government can enjoy the benefits of geothermal development. Furthermore, society also enjoys the benefits even with the oil price at 60 USD/barrel. This GDPS Fund and Feed-in Tariff combination incentives scheme should be considered extremely useful in promoting geothermal projects through private sector participation.

Table 13.4-4 Sensitivity analysis of the GDPS and FIT combination incentives

Fig. 13.4-5 Sensitivity analysis of the GDPS and FIT combination incentives

CHAPTER 14

IMPORTANCE OF FEED-IN TARIFF

INCENTIVES


JICA West JEC 14-1

Chapter 14 IMPORTANCE OF FEED-IN TARIFF INCENTIVES

In Chapter 13, three kinds of geothermal development incentives, i.e., (i) the Feed-in

Tariff incentives, (ii) the Tax Reduction and Feed-in Tariff combination incentives, and (iii) the

GDPS and Feed-in Tariff combination incentives, are examined in light of the costs and benefits

for government and for society. This Chapter clarifies the importance and the urgent need for

the Feed-in Tariff incentives from among these three incentive packages.

< The Second Crash Program > While this Study was being carried out, two important policies relating to geothermal

development have been announced by the Indonesian government; one is the Second Crash Program

and the other is the Ministerial Regulation of Energy and Mineral Resources on Guideline for

Electricity Power Purchase price by PT. PLN (MR No.5/2009). The Second Crash Program is an

urgent electric power development program to avoid shortages of electric power and to specify and

announce the most important electric power development plans to the public. A similar program was

implemented as the First Crash Program, which aimed to develop 10,000 MW of power during the

period of 2006-2009. The First Crash Program was authorized by a Presidential Decree in 2006. The

Second Crash Program continues the First one and also aims at a 10,000 MW development. Its

scheduled period is 5 years from 2010 to 2014. The characteristic of the Second program is that it

puts priority on renewable energy sources, i.e. 59% of the new power derives from renewable

sources. Among these, geothermal energy accounts for 47% or 4,616 MW. A comparison between

the First and Second Crash Programs is shown in Table 14.1-1. The geothermal projects listed in the

program are shown in the Table 14.1-2.

Table 14.1-1 Comparison between the First and Second Crash Programs The First Crash Program The Second Crash Program Program period 2006-2009 2010-2014 Developers PLN 100% PLN 60% IPP 40% Development amount

Approximately 10,000 MW （of which）Java-Bali 6,900 MW Others 3,100 MW

Approximately 10,000 MW （of which）Java-Bali 4,220 MW Others 5,628 MW

Objectives ・Urgent power source development ・Energy diversity

・ Urgent power source development ・ Energy diversity ・ Renewable energy development

Energy mix Coal 100% Renewable energy 59% （Geothermal 47%, hydro 12%）

Fossil fuel 41% （Coal 26%, Natural gas 15%）

Authorized by Presidential Decree（No.71/2006） Undecided at this date （Source）Made by the Study Team from the collected materials


JICA West JEC 14-2

Region PowerSource

Project Work Area Developer Output

2010 2011 2012 2013 2014 (MW)1 Java IPP PLTP Arjuna Welirang IPP 55 552 Java IPP PLTP Baturaden IPP 110 110 2203 Java IPP PLTP Bedugul Pertamina P-IPP 10 104 Java IPP PLTP Cibuni Pertamina P-IPP 10 105 Java IPP PLTP Cisolok-Cisukarame Tender T-IPP 50 506 Java IPP PLTP Darajat Pertamina P-IPP 55 55 1107 Java IPP PLTP Dieng Pertamina P-IPP 55 60 1158 Java IPP PLTP Mt.Tangkuban Parahu 1 Tender T-IPP 55 55 1109 Java IPP PLTP Mt.Tangkuban Parahu 2 IPP 5 25 30

10 Java IPP PLTP Mt.Papandayan IPP 55 5511 Java IPP PLTP Guci IPP 55 5512 Java IPP PLTP Ijen IPP 110 11013 Java IPP PLTP Iyang Argopuro Pertamina P-IPP 55 5514 Java IPP PLTP Kamojang Pertamina PGE 60 6015 Java IPP PLTP Karaha Bodas Pertamina P-IPP 30 110 14016 Java IPP PLTP Patuha Pertamina P-IPP 60 60 60 18017 Java IPP PLTP Rawa Dano IPP 110 11018 Java IPP PLTP Salak Pertamina P-IPP 40 4019 Java IPP PLTP Tampomas Tender T-IPP 45 4520 Java IPP PLTP Ungaran IPP 55 5521 Java IPP PLTP Wayang Windu Pertamina P-IPP 120 120 24022 Java IPP PLTP Wilis / Ngebel IPP 55 110 16523 Maluku PLN PLTP Songa Wayauwa IPP 10 1024 Maluku PLN PLTP Tulehu PLN PLN 20 2025 Maluku IPP PLTP Jailolo Tender T-IPP 10 1026 NTB PLN PLTP Huu IPP 10 1027 NTB PLN PLTP Sembalun IPP 20 2028 NTT PLN PLTP Atadei IPP 10 1029 NTT PLN PLTP Mataloko PLN PLN 10 1030 NTT PLN PLTP Sukoria Tender T-IPP 10 1031 NTT PLN PLTP Ulumbu PLN PLN 5 8 1332 NTT IPP PLTP Ulumbu IPP 3 333 Sulsera PLN PLTP Lainea IPP 20 2034 Sulutenggo PLN PLTP Bora IPP 10 1035 Sulutenggo PLN PLTP Kotamobagu Pertamina PGE 40 40 8036 Sulutenggo PLN PLTP Lahendong IV Pertamina PGE 20 2037 Sulutenggo PLN PLTP Lahendong Optimasi Pertamina PGE 25 2538 Sulutenggo PLN PLTP Lahendong V Pertamina PGE 20 2039 Sulutenggo PLN PLTP Merana IPP 20 2040 Sumbangsel PLN PLTP Hululais Pertamina PGE 110 55 16541 Sumbangsel PLN PLTP Lumut Balai Pertamina PGE 55 55 55 16542 Sumbangsel PLN PLTP Sungai Penuh Pertamina PGE 55 55 11043 Sumbangsel PLN PLTP Ulubelu Pertamina PGE 55 55 55 55 22044 Sumbangsel IPP PLTP Danau Ranau IPP 110 11045 Sumbangsel IPP PLTP Rajabasa IPP 110 110 22046 Sumbangsel IPP PLTP Rantau Dadap IPP 110 11047 Sumbangsel IPP PLTP Suoh Sekincau IPP 110 11048 Sumbangsel IPP PLTP Wai Ratai IPP 55 5549 Sumbagut IPP PLTP Bukit Kili IPP 55 5550 Sumbagut IPP PLTP Mt. Talang IPP 20 2051 Sumbagut IPP PLTP Jaboi IPP 10 1052 Sumbagut IPP PLTP Muaralaboh IPP 220 22053 Sumbagut IPP PLTP Pusuk Bukit IPP 110 11054 Sumbagut IPP PLTP Sarulla1 Pertamina P-IPP 60 50 220 33055 Sumbagut IPP PLTP Sarulla 2 Pertamina P-IPP 110 11056 Sumbagut IPP PLTP Seulawah Agam IPP 55 5557 Sumbagut IPP PLTP Sipoholon IPP 55 5558 Sumbagut IPP PLTP Sorik Merapi IPP 55 55

Total 70 158 1,028 740 2,620 4,616(Note) 1. P-IPP means development by IPP under JOC with Pertamina. 2. T-IPP means development by IPP already selected by tender process. 3. IPP means development by IPP to be selected by tender process in the future. 4. PGE means development by Pertamina Geothermal Energy. PLN means development by PT. PLN.

Commission Year

Table 14.1-2 Geothermal projects listed in the Second Crash program

（Source）Made by the Study Team from the collected materials


JICA West JEC 14-3

Working Area Developer Area No. 2010 2011 2012 2013 2014Pertamina PGE 9 0 100 335 225 205 865 (18.7%)

IPP 11 60 50 550 165 515 1,340 (29.0%)PLN 3 5 8 20 0 10 43 (0.9%)Already Tendered 5 0 0 0 55 170 225 (4.9%)Undecided (New IPP) 30 5 0 123 295 1,720 2,143 (46.4%)Total 58 70 158 1,028 740 2,620 4,616 (100.0%)

Total MW

Table 14.1-2 shows 58 geothermal projects adding up to a total capacity of 4,616 MW. The

developer column of the table shows the steam developers presumed by the Study team taking into

account the current situation of each field. Table 14.1-3 summarizes the development capacity by

developers. As this table shows, the Second Crash Program depends on existing private IPPs who

have Joint Operation Contracts with Pertamina for the development of 1,340 MW or 29.0% of the

total target capacity. Likewise, the program also depends on Pertamina (including PT. PLN in the

case of the joint projects between Pertamina and PT PLN) for the development of 865 MW or 18.7%

of the total target capacity. The program depends on new private IPP participation for the

development of the remaining 2,143 MW or 46.4% of the total target capacity. This means that the

Second Crash Program largely depends on developments undertaken by new private IPPs.

Table 14.1-3 Development outlook by developer in the Second Crash Program

（Source）Made by the Study Team from the collected materials

The JICA Master Plan Study shows the geothermal development outlook for each field

until 2025, taking into consideration the current development situation and the resource potential in

each field. Many geothermal fields listed in the Second Crash Program were studied in the JICA

Study. The study shows that the geothermal development shown in Fig. 14.1-1 is necessary to

achieve the 9,500 MW target by 2025. The development outlook indicated in various colors in Fig.

14.1-1 is that of the 58 project fields listed in the Second Crash Program, and the development

outlook shown in white is that of other fields. The figure also shows the development capacity of the

Second Crash Program with a dotted line.

Table 14.1-3 and Fig. 14.1-1 clearly depict the large difference in the development

outlooks of the JICA Master Plan Study and the Second Crash Program. The first conspicuous

difference is the development capacity by 2014. The Second Crash Program expects 4,616 MW of

new development by 2014, for a total capacity of 5,800 MW including existing capacity. On the

other hand, the JICA Master Plan Study forecasts 1,200 MW of new development with a total

capacity of 2,400 MW by 2014. From this point of view, the Second Crash Program seems to be a

very ambitious program. If the government seriously sets forth this ambitious program as its policy

target, it should make all efforts to attain the target.


JICA West JEC 14-4

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Year

Cap

acity

(MW

)

OthersIPP undecidedIPP in TenderIPP in Pertamina Work AreaPLNPertaminaExistingCrash program

2,400MW

1,200MW

9,500MW

500MW700MW

1,200MW

1,900MW

1,200MW

2,450MW

2,450MW

220MW

70MW

2nd Crash program(new 4,600MW)

＜Importance of the Feed-in Tariff incentives＞ The second difference is the key-role developers. Fig. 14.1-1 shows that three

contributions are necessary to achieve 9,500 MW target; one is development by state companies

such as Pertamina and PT. PLN (the light blue part of Fig.14.1-1), another is development by the

existing private IPPs who have the Joint Operation Contracts with Pertamina (the orange part of the

same figure), and the third is development by the private IPP newcomers (the light yellow part and

the white part). Each group of entities contributes about one third to the overall development

according to Fig. 14.1-1.

These three kinds of developer each face different difficulties in their undertakings. These

difficulties can be summarized in simplified form as follows:

(i) For the state companies such as Pertamina and PT PLN, the main difficulties are the

unattractive purchase price and the fund raising.

(ii) For the existing private IPPs who have JOCs with Pertamina, the main difficulty is the

unattractive purchase price.

(iii) For the private IPP newcomers, the main difficulties are the unattractive purchase price

and the large resource development risks.

（Source）Made by the Study Team referring to the JICA Master Plan Study

Fig. 14.1-1 Geothermal development outlook in the JICA Master Plan Study


JICA West JEC 14-5

These considerations make clear that the most important and urgent policies to promote

geothermal development are the pricing incentives such as the Feed-in Tariff incentives and the Tax

Reduction and Feed-in tariff combination incentives. Among these, the Tax Reduction incentives

might face some difficulties in practical application. On the other hand, Chapter 13 indicates that the

costs and benefits of the Tax Reduction and Feed–in Tariff combination incentives and those of the

Feed-in Tariff incentives are not so different. Therefore, the Feed-in Tariff incentives can be said to

be the easiest, the most important and the most urgent incentives to adopt under the current situation.

< Ministerial Regulation of Energy and Mineral Resources (MR No.5/2009) > The second important policy which has been implemented during this Study is the

Ministerial Regulation of Energy and Mineral Resources on Guideline for Electricity Power

Purchase price by PT. PLN (MR No.5/2009). This Decree stipulates the following:

(i) Electric power purchase is to be carried out based on the Electric Power Supply

Business Plan (RUPTL) of PT PLN. (§3-1)

(ii) PT PLN must purchase electric power that uses renewable energy resources with

capacity up to 10 MW. (§3-2)

(iii) PT PLN is obligated to determine a Self-Estimate Price as a reference to be calculated

based on the type of power plant, powerhouse location, capacity, capacity factor with

certain assumptions, including:

a. level of Domestic Component Content;

b. fuel price and quality;

c. exchange rates; and

d. other macroeconomic indicators

e. parameters of reference for exploration and development costs in the case of

geothermal development.

(iv) To implement planned electric power purchases, PT PLN may issue the highest

benchmark price.

(iv) Ministerial Regulation of Energy and Mineral Resources (No. 14/2008) on Benchmark

Prices for Electric Power Sales from Geothermal Power Plants should be revoked.

This Ministerial Regulation replaces the old Ministerial Regulation on Benchmark Prices

for Electric Power Sales from Geothermal Power Plants (MR No. 14/2008). The old regulation

empowered the Ministry of Energy and Mineral Resources to set the purchase price of geothermal

energy. The purchase price for PT PLN was stipulated as 80%-85% of the PT PLN’s average

generation costs in each electric system. On the other hand, the new regulation empowers PT PLN to


JICA West JEC 14-6

decide the purchase price project by project, although the price is subject to final approval by

MEMR. The adoption of a project-base purchase price scheme can be evaluated as a one step

forward from the old regulation which stipulated a simple purchase price based on the PT PLN’s

average generation cost.

This new regulation, however, is a big policy shift which allows a utility company to

decide a purchase price. In principle, renewable energy policy can be divided into two kinds; one is a

price-oriented policy and the other is a quantity-oriented policy. The price-oriented policy is a policy

under which the government obliges utility companies to purchase renewable energy at the

government-decided price, with the quantity purchased being at the discretion of utility companies.

The Feed-in Tariff scheme falls into this category and many European countries have adopted this

type of policy. A quantity-oriented policy, on the other hand, is a policy under which the government

obliges utility companies to purchase renewable energy in quantities decided by the government,

with the purchase price being at the discretion of utility companies. The RPS scheme falls into this

category. The U.S., the U.K. and Japan have adopt this type of policy. The old Indonesian policy was

a price-oriented policy where the government decided the purchase price. Since the designated

purchase price has been relatively low, this report proposes an increase in the purchase price

(Chapter 3, Chapter 8 and Chapter 9). However, the government has shifted from a price-oriented

policy to one that is quantity-oriented by transferring the right of deciding the purchase price from

the government to PT PLN. In spite of this shift, the government has not yet imposed a general

obligation to purchase geothermal energy on PT PLN, although the government has required that PT

PLN purchase renewable energy up to 10 MW. This obligation is too small, though, and, therefore,

the new regulation will do little to promote geothermal development.

As mentioned before, the most important policies in the current situation are the price

incentives. From this point of view, the new Ministerial Regulation is imperfect. If the government

intends to empower PT PLN to decide the purchase price by itself, the government should at the

same time obligate PT PLN to purchase a certain amount of geothermal power, i.e. PT PLN should

be required to use a specific number of MW of geothermal energy by 2014, for example. Otherwise,

the government should revoke the new Ministerial Regulation (MR No. 5/2009) and should

designate appropriate purchase prices.

Again here, the Study Team would like to emphasize the importance and the urgency of

the Feed-in Tariff incentives in promoting geothermal energy development in Indonesia.

CHAPTER 15

AIMING FOR ECONOMIC GROWTH

THROUGH GEOTHERMAL

DEVELOPMENT ~ A WAY TO FOSTER

THE GEOTHERMAL INDUSTRY IN

INDONESIA ~


JICA West JEC

15-1

Chapter 15 AIMING FOR ECONOMIC GROWTH THROUGH GEOTHERMAL DEVELOPMENT ~ A WAY TO FOSTER THE GEOTHERMAL INDUSTRY IN INDONESIA ~

The previous Chapters have discussed the necessity of geothermal energy incentives quantitatively. This Chapter discusses the necessity of them qualitatively and closes the report with the forecast of the future of geothermal development in Indonesia. <Green New Deal Policy>

Chief among the possible long-term incentives to promote the geothermal IPP business without governmental cost-sharing are the CDM and the carbon tax scheme. However, there are many unknown factors in the future of the CDM scheme and uncertainties concerning the future price of CO2. Accordingly, the CDM scheme will probably not be reliable as a long-term incentive. Also, the carbon-tax scheme may have a huge negative impact on the Indonesian economy, if it is introduced, although the carbon tax is very favorable for geothermal development. Therefore, the third and more appropriate way to promote geothermal energy in Indonesia is required.

Under these circumstances, many countries are showing a strong interest in a "Green New Deal" policy, in which stable energy supply, global environmental issues and the economic recovery are effectively addressed together in “three birds with one stone" policy. For example, Mr. Ban Ki-Moon, the U.N. Secretary General, claimed in his speech at the 14th conference of parties (COP14) of UN Framework Convention on Climate Change in December, 2008, that the current global economic downturn is a good chance to address the climate change issue. A green revolution to address the current economic downturn will create millions of jobs. In January 2009, Mr. Obama, the new president of the United States, in a speech entitled “Green Jobs”, advocated a plan to invest USD 150 billion in renewable energy development in the coming 10 years and to create 5 million jobs. Mr. Aso, Prime Minister of Japan, also announced his “Green Economy and Social Restructuring” initiative, which will expand the environment-related market in Japan from JPY 70 trillion in 2006 to JPY 100 trillion within 5 years and will create an additional 800,000 jobs to the current 1.4 million by encouraging solar power generation, energy conservation, fuel-efficient vehicles and so on. In addition, the United Kingdom has announced a plan to install more than 7,000 wind turbines, providing 160,000 additional jobs by 2020. Through these investments, the UK intends to enhance its international competitiveness in the environmental industry. As these examples indicate, each country is implementing a strategy to make environment-related industry one of the main industries for the future, diversifying energy sources, protecting the environment, and stimulating the economy. Clearly, many countries are currently formulating policy around the central concept of strategic renewable


JICA West JEC

15-2

energy1. Indonesia, with 150 volcanoes and more than 27,000 MW of geothermal resource

potential, is the world’s richest country in geothermal resources (Table 15.1-1, Fig. 15.1-1). There is a large development potential, although currently only about 1,100 MW has been developed. This is a good time for Indonesia to adopt a Green New Deal strategy focused on the development of geothermal energy, when many countries are beginning to identify the type of renewable energy development in which they can achieve a comparative advantage. When the geothermal industry is well developed and serves a large domestic market, the localization of technology will start, triggering the next round of cost reductions and leading to the further expansion of the domestic market. As Chapter 7 shows, investment in geothermal projects has a far larger effect in stimulating the national economy and creating more new employment than coal-fired projects. Therefore, the encouragement of investment in geothermal energy raises the likelihood of economic growth and employment expansion. For instance, approximately 400,000 new jobs and around IDR 66.5 trillion in increased production will be created by the geothermal development of 2,400 MW by 2016, according to the Input Output Analysis. This job creation is 2.5 times greater than the 160,000 jobs that would be created if the same capacity was developed with coal-fired plants (BAU case), and the production increase is 3.4 times greater than the IDR 19.4 trillion increase in the BAU case (Fig. 15.1-2, Fig. 15.1-3) 2. This can be called the Green New Deal policy of Indonesia (Fig.15.1-4).

That is not the only target which Indonesia aims at. Indonesia aims to leverage the technological ability it cultivates through domestic geothermal development to contribute proactively to geothermal development in other parts of the world. As this role for Indonesia takes shape, its technological competitiveness will be a driving force in penetrating markets in developing countries and its cost competitiveness will be a driving force in penetrating markets in developed countries. Furthermore, Indonesia should advance its research and development (R&D) efforts to develop more effective and efficient geothermal exploration and exploitation technology to apply to its large resource potential. In addition, Indonesia should offer the geothermal technology thus developed to other countries with geothermal potential which are facing difficulties in geothermal development. Indonesia, which has about 40% of the geothermal resources in the world, is truly blessed in its geothermal endowment to make scientific and engineering contributions to world geothermal development.

1 This information is derived from the website of the Ministry of Environment, Japan, and a Nikkei newspapaer feature article of 10, March, 2009. 2 Refer to Table 7.7-9 and Table 7.7-10.


JICA West JEC

15-3

y = 185.08x - 417.83R2 = 0.9705

0

5,000

10,000

15,000

20,000

25,000

30,000

0 20 40 60 80 100 120 140 160No. of Volcanoes

Geo

ther

mal

pot

entia

l (M

W)

Indonesia

USA

Japan

PhilippinesMexico

Iceland

New ZealandItaly

0

50

100

150

200

250

300

350

400

450

2012 2013 2014 2015 2016

Year

Empl

oym

ent (

1000

per

son)

Geothermal advance case BAU case

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

2012 2013 2014 2015 2016

Year

Prod

uctio

n In

crea

se (b

Rp)

Geothermal advance case BAU case

Country No. ofvolcanoes

Geothermalpotential(MW)

Indonesia 150 27,791USA 133 23,000Japan 100 20,540Philippines 53 6,000Mexico 35 6,000Iceland 33 5,800New Zealand 19 3,650Italy 14 3,267

Government

Private Sector

Geothermal Industry

National Economic Growth

Geothermal Development Target9,500 MW by 2025

Geothermal Incentive Policy

Market Expansion

Domestic ProcurementIncrease

Localization ofTechnology

Cost ReductionGeothermal SupportIndustry Growth

National Economic Growth

EmploymentCreation

Table 15.1-1 Geothermal resources in the World

（Source）Agency of Industrial Science and technology, Fig. 15.1-1 Relation between number of volcanoes METI, Japan and geothermal potential

Fig.15.1-2 Employment creation by Fig.15.1-3 Production increase created by geothermal and coal-fired projects geothermal and coal-fired projects

Fig. 15.1-4 Green New Deal Policy of Indonesia


JICA West JEC

15-4

<Current State of the Geothermal Industry in Indonesia> The geothermal industry is comprised of a wide range of industries: geothermal

exploration service companies, drilling service companies, manufacturers and providers of materials, equipment and machinery for geothermal power plants, local industries which use hot water from geothermal plants to enhance their product quality, etc. Fig. 15.1-5 is Geothermal Industry Cluster Map, showing the value chain and supply chain in geothermal operations. Generally geothermal operations can be divided into two main activities: the upstream activity (steam development) and the downstream activity (energy generation).

The upstream activity is similar to oil and gas exploration and drilling activities. Indonesia’s oil and gas service market is reported to be continuing to increase, from USD 5.2 billion in 2004 to USD 6.2 billion and USD 8.6 billion in 2005 and 2006, respectively3. The geothermal upstream service market is not so large, but the market is also expected to increase as geothermal development proceeds. In the fields of oil and gas upstream activities, the localization of technology is still in the early stages. Indonesia has managed to achieve an average of 25%-35% of local content in this field4, while some specific activities have seen local content rise above the 80% level. The Government has targeted the local content of oil and gas service activities for an increase to 50% by 2010 and 70% by 20255. Since geothermal upstream technology depends largely on the oil and gas upstream technology, the localization of technology in oil and gas sector will contribute to the localization of geothermal technology.

Downstream geothermal activity is similar to the activity of fossil-fuel power generation. For fossil-fuel power plants, Indonesia has managed to achieve a 90% local content for manpower engaging in plant construction (electrical and civil work) and project management6. Also, many Indonesia companies have participated in specialized fields such as fabrication of boiler/heat recovery steam generators, condensers, feed water heaters, cooling water piping, structural steel, ducting, critical piping, coal silos, air heaters, coal-handling and ash-handling equipment and small turbines , but overall local content is still below 25%7. The main pieces of equipment are turbines and generators, and Indonesia has finally reached the stage where it manufactures 1.2 MW capacity equipment itself. Much effort is still needed to enhance the national engineering/manufacturing capacity in these fields.

In the power transformation and transmission fields, Indonesia has achieved a certain level of technology. A review of the list prepared by the Ministry of Industry regarding the National Capacity in manufacturing shows that most of the electrical components such as transformers, switchboards and insulators currently manufactured locally are intended to meet 3 According to BPMIGAS 4 Estimation of PEN Consulting Co. 5 According to a plan of Ministry of Industry 6 Estimation of PEN Consulting Co. 7 Estimation of PEN Consulting Co.


JICA West JEC

15-5

the market of the electricity distribution sector, i.e. for low and medium-voltage equipment. For example, the main transformer installed in Lahendong geothermal power plant (unit-1) was produced in Indonesia, and 20 kV insulators can be manufactured locally. Indonesia also has the technology to produce transmission cables and towers locally8.

Fig. 15.1-5 Geothermal industry cluster

<Possibility of Fostering Geothermal Industry in Indonesia> Fortunately, unlike oil and gas development in the 1960’s, the development of

Indonesia’s geothermal industry today is not starting from scratch. From a technological perspective, many of the advances required in order to increase the feasibility of a viable Indonesian geothermal industry are already at various stages of commercialization, or undergoing research and development, within the related mining, oil, and gas industries and industrial research organizations, either in Indonesia or abroad. These are factors that can make a tremendous positive contribution. Moreover, research and development for technology improvement is also being promoted in the power generation field, contributing greatly to technology localization. The prospects for geothermal technology localization are roughly as follows: (Resource Exploration Technology)

Currently, studies and analysis of geological, geochemical, and geophysical conditions are being carried out in Indonesia. Some of the subsurface techniques most commonly used are aeromagnetic surveys, gravity surveys, radiometric imaging, electromagnetic soundings (for example magneto-telluric (MT) and time-domain electro-magnetic surveys), reflection and 8 The description of Indonesian industry’s ability is based on the data of Ministry of Industry, Inventory Lists of Domestically Produced Goods and Services Year 2008, and estimation of PEN Consulting Co. and West JEC Co..


JICA West JEC

15-6

refraction seismic surveys, seismic tomography and synthetic aperture radar imaging. The technological level of these Indonesian surveys is high. However, in certain fields which need special expertise or state-of-the-art technologies, Indonesia depends on overseas consulting services. It is necessary for Indonesia to catch up in its mastery of these technologies. It should be possible for Indonesia to acquire them over the short or middle term. (Resource Management Technology)

Reservoir modeling is the main technology in this field. Indonesia is on its way to developing highly accurate reservoir simulation technology. It should be able to acquire this technology over the short or middle term and utilize it in the design and management of geothermal plants. (Drilling Technology)

The necessary technologies in this field are almost mature, and Indonesia can provide a certain portion of services in this field. One of the big challenges facing the field is the rise in drilling costs. High oil prices have stimulated oil exploration activity, and the price of drilling service is rising. Geothermal drilling is also greatly affected by these price increases. However, drilling costs can be expected to fall somewhat in the future if geothermal development expands, partly because of the learning effect and partly because of the emergence of specialized geothermal drilling service companies. If the number of drilling service suppliers increases, the service cost will fall. New technologies may also contribute to cost reduction. For example, technology for cleaning the inside of wells using acid (acidizing) will increase steam production. If Indonesia acquires this kind of technology, its steam costs will be remarkably reduced. Indonesia should be able to acquire such technology soon.

Although Indonesia produces steel plate and pipes, it has not yet acquired seamless pipe production technology. Therefore it largely depends on imported drilling pipes, well-casing pipes, slotted liners and so on. Yet there is a possibility of localizing the production of these products, if Indonesia makes an effort to acquire the necessary technologies, because the market for these products is large when the oil and gas exploration market is also considered. Indonesia also depends on imports for high-quality drilling mud and casing cement, although it produces simple drilling mud and cement itself. The production of these materials is also likely to be localized in the future, with production under a licensed production scheme as an intermediate stage. (Steam Gathering Systems)

Steam gathering system components such as steam pipes, silencers and separators can be manufactured by existing national technology. In some geothermal fields it is difficult to inhibit the formation of scale in reinjection pipes. Scale inhibition technology is necessary in such fields, but Indonesia should acquire it over the short or middle term.


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15-7

(Steam Turbines and Generators)

Indonesia is now able to produce turbines and generators of about 1 MW in capacity. Currently efforts to enhance this ability are proceeding. The National Agency for the Assessment and Application of Technology (BPPT) is implementing a research and development program to produce a 10 MW-class geothermal turbine and generator. BPPT has already succeeded in developing a 1 MW-class prototype of a binary generator. The machine was demonstrated in Wayang Windu geothermal power plant (Fig. 15.1-6). Moreover, BPPT has designed a 2 MW-class back-pressure type generator, and PT. Nusantra Turbine Co. in Bandung is manufacturing it. There is another plan to produce a 5 MW-class condensing type geothermal turbine and generator by about 2013-2014. These R&D activities are supported by public and private cooperation between BPPT, the Ministry of Research and Technology, PT. Rekayasa, PT. Nusantara Turbine Co. and PT. PINDAD (Persero). If these power generation technologies can be successfully developed, cost reductions can be expected. BPPT’s target is to produce 2 MW-class back-pressure turbines at a price of USD 1,600 per kW. When mass production starts, the price can be reduced even further. Even though the capacity is small, the localization of these technologies will make a great contribution to geothermal development in Indonesia. (Transmission and Distribution of Power)

Indonesia has a good technological level in this field, as mentioned earlier. 20 kV-class transformers, switch boards and insulators can be produced in Indonesia. It is natural to forecast that Indonesia will be able to manufacture higher voltage versions of these products in the future.

(Source) BPPT (Source) BPPT

Fig. 15.1-6 Prototype of binary Fig. 15.1-7 Hot water utilization in palm sugar processing type (Lahendong geothermal power plant) turbine/generator (1 MW) developed by BPPT


JICA West JEC

15-8

(Hot Water Utilization) Hot water utilization is partially carried out as a local society development program in

some geothermal plants. For instance, a local palm sugar factory is using hot water from Lahendon geothermal plant, and mushroom cultivation and tea leaf drying are being researched at Kamojang geothermal plant. BPPT is implementing research and development activity to expand hot water utilization.

Table 15.1-2 shows a geothermal industry development strategy. It is to be hoped that the geothermal industry will develop in such a way through expansion of the geothermal market in Indonesia. <Contribution to the Geothermal Development around the World>

The future of the geothermal industry of Indonesia is to advance into overseas markets using technology cultivated through domestic geothermal development. The Indonesian geothermal industry could enter the market in developing countries thanks to technological competitiveness, and could enter the markets of the developed countries thanks to cost competitiveness. Indonesia should further promote research and development of more effective and efficient geothermal technologies, leveraging its big domestic market. There are good examples of the Indonesian oil and gas industry making a solid contribution to research and development in oil and gas technology. One of these success stories is the steam-flood project in Duri oil field (Riau Province).

Duri oil field was discovered in 1941. Although it is the second largest oil field in

Indonesia, only 7.5% of its oil-in-place will be recovered by primary means. Therefore it has been necessary to develop an innovative recovery method through focused research. Encouraged by the results of laboratory and field tests in early 1980’s, the Production Sharing Contractor decided to embark on field-wide-scale steam injection. Supported by its shareholders and the Government, the project has been successful, and currently contributes about 20% of total Indonesian oil production, becoming the world’s largest steam-flood project. Besides providing additional revenue from increased oil recovery, the project has generated employment opportunities, new business opportunities, socio-economic growth and technological development of enhanced oil recovery methods. By developing expertise on a large scale at an early stage, Indonesia is in an excellent position to extensively expand its steam-flood operations in other oil fields in Indonesia and in other parts of the world. Indonesia has made a remarkable intellectual contribution to this technology.

The geothermal potential of Indonesia is very large and derives from a great variety of geothermal fields. When standard technology is insufficient to exploit the resources of a field, new technological innovation is needed. Once a new technology is developed, it can be of great use in other similar geothermal fields, not only in Indonesia but also in other countries. It may


JICA West JEC

15-9

be thought of as a kind of obligation for a country like Indonesia, which has the world’s most extensive geothermal resources, to take the lead in global geothermal energy development.

<The Way forward for the Geothermal Industry in Indonesia>

What kinds of policy should the government implement to develop the geothermal industry of Indonesia? It is important to have appropriate industrial development policies and technology promotion policies. In the case of industrial policy, it must be emphasized that the key to success will not be industry protection, but the encouragement of dynamic industrial development that involves competent players with the necessary knowledge and international competence. Thoughtless local content regulations are useless for effectively promoting fledgling industries. To fully realize the technological potential of local industry, most effort should be focused on making domestic industry more competitive with foreign industry.

In formulating policy to promote technology, it is important to strengthen the

infrastructure available for future technological development. It is also important to maintain the capacity-building programs of universities and other institutions of higher education. It is necessary to train an adequate number of engineers to promote geothermal development in line with the Geothermal Development Road Map. The program to train a sufficient number of engineers to respond to the quantitative and qualitative needs of the geothermal industry should be strengthened.

However, there is one policy that is more important than these policies and that is “to

convince everyone of the existence of an extremely large geothermal market in Indonesia”. Specifically, the government should put into practice the policies proposed in Chapter 9, thus convincing the public of its serious determination to develop Indonesia’s geothermal potential. By implementing these policies in a stable manner over a long period of time, the government can establish popular confidence in a large domestic geothermal market. Once people have this confidence, some will invest in geothermal IPP projects, and others will invest in local factories to produce equipment or materials for geothermal activities. Through these investments, steady steps will be taken in the creation of a geothermal industry cluster in Indonesia. The first policy should be to "implement the incentives to accelerate geothermal energy development" proposed in Chapter 9, and to “continue the incentives for a certain period” to convince everyone inside and outside of Indonesia of the golden future that lies ahead for Indonesia geothermal development.

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

Geo

ther

mal

Ene

rgy

Dev

elop

men

t in

the

Rep

ublic

of I

ndon

esia

Fina

l Rep

ort

JIC

A

Wes

t JEC

15

-10

Tabl

e 15

.1-2

G

eoth

erm

al in

dust

ry d

evel

opm

ent s

trate

gy

ITEM

CU

RREN

T CA

PACI

TY

MID-

TERM

TARG

ET (2

020)

LO

NG-T

ERM

TARG

ET (2

025)

Explo

ratio

n Tec

hnolo

gy:

• Ge

ologic

al •

Geop

hysic

al •

Geoc

hemi

cal

Dome

stic S

ervic

e Pro

vider

is av

ailab

le for

: •

Abso

lute d

ating

, rem

ote se

nsing

, vo

lcano

-geo

therm

al;

• Gr

avity

, Mag

neto-

Tellu

ric (M

T), m

ulti-e

lectro

de

rece

ptivit

y, CS

AMT,

TDEM

, ele

ctrica

l-rec

eptiv

ity;

• X-

ray d

iffrac

tion,

isotop

e hyd

rolog

y, ga

s mo

nitor

ing sy

stem,

chem

ical

geo-

therm

ometr

y.

•

Keep

ing ab

reas

t of s

tate-

of-the

-art

techn

ology

•

Expa

nsion

of se

rvice

s to o

ther c

ountr

ies

Field

Deve

lopme

nt:

• Re

servo

ir Man

agem

ent

• Dr

illing

Tech

nolog

y •

Prod

uctio

n Fac

ilities

Avail

able

Capa

city

•

Rese

rvoir m

odeli

ng; r

eser

voir

char

acter

izatio

n; fra

cture

imag

ing.

•

Drilli

ng m

ud, d

rill bi

ts, ce

ment

and

acce

ssor

ies, c

asing

& tu

bing;

•

Small

diam

eter s

team

pipes

, valv

es, lo

w pr

essu

re co

ntaine

rs, pi

pelin

e mou

nts.

• Ke

eping

abre

ast o

f stat

e-of-

the-a

rt tec

hnolo

gy;

• Hi

gh qu

ality

drilli

ng m

ud, h

igh qu

ality

drill

bits,

high q

uality

ceme

nt, hi

gh qu

ality

casin

g and

tub

ing et

c. •

Air d

rilling

, drill

pipe

s •

Larg

e diam

eter s

team

pipes

and v

alves

, high

pr

essu

re co

ntaine

rs

• Ex

pans

ion of

servi

ces t

o othe

r cou

ntries

•

Drilli

ng R

ig ma

nufac

turing

Powe

r Gen

erati

on:

• FE

ED, E

PC

• Bu

ilding

s •

Tank

s, pu

mps

• Tu

rbine

, Gen

erato

r

• Lo

cal c

ontra

ctors

are a

vaila

ble

• Fo

unda

tions

of bu

ilding

s •

Tank

s •

Small

turb

ine/ge

nera

tors u

p to 1

.2 MW

• Ex

port

of se

rvice

s •

High

pres

sure

pipe

s and

tank

s, pu

mps

• La

rger

turb

ine/ge

nera

tors u

p to 3

0 MW

• La

rge t

urbin

e/gen

erato

rs up

to 10

0MW

Tran

smiss

ion eq

uipme

nt:

• Tr

ansfo

rmer

s, ins

ulator

s •

Tran

smiss

ion Li

nes

• Lo

w to

mediu

m vo

ltage

(20-

30kV

) •

Low

to me

dium

volta

ge (2

0-30

kV)

•

High

volta

ge (

30-1

50kV

)

• Hi

gh vo

ltage

( 30

-150

kV)

•

Ultra

High

volta

ge (

-500

kV)

•

Ultra

High

volta

ge (

-500

kV)


JICA West JEC ANNEX-1-1

ANNEX-1

Geothermal Business Economic Evaluation Model

1. Outline This is a economic evaluation model of geothermal business. With certain given conditions, the model seeks a power selling rate at which a certain financial viability of the geothermal business could be secured, and outputs several calculation results when the electricity generated by the geothermal power is sold at the selling rate. Making use of this model, you can reflect several geothermal support measures to the given conditions and then calculate the effects.

2. Basic Structure of the Model The model is composed of calculations on spread sheets and iterative calculations by macros. The Excel file name is “Geo_PriceModel_Indonesia_(JBIC)(ver12.00)” consisting of 15 basic sheets; “IO_Table”, “PJ_Cost”, “WACC”, ”Repay(F)” “RepayBase(F)”, “Repay(L)”, “RepayBase(L)”, “Repay(T)”, “RepayBase(T)”, “Field_P&L”, ”Plant_P&L”, ”Total_P&L”, “Field_CF”, “Plant_CF”, and “Total_CF” 1) “IO_Table” : To input basic parameters and to output (print out) major results 2) “PJ_Cost” : To input the project costs and project schedule 3) “WACC” : To calculate the WACC (weighted average capital cost) 4) ”Repay”: To calculate repayment schedules (interest payment, principle payment, etc.)

of a part of the project cost procured by the loan. “Repay(F)” is for the repayment schedule of the foreign currency portion and “Repay(L)” for that of the local currency portion. Then, “Repay(T)” is the one combined both foreign and local portions.

5) “RepayBase”: To calculate repayment schedules (interest payment, principle payment, etc.) of a part of the project cost procured by the loan without financial incentives. The sheet calculates the financial incentive cost which is a difference from the “Repay” sheet calculations. “RepayBase(F)” is for foreign currency portion, “RepayBase(L) for local currency portion and “RepayBase(T)” the combined one for both foreign and local currencies without financial incentive.

6) “Field_P&L”: A profit and loss calculation sheet for steam field development which calculates annual profits and losses and provides the IRR of the upper-stream development.

7) ”Plant_P&L”: A profit and loss calculation sheet for power plant development which calculates annual profits and losses and provides the IRR of the down-stream development.

8) ”Total_P&L”: A profit and loss calculation sheet for both the steam field and power plant development which calculates annual profits and losses and provides the IRR of



both the upper- and down-stream developments. 9) “Field_CF”: A cash flow calculation sheet for steam field development which calculates

annual cash flows and provides the equity IRR of the upper-stream development. 10) “Plant_CF”: A cash flow calculation sheet for power plant development which

calculates annual cash flows and provides the equity IRR of the down-stream development.

11) “Total_CF”: A cash flow calculation sheet for both the downstream and power plant development which calculates annual cash flows and provides the equity IRR of both the upper- and down-stream development. Evaluating each financial condition of steam field and power plant development independently, the Model permits to evaluate the project in case that the project should be implemented by separate executing body, upper-stream and down-stream.

The Macro automatically calculates the following; 1) To provide an initial value of the “Power Selling Price” 2) To seek for a “Steam Price” until both the project IRRs of the steam field development

and power plant development would have agreed. 3) To seek for a minimum power selling price with which the following two conditions

would have been satisfied; the equalized project IRRs of both the development should have exceeded the “value of WACC plus a certain margin” and the equity IRR of the combined project development should have exceeded “a certain expected equity IRR”.

4) After determined the power selling price, the Model could output several calculation results including the project profitability at the selling price on the “IO_Table” sheet. The model configuration is shown in Fig. 1:

3. Performance

Using the Model, you can evaluate the economic efficiency of the investment to a geothermal power project with the following restrictions, or provisions: 1) The economic life of the geothermal power plant is fixed at 30 years1. 2) The economic evaluation of the geothermal power plant is made for 15 years after

commissioning. The evaluation period is fixed. 3) The development period of a geothermal power station is fixed; 2 years for initial

survey, 2 years for exploration and 2 years for construction.2 4) In case that the project cost is procured with loans, the maximum loan period, grace

period plus repayment period, is fixed for 45 years. 5) No other restrictions of input parameters.

1 Deviation from this will require a total modification of the program. 2 Deviation from this will require a total modification of the program.



Outline of "Geo_Price_Model"

Input of parameters

(General Parameters) (Construction Cost Data)

Calculation of Repayment of Loan

(With Gov't Incentives) (Without Gov't Incentives)

Calculation of Profit & Loss Calculation of Cash Flow

MACRO Calculation

No

Yes

No No

Output of CalculationYes Yes

IO_Table PJ_Cost

RepayBase(F),(L),(T)

Field_P&L Plant_P&L Total_P&L

Repay(F),(L),(T)

Field_CF Plant_CF Total_CF

IO_Table

Project IRR Equity IRR

WACC + Margin<= Project IRR

Expected Equity IRR<= Equity IRR

FieldProject IRR

PlantProject IRR

STeam Price

Energy Selling Price

Field Pj IRR =Plant Pj IRR

Fig. A1-1 Basic Configuration of Economic Evaluation Model of A Geothermal Power Project: “Geo_Price_Model)



4. Basic Concept of Economic Evaluation 1) Basic Input Parameters

The development of a geothermal power project is divided into the following

stages: (0) Reconnaissance stage and prefeasibility stage (1) Resource exploration stage (2) Resource confirmation stage and Feasibility Study (FS) (3) Construction of gathering (FCDS) and power plant (4) Power plant operation The period of each stage is assumed as follows: (1) Resource exploration stage: 2 years (2) Resource confirmation stage and FS study: 2 years (3) Construction of gathering (FCDS) and power plant: 2 years These stages are defined as follows;

(0) Reconnaissance stage and prefeasibility stage: The surface survey only (1) Resource exploration stage: Until securing 10% of required steam volume for

power plant operation (2) Resource confirmation stage and FS study: Until securing 40% of required steam

volume for power plant operation (3) Construction of gathering (FCDS) and power plant: Until securing 100% of

required steam volume for power plant operation plus one additional production well drilling

The definition above may be changed in the Model depending on the site conditions of the project. The success ratio of the production wells must be given as parameters and the default value is: (1) Resource exploration stage: 50% (2) Resource confirmation stage and FS study: 70% (3) Construction of gathering (FCDS) and power plant: 80%



Besides, a part of the unsuccessful wells for production wells will be converted for use of the reinjection wells and a lucking number of reinjection well will be additionally drilled. The default success ratio of the reinjection well is 100%. You may change the specifications of the production and reinjection wells but the

default values are as follows: (1) Depth of production wells: 2,000 m (2) Depth of reinjection wells: 1,000 m (3) Unit cost of production and reinjection wells: 2,500 $/m, (5 M$/2,000 m well) (4) Unit production well capacity: 8 MW/well Concerning the finance procurement,

The finance procurement is divided into the following 4 categories. Each category can be set with 1) Equity and loan amounts, 2) Equity and loan interest rates, 3) other terms and conditions of each loan (grace and repayment periods). The default values are shown in the following table:

(1) Resource exploration stage: (2) Resource confirmation stage and FS study: (3) Construction of steam field: (4) Construction of power plant

Category Resource exploration stage

Resource confirmation stage and FS study

Construction of steam field

Construction of power plant

Equity ratio 100％ 100％ 30％ 30% Loan ratio 0％ 0％ 70％ 70％ Opportunity cost of equity

17% 17% 17% 17%

FC interest rate - - 6.5% 6.5% FC repay. period - - 12 years 12 years FC grace period 3 years 3 years LC interest rate - - 13.0% 13.0% LC repay. period - - 12 years 12 years C grace period 3 years 3 years



2) Repayment Schedule of Loans

The repayment will be made with principal-equal-installment for the repayment period at a fixed interest rate.

3) Project Profitability Calculations The Project IRR (PrIRR) is calculated with the following formula:

( )( )

( )∑∑=

−

−

−= +

−−+

+

−=

N

nn

nnnnK

kk

k

rAICQP

rINPVpr

11

1 11 （1）

Where, NPVpr : Net present value of the project asset (at commissioning year) Ik : Construction investment at the k-th year (butｋ=-K,-K+1,・・-2,-1） K : Construction period Pn : Power selling price at the n-th year, (but n=1,2、・・N） N : Economic life for the project Qn : Energy sold at the n-th year Cn : O&M cost at the n-th year AIn : Additional investment at the n-th year

r : Discount rate Besides, the operation and maintenance cost is composed of the following formula:

nnnnn TAXROYMODEPC +++= & (2)

Where, DEPn : Depreciation cost at the n-th operating year (including the additional investment) O&Mn : O&M cost at the n-th operating year

ROYn : Geothermal resource royalty at the n-th operating year TAXn : Corporate tax at the n-th operating year

The r which makes NPVpr＝0 is Project IRR (PrIRR).



4) Equity Profitability Calculations

The Equity IRR (EqIRR) is calculated with the following formula:

( )( )

( )∑∑=

−

−

−= +

−−−−+

+

−=

N

nn

nnnnnnK

kk

k

rINTREPAICQP

rENPVeq

11

1 11 （3）

Where, NPVeq : Net present value of the equity asset (at commissioning year) Ek : Construction equity investment at the k-th year (butｋ=-K,-K+1,・・-2,-1） K : Construction period Pn : Power selling rate at the n-th year, (but n=1,2、・・N） N : Economic life for the project Qn : Energy sold at the n-th year Cn : O&M cost at the n-th operating year AIn : Additional investment at the n-th operating year REPn : Principal repayment at the n-th operating year INTn : Interest repayment at the n-th operating year

r : Discount rate The operating and maintenance cost, Cn, is the same as the Project IRR calculations.

The r which makes NPVeq＝0 is Equity IRR (EqIRR).

5. Practical Usage

1) You may change the parameters at the cells with a red font and enter figures you want to calculate. Besides, the cells with a blue font show the calculation results at the different sheet or sheets, and ones with a black font the calculation results within the sheet.

2) On the “IO_Table” sheet, once you push an “Energy_Selling_Price” button, the Macro starts and automatically calculates the selling price at the input conditions.

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81

102,9

75

179,4

45

6,3

44

57,2

72

6,2

19

162,4

43

25,2

78

167,1

63

62

Real

est

ate

and b

usi

ness

serv

ice

1,0

97,0

94

117,8

70

210,1

25

26,3

40

409,5

81

129,0

06

327,8

60

95,1

06

279,2

39

5,0

44

41,8

60

28,3

85

209,7

71

33,5

49

1,5

49,9

17

63

Genera

! go

vern

ment

and d

efe

nse

0

00

00

00

06

00

00

00

64

Socia

l an

d c

om

munity,

serv

ices

22,7

52

22,4

57

022,2

65

56,5

96

27,1

37

19,4

52

70,9

58

61,1

86

1,5

87

26,8

02

6,6

46

61,7

96

16,8

06

32,6

96

65

Oth

er

serv

ices

2,0

29,9

84

98,3

12

341,3

72

10,5

94

2,4

36,2

38

128,7

85

759,9

24

449,0

14

447,1

84

317,0

55

238,4

51

182,2

89

430,3

95

846,3

72

1,4

07,5

48

66

Unsp

ecifie

d s

ecto

r 9,2

28

00

00

00

870

10

132

09,8

03

26,7

61

360,1

94

190

Tota

l in

term

edia

te input

66,8

33,3

27

45,6

12,0

45

4,1

07,4

62

12,2

74,2

93

31,4

56,3

35

17,7

75,3

65

6,9

33,0

61

42,7

12,3

82

59,3

74,5

00

86,7

25,5

68

25,3

97,2

81

7,8

52,5

95

59,0

82,5

13

6,7

74,3

62

21,7

07,4

08

200

Import

inte

rmedia

te input

5,9

70,2

31

2,0

44,5

18

447,2

72

1,0

02,3

22

3,8

51,1

29

9,7

65,7

99

300,0

28

816,0

64

462,5

87

52,4

03

9,4

72,0

72

80,9

18

5,8

70,4

75

729,3

70

5,5

95,4

32

201

Wag

e a

nd s

alar

y 52,3

20,3

23

20,6

51,8

56

4,7

67,1

67

11,6

16,8

11

17,0

00,2

26

16,2

78,4

48

10,3

91,8

51

4,9

57,0

93

11,0

69,4

00

4,9

67,9

95

4,4

79,2

95

920,3

89

9,6

43,0

87

1,3

48,3

49

5,3

57,5

71

202

Opera

ting

surp

lus

189,7

33,6

41

36,3

56,5

79

15,6

93,4

29

45,5

04,3

70

73,8

31,5

12

155,1

08,1

77

14,5

77,3

83

12,7

27,9

82

19,0

73,1

63

16,0

66,7

50

8,8

41,7

67

1,4

35,1

49

17,1

50,5

84

1,5

87,6

21

10,3

15,9

10

203

Depre

cia

tion

4,4

71,4

17

1,5

36,6

38

1,1

35,3

64

1,6

42,6

08

7,2

18,3

26

6,7

53,3

74

2,8

84,0

50

719,4

26

1,5

91,8

75

3,6

99,9

64

667,1

38

309,9

96

3,7

75,5

95

306,5

71

2,0

60,1

00

204

Indirect

tax

3,5

29,3

38

1,3

00,9

02

949,2

37

720,7

55

4,2

69,2

82

7,7

79,0

87

1,0

77,8

99

1,5

13,0

05

894,4

73

463,8

84

623,5

66

237,5

31

1,3

23,2

86

1,2

54,1

18

27,0

50,1

93

205

Subsi

dy

-147,7

51

00

00

00

00

00

00

00

209

Gro

ss v

alue a

dded

249,9

06,9

68

59,8

45,9

75

22,5

45,1

97

59,4

84,5

44

102,3

19,3

46

185,9

19,0

86

28,9

31,1

83

19,9

17,5

06

32,6

28,9

11

25,1

98,5

93

14,6

11,7

66

2,9

03,0

65

31,8

92,5

52

4,4

96,6

59

44,7

83,7

74

210

Tota

l in

put

322,7

10,5

26

107,5

02,5

38

27,0

99,9

31

72,7

61,1

59

137,6

26,8

10

213,4

60,2

50

36,1

64,2

72

63,4

45,9

52

92,4

65,9

98

111,9

76,5

64

49,4

81,1

19

10,8

36,5

78

96,8

45,5

40

12,0

00,3

91

72,0

86,6

14

Tabl

e A2-

1(1)

Inpu

t Out

put T

able

of 4

7 Se

ctor

s (D

omes

tic T

able

) A

NN

EX

-2

Inpu

t Out

put T

able

of 4

7 Se

ctor

s (20

05)

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

G

eoth

erm

al E

nerg

y D

evel

opm

ent i

n th

e R

epub

lic o

f Ind

ones

ia

Fina

l Rep

ort

JIC

A

W

est J

EC

AN

NEX

-2-2

Tra

nsa

ction D

em

est

ic a

t P

roducer's

Price (

47 s

ecto

r, Y

ear

2005)

（M

illio

n　

Rupia

)S

ecto

r35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

Yar

n s

pin

ni n

Man

ufa

ctu

re M

anufa

ctu

reM

anufa

ctu

reM

anufa

ctu

re M

anufa

ctu

re o

Petr

ole

um

re

Man

ufa

ctu

re o

f M

anufa

ctu

reM

anufa

ctu

re o

Man

ufa

ctu

reM

anufa

ctu

reM

anufa

ctu

reM

anufa

ctu

re M

anufa

ctu

re o

Manufa

ctu

reEle

ctr

icity,

gC

onst

ruction

1A

gric

ulture

108,5

88

1,7

59,7

24

26,4

26

227,5

50

3,6

02

3,6

17,6

50

55

17,9

99,0

97

27,0

36

00

0550

181

0107,0

97

00

2Liv

est

ock

1,4

06

2,4

56,3

06

10

120

51,4

00

0339

00

00

45

00

57,2

42

00

3Fore

st8

58,6

58

10,3

76,6

77

1,0

54,3

81

461

218,7

46

098

43,1

26

00

09,3

13

376

25,7

58

130,2

68

14

9,2

54,6

86

23

Fis

hery

0

28

00

09,3

60

00

00

00

00

0172,5

94

00

24

Coal

and m

eta

l ore

min

ing

12,0

23

193,4

04

33,4

52

59,4

77

4,4

49

6,1

80,2

17

37

105,6

89

344,5

97

3,6

57,3

75

297,2

73

21,7

12,9

84

934,3

42

29,2

38

17,0

70

4,8

25

5,9

44,9

14

025

Cru

de o

il, n

atura

l ga

s an

d g

eoth

erm

al m

in95,0

00

00

109,7

26

8,9

30,4

65

18,0

79,5

84

43,2

79,0

13

4,5

49,1

92

19,7

08

1,6

92,5

28

3,6

79,8

90

0526,3

99

1,2

82

07

6,6

15,5

68

4,0

43

26

Oth

er

min

ing

and q

uar

ryin

g 0

30

012,5

07

303,7

26

144,8

17

237

1,9

97

1,6

98,4

14

1,0

86,0

80

00

1,8

22

4,5

96

0107,7

21

030,8

51,7

60

27

Man

ufa

ctu

re o

f fo

od p

rocess

ing

and p

res e

01,2

58

00

04,7

84

00

00

00

00

01,7

09

00

28

Man

ufa

ctu

re o

f oil

and f

at

00

4,5

94

036

1,0

12,7

09

00

00

00

00

0288

00

29

Ric

e m

illin

g 0

00

00

95,6

86

00

850

00

00

00

00

030

Man

ufa

ctu

re o

f flour, a

ll ki

nds

185,2

96

426,4

63

243,5

66

278,6

35

21,2

40

21,8

13

0890

00

00

00

09,4

80

00

31

Suga

r fa

cto

ry

00

00

38

134,7

59

00

00

00

00

00

00

32

Man

ufa

ctu

re o

f oth

er

food p

roducts

5,9

14

222,6

97

00

3162,4

87

0116

50

00

027,0

77

07

00

33

Man

ufa

ctu

re o

f beve

rage

s 0

90

812

31

9,6

60

00

00

00

014

00

00

34

Man

ufa

ctu

re o

f cig

arett

es

00

00

00

00

00

00

00

00

00

35

Yar

n s

pin

nin

g 5,7

45,1

47

23,8

35,0

42

46,8

55

12,2

79

695

35,1

59

0610,6

19

11,6

57

4,9

03

00

100,0

97

70,5

47

162

20,6

34

03,1

40

36

Man

ufa

ctu

re o

f te

xtile

, w

ear

ing

appar

el an

610,6

94

32,8

55,5

94

290,3

58

38,6

69

4,4

60

77,8

10

95

428,0

59

17,9

56

0132

399

184,5

28

378,5

76

258,9

59

303,4

44

12,1

20

137,4

92

37

Man

ufa

ctu

re o

f bam

boo, w

ood a

nd r

atta

n

16,4

46

72,6

92

11,8

17,5

14

82,5

20

3,8

82

54,8

14

685

47,1

99

32,5

55

00

0946,6

40

307,2

12

183,1

86

593,0

83

019,4

84,3

05

38

Man

ufa

ctu

re o

f pap

er, p

aper

pro

ducts

and

153,3

68

779,7

98

177,3

14

22,7

49,5

42

50,0

40

652,3

30

892

467,7

26

144,9

22

84,9

68

18,3

27

13,6

78

122,9

24

1,2

25,7

44

119,3

42

100,4

02

191,7

53

1,2

86,3

81

39

Man

ufa

ctu

re o

f fe

rtili

zer

and p

est

icid

e

721

1,6

16

21,3

26

1,2

12

30,0

70

59,7

59

75

21,1

57

5,9

63

5,2

58

00

7,4

45

35,0

95

01,2

44

00

40

Man

ufa

ctu

re o

f chem

ical

s 2,9

63,7

96

5,6

39,5

28

2,5

33,5

97

4,5

87,3

44

105,2

76

5,2

40,0

09

52,9

09

11,8

11,1

62

763,0

86

12,2

70

356,5

58

38,6

46

3,9

74,3

98

6,7

14,9

52

548,8

26

499,7

44

1,1

98,2

82

3,3

81,4

83

41

Petr

ole

um

refinery

79,2

44

1,7

73,1

99

631,4

82

1,5

29,8

54

112,1

03

1,2

44,9

51

3,8

61,1

85

3,2

38,5

55

2,7

45,5

43

765,0

19

1,9

44,5

69

664,2

62

2,4

03,0

17

1,6

26,6

70

698,8

02

222,6

88

18,0

54,7

87

25,5

83,7

65

42

Man

ufa

ctu

re o

f ru

bber

and p

last

ic w

ares

7,2

84

1,5

11,6

70

261,3

06

311,3

63

23,1

44

324,8

44

18,3

52

7,9

88,3

50

11,5

05

846

24,6

33

3,7

27

458,3

67

6,6

31,8

68

1,4

14,2

90

648,3

89

378

7,6

27,5

47

43

Man

ufa

ctu

re o

f non m

eta

llic m

inera

l pro

du

16,3

55

212,7

56

2,9

59

7,6

03

132,8

90

716

73,4

91

401,4

27

10,1

51

27

736

200,9

05

700,1

58

133,8

28

407,8

15

7,6

49

19,9

78,5

76

44

Man

ufa

ctu

re o

f cem

ent

00

00

00

00

643,8

57

37,6

24

00

7,6

53

3,1

64

020,7

89

019,4

08,7

98

45

Man

ufa

ctu

re o

f bas

ic iro

n a

nd s

teel

016,5

57

3,0

97

77

00

117

1,2

59

104,3

91

02,2

34,7

91

31,1

97

5,8

01,8

67

1,3

78,2

90

2,7

14,7

23

253,1

31

013,0

74,8

42

46

Man

ufa

ctu

re o

f nonfe

rrous

bas

ic m

eta

l 0

27,6

33

30,6

68

72,5

98

02,1

89

262

2,4

84

18,1

39

087,8

99

2,8

28,1

88

3,6

82,7

83

1,5

91,5

61

545,2

50

840,7

54

03,6

56,7

93

47

Man

ufa

ctu

re o

f fa

bricat

ed m

eta

l pro

duct s

425

306,1

27

285,1

21

113,2

71

1,7

14

4,3

72

43,0

21

330,4

48

271,4

46

051,7

40

62,0

43

1,7

70,9

05

3,1

07,8

04

1,5

56,6

08

443,7

60

33,4

19

43,9

85,4

48

48

Man

ufa

ctu

re o

f m

achin

e, ele

ctr

ical

mac

hi n

62,6

36

2,3

01,8

08

1,1

34,0

11

637,9

69

12,6

13

613,8

39

261,1

23

1,3

13,5

81

611,2

66

0249,6

71

134,2

63

538,4

93

37,2

07,8

22

2,2

68,4

64

302,5

87

1,4

08,3

58

13,3

44,5

89

49

Man

ufa

ctu

re o

f tr

ans p

ort

equip

ment

and

00

117

00

22,4

18

30

00

065,5

89

029,8

17,4

77

90

050

Man

ufa

ctu

re o

f oth

er

pro

ducts

not

els

ew

h675

126,4

22

103,6

05

18,9

02

131

28,9

16

803

162,9

52

46,1

06

350

4,4

15

1,5

47

75,6

15

450,7

40

177,2

67

197,7

66

1,2

33

230,9

87

51

Ele

ctr

icity,

gas

and w

ater

supply

2,1

61,4

67

3,8

41,1

51

1,0

07,7

81

1,7

49,0

80

64,7

96

1,1

97,5

60

51,5

98

1,4

58,7

67

775,9

19

1,8

03,7

02

2,0

97,9

15

370,2

42

1,6

64,7

92

2,6

11,9

70

1,2

19,7

76

539,6

79

13,5

03,9

93

248,1

24

52

Const

ruction

4,2

12

520,6

66

37,6

00

23,0

36

2,7

84

257,0

02

49,6

92

58,4

66

202,1

21

99,5

88

18,8

48

136,7

41

236,2

78

449,6

77

156,6

72

15,6

14

847,9

48

589,4

16

53

Tra

de

2,2

42,8

66

8,6

68,6

03

6,3

13,3

73

5,7

19,5

74

389,9

46

5,5

09,7

65

313,9

82

7,3

86,0

80

1,6

24,4

96

747,7

61

1,6

53,3

26

565,1

93

4,8

07,3

80

19,4

05,0

78

7,4

01,6

93

1,1

03,9

81

3,1

96,3

49

48,4

84,4

76

54

Rest

aura

nt

and h

ote

l 29,9

66

321,4

75

24,3

81

101,9

21

7,8

25

169,4

62

76,4

63

69,3

69

38,8

23

78,5

29

95,2

29

56,4

41

35,2

72

207,9

57

220,6

15

36,8

28

37,4

56

776,4

70

55

Rai

lway

tra

nsp

ort

900,2

86

2,4

12,6

97

2,3

51,3

47

2,5

00,8

21

97,8

30

1,5

06,8

30

115,9

64

1,5

48,7

18

655,4

31

246,3

01

442,3

97

284,0

17

1,1

64,2

81

5,5

08,6

52

1,5

41,5

59

464,7

20

570,9

30

7,8

14,9

41

56

Road

tra

nsp

ort

196,8

23

881,5

44

794,3

86

487,6

72

34,7

85

449,4

98

27,1

76

717,4

53

220,2

49

85,3

81

148,6

63

60,0

89

431,1

94

1,8

06,7

48

542,4

58

170,9

98

207,4

11

2,9

66,8

38

57

Wat

er

tran

sport

41,0

14

225,8

90

217,6

82

100,2

10

14,4

56

187,0

36

29,7

46

159,4

28

68,3

37

48,2

30

81,1

52

51,9

44

123,3

96

458,7

15

151,6

82

58,8

69

81,1

66

882,5

73

58

Air t

ransp

ort

154,8

63

511,5

23

484,2

10

227,1

77

26,2

43

259,7

53

15,5

83

383,4

13

138,7

27

30,0

39

161,8

31

48,9

13

289,3

98

1,0

93,1

35

277,3

53

72,0

08

95,9

69

1,2

73,1

02

59

Serv

ices

allie

d t

o t

ransp

ort

147,9

99

664,8

61

142,5

58

458,2

57

122,3

07

1,0

10,4

46

29,6

32

484,5

50

286,6

21

159,6

58

44,1

80

237,9

36

518,5

15

1,2

21,1

89

306,8

37

94,7

01

97,0

60

2,7

21,8

55

60

Com

munic

atio

n

546,6

74

2,3

89,7

97

1,5

13,6

87

1,6

65,1

33

107,5

64

1,3

38,1

91

416,2

94

2,0

25,9

17

491,3

20

224,4

59

173,2

06

171,2

10

1,3

08,6

12

1,5

20,6

07

1,3

77,9

16

377,7

06

751,4

89

4,4

63,1

50

61

Fin

ancia

l in

term

edia

ries

374,9

30

1,0

00,0

86

83,0

99

378,0

03

89,2

88

704,1

51

138,6

93

474,7

21

103,5

04

50,7

67

211,7

78

71,2

65

367,6

05

753,1

80

350,2

91

92,1

18

283,2

81

2,7

19,2

48

62

Real

est

ate a

nd b

usi

ness

serv

ice

422,3

38

1,2

37,3

01

979,7

72

474,6

68

70,2

29

735,6

98

306,2

19

396,9

56

294,7

07

45,7

71

402,2

43

157,1

50

1,1

31,1

38

5,1

96,9

58

2,1

39,6

48

246,1

68

1,4

05,3

71

14,9

59,1

67

63

Genera

! go

vern

ment

and d

efe

nse

0

12

54

02

00

02

00

02

00

00

64

Socia

l an

d c

om

munity,

serv

ices

113,5

22

199,9

99

37,2

53

405,2

06

13,5

12

605,7

91

1,9

82

88,6

97

33,9

49

68,9

34

20,2

21

696,5

11

21,2

48

157,0

63

337,4

08

36,2

64

60,2

68

1,9

21,3

81

65

Oth

er

serv

ices

84,0

74

1,2

19,7

77

1,1

71,8

38

623,0

16

23,3

06

2,1

09,5

93

368,6

00

547,7

19

299,4

77

122,7

71

102,2

98

596,1

13

630,5

12

3,0

39,9

47

505,6

01

83,7

42

110,0

42

1,4

28,1

83

66

Unsp

ecifie

d s

ecto

r 1,4

71

57,4

42

45,3

05

160,4

28

45

73,2

75

3,3

99

426,1

15

21,8

91

0340,2

91

97,0

58

68,6

33

73,3

13

1,1

26

46,7

66

17

29,1

52

190

Tota

l in

term

edia

te input

17,4

71,1

77

98,5

25,5

23

43,4

38,1

28

46,9

75,0

53

10,6

80,8

18

54,3

29,6

09

49,4

67,0

18

65,3

80,8

32

13,2

19,1

27

11,1

69,2

65

14,9

43,5

03

29,0

92,4

93

34,6

11,9

51

104,9

97,1

58

57,0

10,6

47

8,8

87,6

39

54,7

17,2

25

302,5

72,7

11

200

Import

inte

rmedia

te input

13,6

27,6

56

15,6

47,6

17

5,4

73,5

12

13,9

06,1

84

2,2

80,3

50

39,9

01,2

56

47,8

66,3

86

27,9

80,2

35

3,6

07,1

77

1,2

20,2

74

8,8

51,9

49

2,7

64,3

04

15,4

09,2

99

76,7

71,9

90

37,3

02,7

97

3,9

19,4

80

7,2

65,5

28

69,0

06,9

08

201

Wag

e a

nd s

alar

y 2,8

92,5

85

22,8

87,3

58

9,7

89,0

99

10,2

86,3

03

3,4

23,5

32

12,5

53,4

38

34,5

08,6

71

11,7

14,1

89

5,4

88,9

37

2,3

77,9

65

1,3

16,1

07

3,2

16,7

93

10,8

98,7

09

25,1

97,6

67

21,1

27,5

65

2,3

38,9

60

8,6

88,6

14

76,8

81,8

31

202

Opera

ting

surp

lus

8,4

97,3

54

36,5

96,3

45

20,8

73,7

63

20,2

24,6

02

4,9

96,7

82

17,7

75,1

01

136,1

62,9

58

17,7

49,0

64

6,4

71,7

01

4,4

89,2

43

5,1

85,6

89

4,5

56,4

60

15,0

16,9

49

45,1

78,8

97

33,6

25,4

37

2,9

36,2

54

13,5

04,3

37

103,7

73,7

11

203

Depre

cia

tion

1,7

96,4

01

7,5

25,9

81

3,7

53,7

22

3,4

93,7

54

504,0

50

6,2

91,0

30

17,1

59,2

39

2,9

46,9

11

3,1

26,7

40

1,1

10,9

71

1,1

91,8

80

2,0

56,2

01

3,7

09,6

61

15,3

04,1

15

7,6

12,2

42

390,0

24

12,0

65,2

15

18,7

22,1

41

204

Indirect

tax

613,1

37

1,7

67,4

40

1,0

45,8

90

928,4

24

71,1

15

2,6

55,4

61

1,2

27,0

72

1,9

29,3

95

1,0

09,4

20

623,1

69

459,1

86

572,8

15

1,1

25,1

06

4,2

68,4

87

1,9

41,7

27

458,2

31

1,5

03,1

84

7,4

84,5

09

205

Subsi

dy

00

00

-2,5

49,7

95

0-53,3

93,4

09

00

00

00

00

0-8,8

50,6

00

0209

Gro

ss v

alue a

dded

13,7

99,4

77

68,7

77,1

24

35,4

62,4

74

34,9

33,0

83

6,4

45,6

84

39,2

75,0

30

135,6

64,5

31

34,3

39,5

59

16,0

96,7

98

8,6

01,3

48

8,1

52,8

62

10,4

02,2

69

30,7

50,4

25

89,9

49,1

66

64,3

06,9

71

6,1

23,4

69

26,9

10,7

50

206,8

62,1

92

210

Tota

l in

put

44,8

98,3

10

182,9

50,2

64

84,3

74,1

14

95,8

14,3

20

19,4

06,8

52

133,5

05,8

95

232,9

97,9

35

127,7

00,6

26

32,9

23,1

02

20,9

90,8

87

31,9

48,3

14

42,2

59,0

66

80,7

71,6

75

271,7

18,3

14

158,6

20,4

15

18,9

30,5

88

88,8

93,5

03

578,4

41,8

11

Tabl

e A

2-1(

2)

Inp

ut O

utpu

t Tab

le o

f 47

Sect

ors (

Dom

estic

Tab

le) (

cont

inue

d)

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

G

eoth

erm

al E

nerg

y D

evel

opm

ent i

n th

e R

epub

lic o

f Ind

ones

ia

Fina

l Rep

ort

JIC

A

W

est J

EC

AN

NEX

-2-3

Secto

r53

54

55

56

57

58

59

60

61

62

63

64

65

66

180

Tra

de

Rest

aura

nt

Rai

lway

tra

nR

oad

tra

nsp

Wat

er

tran

sA

ir t

ransp

orS

erv

ices

allC

om

munic

atio

Fin

ancia

l in

teR

eal

est

ate a

Genera

! go

vSocia

l an

d c

omO

ther

serv

iceU

nsp

ecifie

Tota

l in

term

ed

1A

gric

ulture

11,8

08,7

45800

,144

506

34,2

08

124

00

025

13,3

32199

,669

7,088,

551

507,9

60

364

,634

208

,977

,653

2Liv

est

ock

23,6

94,6

002,0

00,4

326,5

53

35,6

47

2,2

24

00

00

289

02,

271,

738

119,6

20

054

,453

,778

3Fore

st72

,133

14,1

710

00

00

00

8,9

153,3

006,

601

141,0

74

022

,267

,804

23

Fis

hery

4,8

02,2

83327

,463

015,1

94

1,2

70

00

00

54,2

770

773,

652

85

025

,250

,290

24

Coal

and m

eta

l ore

min

ing

029

,204

00

00

00

00

00

00

50,5

64,1

6425

Cru

de o

il, n

atura

l ga

s an

d g

eoth

erm

al m

i n0

00

00

00

00

00

00

0103

,999

,634

26

Oth

er

min

ing

and q

uar

ryin

g 9,5

000

00

00

00

00

315

,373

358,

324

00

35,2

87,0

1127

Man

ufa

ctu

re o

f fo

od p

rocess

ing

and p

res e

8,7

85,0

00710

,464

023

0,3

80

5,5

45

00

00

00

506,

443

00

17,9

31,1

7828

Man

ufa

ctu

re o

f oil

and f

at

2,6

83,5

11100

,064

020,5

77

839

00

00

00

36,

548

4,2

12

037

,089

,066

29

Ric

e m

illin

g 12

,413

,602

881

,103

016

4,5

93

11,5

13

00

00

00

5,278,

559

00

25,9

68,0

4430

Man

ufa

ctu

re o

f flour, a

ll ki

nds

3,4

63,8

29437

,604

037

9,7

03

16,1

59

7,5

47

7,7

99

00

00

250,

371

20,9

26

019

,260,7

8031

Suga

r fa

cto

ry

949

,041

343

,017

011

8,7

75

2,7

62

00

00

00

248,

694

8,6

93

08,7

53,7

1232

Man

ufa

ctu

re o

f oth

er

food p

roducts

4,8

06,1

381,0

30,7

1619,4

85

225,8

92

28,9

14

3,0

68

08,3

862,

294

61,4

510

1,864,

069

2,4

75,9

15

043

,467

,545

33

Man

ufa

ctu

re o

f beve

rage

s 1,1

13,8

29453

,281

013

5,9

94

94,6

68

37,3

90

087

,959

286,

972

00

19,

678

96,7

77

02,6

78,5

4634

Man

ufa

ctu

re o

f cig

arett

es

3,5

38,8

78112

,420

053,4

90

45,3

96

00

0488

00

00

06,9

76,0

8135

Yar

n s

pin

nin

g 0

00

00

00

00

540

16,

039

2,0

30

030

,523

,921

36

Man

ufa

ctu

re o

f te

xtile

, w

ear

ing

appar

el an

4,3

80,6

61154

,079

204,0

55

103,8

52

25,4

67

86,2

76

69,0

38

25,5

32120,

813

777,2

47270

,501

605,

997

1,2

28,6

46

3,6

3344

,248

,688

37

Man

ufa

ctu

re o

f bam

boo, w

ood a

nd r

atta

n

972

,218

1,6

077,7

94

01,4

95

13,8

84

2,5

56

1,6

964,

616

30,3

8160

,254

45,

453

79,0

23

2,4

8635

,123

,538

38

Man

ufa

ctu

re o

f pap

er, p

aper

pro

ducts

and

8,0

02,3

21134

,604

461,6

54

71,5

16

169,3

51

125,7

53

742,4

69

1,5

87,1

07567,

769

4,3

03,4

7910

,113

,954

3,889,

897

267,8

98

3,5

4861

,927

,241

39

Man

ufa

ctu

re o

f fe

rtili

zer

and p

est

icid

e

30,6

8612

,968

7,6

70

3,4

34

585

376

00

365

118

,456

16,9

3130,

253

72,0

44

015

,928

,947

40

Man

ufa

ctu

re o

f chem

ical

s 1,5

70,3

10124

,693

316,4

83

158,6

46

41,5

61

39,5

57

10,1

31

125

,056

71,

729

1,2

33,4

971,7

39,2

517,

310,

144

1,1

66,0

21

4,6

6271

,010

,257

41

Petr

ole

um

refinery

10

,740

,433

750

,745

26,1

18,7

72

10,0

09,0

10

3,8

68,7

19

144,9

47

214,9

92

173

,472

203,

345

1,0

12,0

48336

,313

748,

118

220,3

36

28,3

77129

,916

,137

42

Man

ufa

ctu

re o

f ru

bber

and p

last

ic w

ares

4,2

90,9

206,6

171,9

22,2

08

9,8

52

939,4

77

235,1

41

27,6

25

462

,016

81,

016

503,2

66115

,923

444,

429

13,8

99,5

43

470

,067

52,6

87,7

6543

Man

ufa

ctu

re o

f non m

eta

llic m

inera

l pro

du

256

,250

23,6

1611,5

31

2,2

30

752

341

2,3

60

1,8

287,

718

193

,619

34,4

4716,

897

131,5

88

023

,142

,444

44

Man

ufa

ctu

re o

f cem

ent

00

00

00

00

00

00

00

20,1

21,8

8545

Man

ufa

ctu

re o

f bas

ic iro

n a

nd s

teel

00

00

00

00

00

00

313,8

96

025

,928

,235

46

Man

ufa

ctu

re o

f nonfe

rrous

bas

ic m

eta

l 0

00

00

04,0

53

00

00

02,8

43

013

,405

,221

47

Man

ufa

ctu

re o

f fa

bricat

ed m

eta

l pro

ducts

183

,093

36,7

217,6

97

9,5

45

2,9

15

23,6

67

30,4

48

643

,918

21,

044

1,1

29,1

68135

,598

41,

250

716,1

35

299

56,2

72,3

8948

Man

ufa

ctu

re o

f m

achin

e, ele

ctr

ical

mac

hi n

953

,868

47,5

482,2

20,0

12

231,7

97

35,3

38

294,0

97

771,7

22

623

,723

144,

189

3,1

80,9

51339

,048

559,

968

3,9

32,0

78

507

83,8

12,9

3749

Man

ufa

ctu

re o

f tr

ansp

ort

equip

ment

and

0410

,805

054

4,8

56

2,5

09,2

93

32,8

92

00

0826

,892

00

16,5

91,9

07

051

,087

,256

50

Man

ufa

ctu

re o

f oth

er

pro

ducts

not

els

ew

h392

,265

9,9

3323,0

19

46,8

05

7,4

92

3,3

77

119

56,3

9453,

584

345

,196

1,0

01,3

66265,

481

123,0

39

04,2

64,3

5051

Ele

ctr

icity,

gas

and w

ater

supply

10

,616

,896

667

,221

440,4

93

514,2

43

239,7

59

1,1

39,4

97

1,2

04,6

23

891

,931

344,

196

2,7

69,2

10540

,943

984,

777

2,4

93,8

18

10,7

1561

,340

,842

52

Const

ruction

9,2

29,7

14583

,865

381,4

82

371,3

83

43,8

12

3,4

10,2

23

1,6

29,8

09

915

,031

8,65

7,998

8,8

49,6

291,3

61,5

311,

136,

462

650,3

00

049

,460

,472

53

Tra

de

28,0

77,4

942,1

28,4

724,8

92,0

81

3,1

68,9

45

3,7

85,1

28

257,4

40

439,5

26

912

,997

568,

479

11,9

12,1

322,5

56,9

177,

416,

974

8,7

65,8

12

99,9

53247

,321

,570

54

Rest

aura

nt

and h

ote

l 1,0

74,9

3653

,974

159,8

72

180,7

05

152,7

67

85,9

92

64,0

63

169

,356

219,

755

2,2

56,9

2287

,215

88,

954

371,3

91

100

7,8

35,8

7155

Rai

lway

tra

nsp

ort

18

,179

,071

280

,459

1,9

24,8

86

389,2

44

260,3

93

158,0

59

229,8

88

555

,487

745,

574

3,7

38,9

40856

,489

1,135,

921

1,4

86,3

57

22,7

8971

,391

,826

56

Road

tra

nsp

ort

1,7

08,7

16117

,397

370,8

65

377,7

70

124,3

59

118,4

73

93,9

09

45,4

9723,

779

509

,576

190

,249

471,

236

705,2

95

6,2

5319

,115

,475

57

Wat

er

tran

sport

3,0

09,3

0366

,216

849,5

74

59,5

22

1,5

29,6

40

157,1

01

189,4

08

300

,693

315,

415

4,7

36,3

26146

,375

278,

316

190,4

97

938

16,3

93,3

3458

Air t

ransp

ort

1,2

18,9

14108

,205

1,4

73,4

71

4,1

36,6

56

3,2

74,2

56

1,5

66,4

93

77,1

00

30,0

05

134,

207

895

,040

89,7

71224,

073

281,3

29

2,7

9320

,968

,966

59

Serv

ices

allie

d t

o t

ransp

ort

10

,669

,378

293

,689

1,9

86,9

26

726,6

53

432,8

34

2,0

00,3

01

5,9

07,9

79

2,1

08,0

76828,

046

2,5

66,5

16319

,253

1,576,

719

1,1

78,0

59

14,6

3840

,934

,963

60

Com

munic

atio

n

16,8

84,3

01115

,963

853,8

66

301,3

45

365,7

70

130,6

86

1,0

43,1

14

25,7

40,4

52

3,41

3,758

4,3

41,0

85867

,903

699,

793

1,1

15,2

39

088

,165

,699

61

Fin

ancia

l in

term

edia

ries

34,3

26,5

21142

,268

3,4

83,4

85

1,0

47,1

74

1,1

04,2

79

223,0

34

1,4

45,5

59

3,2

07,6

173,

721,

509

4,9

05,1

58352

,728

1,488,

831

5,5

22,6

28

072

,089

,212

62

Real

est

ate a

nd b

usi

ness

serv

ice

7,6

63,0

68457

,405

1,6

20,3

51

707,0

75

1,2

19,9

42

1,4

94,7

13

963,0

71

3,0

06,4

902,

949,

036

1,9

37,2

89895

,201

2,142,

570

1,1

65,5

79

15,3

8461

,399

,423

63

Genera

! go

vern

ment

and d

efe

nse

0

30

02

00

50

00

00

043

64

Socia

l an

d c

om

munity,

serv

ices

742

,715

160

,868

159,9

42

90,1

05

110,4

38

200,2

63

462,4

17

419

,881

318,

252

1,7

03,3

96835

,475

3,221,

879

923,9

73

014

,617

,949

65

Oth

er

serv

ices

8,8

80,9

97173

,254

30,5

16,0

57

451,3

06

477,5

71

1,2

11,5

83

1,4

68,6

93

1,1

43,7

331,

390,

149

13,3

07,9

61977

,028

1,411,

952

3,1

25,1

20

087

,725

,530

66

Unsp

ecifie

d s

ecto

r 1,4

06,2

220

00

90

1,8

26

043

00

011,2

38

19,9

543,2

92,0

08190

Tota

l in

term

edia

te input

263

,602

,360

14,3

03,2

7880,4

40,7

90

25,1

28,1

22

20,9

32,8

18

13,2

02,1

71

17,1

04,2

97

43,2

44,3

3825,

196,

163

78,2

21,6

9824

,759

,006

54,

955,

611

70,1

08,9

24

1,0

71,7

302,2

44,3

79,6

80200

Import

inte

rmedia

te input

22,2

32,8

93876

,712

9,8

52,2

24

13,0

05,2

99

14,0

38,8

39

3,2

94,4

09

3,7

37,9

02

4,2

06,9

914,

410,

476

18,5

45,1

772,9

54,1

945,

894,

503

24,6

89,6

36

188

567

,002

,965

201

Wag

e a

nd s

alar

y 124

,904

,395

6,0

21,6

5126,3

02,4

21

5,2

74,0

44

7,8

89,9

03

8,6

86,6

87

14,9

34,5

02

23,5

44,7

8513,

823,

121

89,9

94,1

3530

,791

,162

49,

945,

095

38,4

24,3

93

323

,507

882

,217

,985

202

Opera

ting

surp

lus

239

,741

,425

10,3

83,7

0510,0

37,3

23

5,4

64,5

82

2,9

45,6

64

7,6

90,6

66

41,7

41,0

26

59,6

53,3

6982,

945,

496

21,8

40,2

360

15,

455,

570

42,2

15,6

97

907

,664

1,6

56,6

41,0

87203

Depre

cia

tion

35,3

37,3

761,6

63,0

4726,6

86,7

81

4,7

14,1

70

5,7

23,4

10

5,0

57,2

62

17,0

34,4

55

3,6

92,4

518,

994,

512

13,6

93,7

904,0

97,0

217,

905,

458

9,6

35,1

93

26,7

97

291

,794

,443

204

Indirect

tax

15,7

55,6

531,1

01,5

401,2

62,8

58

506,4

99

515,4

23

428,0

75

648,8

93

182

,259

2,81

4,130

2,0

08,7

130

1,148,

938

3,0

84,6

77

36,4

30112

,164

,412

205

Subsi

dy

0-320

,500

0-37

8,6

00

00

-14

6,3

00

00

00

0-13

9,3

34

0-65

,926

,289

209

Gro

ss v

alue a

dded

415

,738

,849

18,8

49,4

4364,2

89,3

83

15,5

80,6

95

17,0

74,4

00

21,8

62,6

90

74,2

12,5

76

87,0

72,8

6410

8,577,

259

127

,536

,874

34,8

88,1

8374,

455,

061

93,2

20,6

26

1,2

94,3

982,8

76,8

91,6

38210

Tota

l in

put

701

,574

,102

34,0

29,4

3315

4,5

82,3

97

53,7

14,1

16

52,0

46,0

57

38,3

59,2

70

95,0

54,7

75

134

,524

,193

138,

183,

898

224

,303

,749

62,6

01,3

83135,

305,

175

188,0

19,1

86

2,3

66,3

165,6

88,2

74,2

83

Tabl

e A

2-1(

3)

Inp

ut O

utpu

t Tab

le o

f 47

Sect

ors (

Dom

estic

Tab

le) (

cont

inue

d)

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

G

eoth

erm

al E

nerg

y D

evel

opm

ent i

n th

e R

epub

lic o

f Ind

ones

ia

Fina

l Rep

ort

JIC

A

W

est J

EC

AN

NEX

-2-4

Tra

nsa

ction D

em

est

ic a

t P

roducer's

Price (

47 s

ecto

r, Y

ear

2005)

（M

illio

n　

Rupia

)S

ecto

r301

302

303

304

305

306

309

310

401

402

403

404

405

409

501

502

503

509

600

700

P

riva

te c

onsu

mG

ove

rnm

ent

cGro

ss f

ixed c

Chan

ge in s

Exp

ort

of

gooE

xport

of

serv

Tota

l final

dem

Tota

l dem

and

Import

of

gooI

mport

sal

esI

mport

duty

Im

port

of

serI

mport

Subsi

dTota

l im

port

Whole

sale

Reta

il tr

adTra

nsp

ort

Tota

l tr

ade m

aTota

l outp

ut

Tota

l su

pply

1A

gric

ulture

102,

826,4

160

1,064

,381

-1,2

61,

364

11,1

03,4

40

011

3,73

2,87

3322

,710,

526

00

00

00

00

00

322,7

10,5

26

322

,710,

526

2Liv

est

ock

54,

786,4

940

212,

227

-2,2

46,

382

296

,421

053

,048,

760

107

,502,

538

00

00

00

00

00

107,5

02,5

38

107

,502,

538

3Fore

st2,

334,3

400

029

3,61

72,2

04,1

70

04,

832,

127

27,0

99,9

310

00

00

00

00

027

,099

,931

27,0

99,9

31

23

Fis

hery

44,

812,1

460

0-1

,095,

736

3,7

94,4

59

047

,510,

869

72,7

61,1

590

00

00

00

00

072,7

61,1

59

72,7

61,1

59

24

Coal

and m

eta

l ore

min

ing

00

02,

437,

024

84,6

25,6

22

087

,062,

646

137

,626,

810

00

00

00

00

00

137,6

26,8

10

137

,626,

810

25

Cru

de o

il, n

atura

l ga

s an

d g

eoth

erm

al m

i n0

081

3,67

62,

457,

174

106,1

89,7

66

010

9,46

0,61

6213

,460,

250

00

00

00

00

00

213,4

60,2

50

213

,460,

250

26

Oth

er

min

ing

and q

uar

ryin

g 12

,823

00

-27,

677

892

,115

087

7,26

136

,164

,272

00

00

00

00

00

36,1

64,2

72

36,1

64,2

72

27

Man

ufa

ctu

re o

f fo

od p

rocess

ing

and p

res e

28,

578,1

530

0-1

,526,

777

18,4

63,3

98

045

,514,

774

63,4

45,9

520

00

00

00

00

063

,445

,952

63,4

45,

952

28

Man

ufa

ctu

re o

f oil

and f

at

16,

027,7

200

0-2

,421,

974

41,7

71,1

86

055

,376,

932

92,4

65,9

980

00

00

00

00

092

,465

,998

92,4

65,

998

29

Ric

e m

illin

g 90,

384,8

880

0-4

,482,

827

106

,459

086

,008,

520

111

,976,

564

00

00

00

00

00

111,9

76,5

64

111

,976,

564

30

Man

ufa

ctu

re o

f flour, a

ll ki

nds

27,

956,0

880

027

0,13

91,9

94,1

12

030

,220,

339

49,4

81,1

190

00

00

00

00

049

,481,1

19

49,4

81,1

19

31

Suga

r fa

cto

ry

1,79

8,3

630

04,

743

279

,760

02,

082,

866

10,8

36,5

780

00

00

00

00

010

,836

,578

10,8

36,5

78

32

Man

ufa

ctu

re o

f oth

er

food p

roducts

47,

051,5

830

01,

223,

147

5,1

03,2

65

053

,377,

995

96,8

45,5

400

00

00

00

00

096

,845

,540

96,8

45,

540

33

Man

ufa

ctu

re o

f beve

rage

s 9,

179,0

760

0-8

1,38

8224

,157

09,

321,

845

12,0

00,3

910

00

00

00

00

012

,000

,391

12,0

00,3

91

34

Man

ufa

ctu

re o

f cig

arett

es

61,

770,6

270

073

5,42

22,6

04,4

84

065

,110,

533

72,0

86,6

140

00

00

00

00

072

,086,6

14

72,0

86,6

14

35

Yar

n s

pin

nin

g 36

5,0

260

0-7

5,75

214

,085

,115

014

,374,

389

44,8

98,3

100

00

00

00

00

044

,898

,310

44,8

98,3

10

36

Man

ufa

ctu

re o

f te

xtile

, w

ear

ing

appar

el an

55,

485,8

910

133,

742

6,71

8,03

076

,363

,913

013

8,70

1,57

6182

,950,

264

00

00

00

00

00

182,9

50,2

64

182

,950,

264

37

Man

ufa

ctu

re o

f bam

boo, w

ood a

nd r

atta

n

8,72

9,9

720

98,0

71

-79,

667

40,5

02,2

00

049

,250,

576

84,3

74,1

140

00

00

00

00

084,3

74,1

14

84,3

74,1

14

38

Man

ufa

ctu

re o

f pap

er, p

aper

pro

ducts

and

8,16

5,8

650

099

1,90

324

,729

,311

033

,887,

079

95,8

14,3

200

00

00

00

00

095

,814,3

20

95,8

14,3

20

39

Man

ufa

ctu

re o

f fe

rtili

zer

and p

est

icid

e

674,5

410

025

2,13

22,5

51,2

32

03,

477,

905

19,4

06,8

520

00

00

00

00

019

,406

,852

19,4

06,8

52

40

Man

ufa

ctu

re o

f chem

ical

s 24,

769,1

400

02,

651,

592

35,0

74,9

06

062

,495,

638

133

,505,

895

00

00

00

00

00

133,5

05,8

95

133

,505,

895

41

Petr

ole

um

refinery

80

1,0

800

02,

810,

982

99,4

69,7

36

010

3,08

1,79

8232

,997,

935

00

00

00

00

00

232,9

97,9

35

232

,997,

935

42

Man

ufa

ctu

re o

f ru

bber

and p

last

ic w

ares

33,

964,8

960

02,

006,

964

39,0

41,0

01

075

,012,

861

127

,700,

626

00

00

00

00

00

127,7

00,6

26

127

,700,

626

43

Man

ufa

ctu

re o

f non m

eta

llic m

inera

l pro

du

3,23

4,6

380

52,5

08

988,

632

5,5

04,8

80

09,

780,

658

32,9

23,1

020

00

00

00

00

032,9

23,1

02

32,9

23,1

02

44

Man

ufa

ctu

re o

f cem

ent

00

019,

334

849

,668

086

9,00

220

,990

,887

00

00

00

00

00

20,9

90,8

87

20,9

90,

887

45

Man

ufa

ctu

re o

f bas

ic iro

n a

nd s

teel

00

071

0,25

75,3

09,8

22

06,

020,

079

31,9

48,3

140

00

00

00

00

031

,948

,314

31,9

48,3

14

46

Man

ufa

ctu

re o

f nonfe

rrous

bas

ic m

eta

l 0

00

1,10

2,49

427

,751

,351

028

,853,

845

42,2

59,0

660

00

00

00

00

042

,259

,066

42,2

59,0

66

47

Man

ufa

ctu

re o

f fa

bricat

ed m

eta

l pro

duct s

5,84

3,8

790

5,605

,838

1,11

5,73

811

,933

,831

024

,499,

286

80,7

71,6

750

00

00

00

00

080

,771

,675

80,7

71,

675

48

Man

ufa

ctu

re o

f m

achin

e, ele

ctr

ical

mac

hi n

60,

575,3

230

31,

828

,912

9,17

2,33

486

,328

,808

018

7,90

5,37

7271

,718,

314

00

00

00

00

00

271,7

18,3

14

271

,718,

314

49

Man

ufa

ctu

re o

f tr

ansp

ort

equip

ment

and

76,

141,6

820

14,

321

,234

-721,

223

17,3

85,8

27

405

,639

107,

533,

159

158

,620,

415

00

00

00

00

00

158,6

20,4

15

158

,620,

415

50

Man

ufa

ctu

re o

f oth

er

pro

ducts

not

els

ew

h5,

670,1

510

580,

291

-812,

487

9,2

28,2

83

014

,666,

238

18,9

30,5

880

00

00

00

00

018

,930

,588

18,9

30,

588

51

Ele

ctr

icity,

gas

and w

ater

supply

27,

552,6

370

00

24

027

,552,

661

88,8

93,5

030

00

00

00

00

088

,893

,503

88,8

93,

503

52

Const

ruction

00

528,

981

,339

00

052

8,98

1,33

9578

,441,

811

00

00

00

00

00

578,4

41,8

11

578

,441,

811

53

Tra

de

348,

107,3

170

19,

547

,732

1,84

9,30

576

,602

,878

8,1

45,3

00

454,

252,

532

701,

574,

102

00

00

00

00

00

701,5

74,1

02

701

,574,

102

54

Rest

aura

nt

and h

ote

l 9,

834,3

380

18,5

48

2,90

880

,591

16,2

57,1

77

26,1

93,

562

34,0

29,4

330

00

00

00

00

034

,029

,433

34,0

29,

433

55

Rai

lway

tra

nsp

ort

67,

289,3

750

3,965

,600

303,

623

11,0

01,1

74

630

,799

83,1

90,

571

154

,582,

397

00

00

00

00

00

154,5

82,3

97

154

,582,

397

56

Road

tra

nsp

ort

10,

709,2

440

1,328

,733

220,

048

5,9

41,4

14

16,3

99,2

02

34,5

98,

641

53,7

14,1

160

00

00

00

00

053

,714

,116

53,7

14,

116

57

Wat

er

tran

sport

27,

455,0

740

205,

692

27,

712

814

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7,1

50,2

22

35,6

52,

723

52,0

46,0

570

00

00

00

00

052

,046

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52,0

46,

057

58

Air t

ransp

ort

8,

495,6

990

878,

319

64,

011

2,6

08,0

94

5,3

44,1

81

17,3

90,

304

38,3

59,2

700

00

00

00

00

038

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38,3

59,

270

59

Serv

ices

allie

d t

o t

ransp

ort

44,

844,0

930

00

09,2

75,7

19

54,1

19,

812

95,0

54,7

750

00

00

00

00

095

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95,0

54,7

75

60

Com

munic

atio

n

43,

579,5

250

00

02,7

78,9

69

46,3

58,

494

134

,524,

193

00

00

00

00

00

134,5

24,1

93

134

,524,

193

61

Fin

ancia

l in

term

edia

ries

64,

775,2

670

00

01,3

19,4

19

66,0

94,

686

138

,183,

898

00

00

00

00

00

138,1

83,8

98

138

,183,

898

62

Real

est

ate a

nd b

usi

ness

serv

ice

9,36

2,2

4113

6,9

18,8

241,

152

,219

00

15,4

71,0

42

162,

904,

326

224

,303,

749

00

00

00

00

00

224,3

03,7

49

224

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749

63

Genera

! go

vern

ment

and d

efe

nse

83

8,8

7058

,306

,542

00

03,4

55,9

28

62,6

01,

340

62,6

01,3

830

00

00

00

00

062

,601,3

83

62,6

01,3

83

64

Socia

l an

d c

om

munity,

serv

ices

83,

971,8

6225

,643

,414

710,

124

00

10,3

61,8

26

120,

687,

226

135

,305,

175

00

00

00

00

00

135,3

05,1

75

135

,305,

175

65

Oth

er

serv

ices

85,

131,5

870

7,875

,153

00

7,2

86,9

16

100,

293,

656

188

,019,

186

00

00

00

00

00

188,0

19,1

86

188

,019,

186

66

Unsp

ecifie

d s

ecto

r -93

7,9

250

01

12,2

32

0-9

25,

692

2,36

6,3

160

00

00

00

00

02,3

66,3

16

2,36

6,31

6190

Tota

l in

term

edia

te input

1,6

02,

950,0

0522

0,8

68,7

8061

9,374

,339

23,5

96,

012

872,8

23,1

28

104,2

82,3

39

3,44

3,89

4,60

35,6

88,2

74,2

830

00

00

00

00

05,

688,2

74,2

83

5,6

88,2

74,2

83200

Import

inte

rmedia

te input

182,

640,9

934,1

11,

760

73,

682

,617

12,6

93,

193

00

273,

128,

563

840

,131,

528

659,0

50,

847

47,3

42,3

3214,

920,6

87161

,027,

356

-42,2

09,6

94840

,131

,528

00

00

0840

,131,

528

201

Wag

e a

nd s

alar

y 0

00

00

00

00

00

00

00

00

00

0202

Opera

ting

surp

lus

00

00

00

00

00

00

00

00

00

00

203

Depre

cia

tion

00

00

00

00

00

00

00

00

00

00

204

Indirect

tax

00

00

00

00

00

00

00

00

00

00

205

Subsi

dy

00

00

00

00

00

00

00

00

00

00

209

Gro

ss v

alue a

dded

00

00

00

00

00

00

00

00

00

00

210

Tota

l in

put

00

00

00

00

00

00

00

00

00

00

Tabl

e A

2-1(

4)

Inp

ut O

utpu

t Tab

le o

f 47

Sect

ors (

Dom

estic

Tab

le) (

cont

inue

d)

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

G

eoth

erm

al E

nerg

y D

evel

opm

ent i

n th

e R

epub

lic o

f Ind

ones

ia

Fina

l Rep

ort

JIC

A

W

est J

EC

AN

NEX

-2-5

Secto

r1

23

23

24

25

26

27

28

29

30

31

32

33

34

35

A

gric

ulture

Liv

est

ock

Fore

stFis

hery

C

oal and m

eCru

de o

il, n

atO

ther

min

inM

anufa

ctu

reM

anufa

ctu

reR

ice m

illin

g M

anufa

ctu

reS

uga

r fa

ctM

anufa

ctu

reM

anufa

ctu

Man

ufa

ctu

reYar

n s

pin

nin

1A

gric

ulture

0.0

77249

0.0

08618

0.0

18720

0.0

03132

0.0

00000

0.0

00000

0.0

00000

0.0

41688

0.2

42384

0.6

86548

0.0

81325

0.5

48979

0.2

11407

0.1

03399

0.0

56450

0.0

02419

2Liv

est

ock

0.0

09441

0.1

74295

0.0

00000

0.0

00168

0.0

00000

0.0

00000

0.0

00000

0.0

18819

0.0

00000

0.0

00000

0.0

11894

0.0

00000

0.0

01613

0.0

01742

0.0

00000

0.0

00031

3Fore

st0.0

00155

0.0

00060

0.0

13150

0.0

00504

0.0

00079

0.0

00000

0.0

01050

0.0

00814

0.0

01347

0.0

00000

0.0

00000

0.0

00153

0.0

01781

0.0

00000

0.0

00007

0.0

00000

23

Fis

hery

0.0

00007

0.0

00000

0.0

00000

0.0

32909

0.0

00000

0.0

00000

0.0

00000

0.2

59733

0.0

00009

0.0

00000

0.0

00373

0.0

00000

0.0

02055

0.0

00000

0.0

00000

0.0

00000

24

Coal

and m

eta

l ore

min

ing

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

79330

0.0

00001

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00014

0.0

05111

0.0

00284

0.0

00001

0.0

00023

0.0

00268

25

Cru

de o

il, n

atura

l ga

s an

d g

eo

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

76265

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00083

0.0

01413

0.0

00000

0.0

00000

0.0

02116

26

Oth

er

min

ing

and q

uar

ryin

g 0.0

00000

0.0

00002

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

04771

0.0

00473

0.0

00000

0.0

00000

0.0

00000

0.0

02499

0.0

01654

0.0

00000

0.0

00000

0.0

00000

27

Man

ufa

ctu

re o

f fo

od p

rocess

i n0.0

00000

0.0

00065

0.0

00000

0.0

00615

0.0

00000

0.0

00000

0.0

00000

0.0

75317

0.0

00045

0.0

00000

0.0

08493

0.0

00002

0.0

23688

0.0

11398

0.0

00000

0.0

00000

28

Man

ufa

ctu

re o

f oil

and f

at

0.0

00016

0.0

01275

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

24830

0.3

02877

0.0

00000

0.0

07667

0.0

00001

0.0

32235

0.0

00092

0.0

00000

0.0

00000

29

Ric

e m

illin

g 0.0

00005

0.0

00823

0.0

00000

0.0

00556

0.0

00000

0.0

00000

0.0

00000

0.0

00001

0.0

00000

0.0

30295

0.0

28736

0.0

00000

0.0

22142

0.0

02736

0.0

00000

0.0

00000

30

Man

ufa

ctu

re o

f flour, a

ll ki

nds

0.0

00000

0.0

00005

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

03498

0.0

00016

0.0

00000

0.2

09438

0.0

08705

0.0

28693

0.0

02180

0.0

00041

0.0

04127

31

Suga

r fa

cto

ry

0.0

00000

0.0

00004

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

23598

0.0

00000

0.0

00000

0.0

25030

0.0

09661

0.0

32185

0.0

81918

0.0

00098

0.0

00000

32

Man

ufa

ctu

re o

f oth

er

food p

r o0.0

01238

0.1

50601

0.0

00000

0.0

45125

0.0

00000

0.0

00000

0.0

00000

0.0

19845

0.0

00080

0.0

00000

0.0

25852

0.0

00853

0.0

95061

0.0

73336

0.0

00123

0.0

00132

33

Man

ufa

ctu

re o

f beve

rage

s 0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00043

0.0

00000

0.0

00000

0.0

01972

0.0

00108

0.0

00159

0.0

18775

0.0

00000

0.0

00000

34

Man

ufa

ctu

re o

f cig

arett

es

0.0

00004

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

44728

0.0

00000

35

Yar

n s

pin

nin

g 0.0

00000

0.0

00000

0.0

00000

0.0

00012

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00069

0.0

00000

0.0

00000

0.0

00000

0.0

00017

0.0

00000

0.0

00000

0.1

27959

36

Man

ufa

ctu

re o

f te

xtile

, w

ear

in0.0

01086

0.0

00012

0.0

01356

0.0

00043

0.0

00630

0.0

00017

0.0

00274

0.0

00667

0.0

00000

0.0

00372

0.0

00144

0.0

00533

0.0

00044

0.0

00025

0.0

00001

0.0

13602

37

Man

ufa

ctu

re o

f bam

boo, w

ood

0.0

00254

0.0

00020

0.0

00000

0.0

00480

0.0

00000

0.0

00000

0.0

00647

0.0

00491

0.0

00040

0.0

00024

0.0

00180

0.0

00439

0.0

00307

0.0

02032

0.0

00134

0.0

00366

38

Man

ufa

ctu

re o

f pap

er, p

aper

p0.0

00320

0.0

00088

0.0

02641

0.0

00215

0.0

00699

0.0

00169

0.0

00609

0.0

01980

0.0

00007

0.0

00037

0.0

01788

0.0

00109

0.0

02820

0.0

17728

0.0

28943

0.0

03416

39

Man

ufa

ctu

re o

f fe

rtili

zer

and p

0.0

47479

0.0

00000

0.0

00156

0.0

00438

0.0

00003

0.0

00000

0.0

00052

0.0

00000

0.0

00000

0.0

00000

0.0

00009

0.0

00732

0.0

00759

0.0

00110

0.0

00009

0.0

00016

40

Man

ufa

ctu

re o

f chem

icals

0.0

04049

0.0

03580

0.0

00999

0.0

02797

0.0

16736

0.0

00010

0.0

18569

0.0

04787

0.0

03010

0.0

00097

0.0

00748

0.0

01048

0.0

04073

0.0

15786

0.0

07662

0.0

66011

41

Petr

ole

um

refinery

0.0

02663

0.0

01229

0.0

03460

0.0

19852

0.0

06948

0.0

00131

0.0

31363

0.0

06242

0.0

03350

0.0

01282

0.0

04135

0.0

15655

0.0

09276

0.0

09869

0.0

17734

0.0

01765

42

Man

ufa

ctu

re o

f ru

bber

and p

l a0.0

00216

0.0

00280

0.0

00006

0.0

02162

0.0

00000

0.0

00000

0.0

00412

0.0

03490

0.0

00057

0.0

00849

0.0

01151

0.0

02344

0.0

04079

0.0

06185

0.0

12018

0.0

00162

43

Man

ufa

ctu

re o

f non m

eta

llic m

0.0

00005

0.0

00004

0.0

00003

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

02033

0.0

00003

0.0

00000

0.0

00015

0.0

00087

0.0

00144

0.0

02850

0.0

00000

0.0

00000

44

Man

ufa

ctu

re o

f cem

ent

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

45

Man

ufa

ctu

re o

f bas

ic iro

n a

nd

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

46

Man

ufa

ctu

re o

f nonfe

rrous

ba

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00013

0.0

00003

0.0

00000

0.0

00000

0.0

00103

0.0

00092

0.0

00000

0.0

00000

0.0

00000

47

Man

ufa

ctu

re o

f fa

bricat

ed m

et

0.0

01431

0.0

00029

0.0

04564

0.0

00153

0.0

00014

0.0

00000

0.0

01640

0.0

03721

0.0

00012

0.0

00011

0.0

00016

0.0

00002

0.0

00109

0.0

01022

0.0

00000

0.0

00009

48

Man

ufa

ctu

re o

f m

achin

e, ele

ct

0.0

01725

0.0

00119

0.0

26510

0.0

02480

0.0

37265

0.0

02438

0.0

08979

0.0

03924

0.0

00008

0.0

00891

0.0

00154

0.0

13698

0.0

00058

0.0

00050

0.0

01683

0.0

01395

49

Man

ufa

ctu

re o

f tr

ansp

ort

equi

0.0

00001

0.0

00000

0.0

00000

0.0

03893

0.0

00000

0.0

00006

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

50

Man

ufa

ctu

re o

f oth

er

pro

duct

0.0

00004

0.0

00021

0.0

01334

0.0

00017

0.0

00050

0.0

00000

0.0

00018

0.0

02303

0.0

00119

0.0

00400

0.0

00237

0.0

00451

0.0

00275

0.0

00562

0.0

00100

0.0

00015

51

Ele

ctr

icity,

gas

and w

ater

supp

0.0

00118

0.0

01326

0.0

00881

0.0

01320

0.0

01766

0.0

00033

0.0

00752

0.0

06775

0.0

00988

0.0

00602

0.0

05461

0.0

05287

0.0

02966

0.0

12040

0.0

02617

0.0

48141

52

Const

ruction

0.0

11418

0.0

00199

0.0

16374

0.0

02646

0.0

17265

0.0

00167

0.0

44288

0.0

00494

0.0

00199

0.0

00004

0.0

00674

0.0

00576

0.0

00789

0.0

00384

0.0

00088

0.0

00094

53

Tra

de

0.0

14998

0.0

59986

0.0

13845

0.0

33546

0.0

14252

0.0

00686

0.0

20908

0.1

10573

0.0

39889

0.0

38650

0.0

61921

0.0

56962

0.0

81633

0.0

78749

0.0

31531

0.0

49954

54

Rest

aura

nt

and h

ote

l 0.0

00104

0.0

00100

0.0

00208

0.0

00077

0.0

00709

0.0

00111

0.0

01662

0.0

00212

0.0

00292

0.0

00043

0.0

00545

0.0

00099

0.0

00470

0.0

03331

0.0

01244

0.0

00667

55

Railw

ay t

ransp

ort

0.0

06916

0.0

09603

0.0

07240

0.0

04680

0.0

09502

0.0

00108

0.0

09738

0.0

18113

0.0

07087

0.0

05530

0.0

10210

0.0

08501

0.0

15010

0.0

14985

0.0

16125

0.0

20052

56

Road

tra

nsp

ort

0.0

01284

0.0

04281

0.0

06181

0.0

03741

0.0

03071

0.0

00060

0.0

00967

0.0

07446

0.0

02944

0.0

02516

0.0

04134

0.0

03833

0.0

06361

0.0

05039

0.0

04006

0.0

04384

57

Wat

er

tran

sport

0.0

00371

0.0

00712

0.0

03514

0.0

00439

0.0

04067

0.0

00201

0.0

01599

0.0

01534

0.0

00459

0.0

00378

0.0

01063

0.0

00732

0.0

01452

0.0

01738

0.0

02698

0.0

00913

58

Air t

ransp

ort

0.0

00638

0.0

01934

0.0

01624

0.0

01140

0.0

00808

0.0

00036

0.0

00996

0.0

04067

0.0

01346

0.0

01253

0.0

02019

0.0

01967

0.0

03243

0.0

04756

0.0

02811

0.0

03449

59

Serv

ices

allie

d t

o t

ransp

ort

0.0

00185

0.0

00411

0.0

00342

0.0

00024

0.0

04082

0.0

00006

0.0

00831

0.0

01841

0.0

01082

0.0

00605

0.0

04124

0.0

00756

0.0

02599

0.0

05425

0.0

00765

0.0

03296

60

Com

munic

atio

n

0.0

11592

0.0

02154

0.0

05647

0.0

03024

0.0

04886

0.0

00483

0.0

04084

0.0

12514

0.0

23943

0.0

01162

0.0

06383

0.0

13940

0.0

10099

0.0

07205

0.0

20690

0.0

12176

61

Fin

ancia

l in

term

edia

ries

0.0

02340

0.0

00233

0.0

02461

0.0

01690

0.0

05311

0.0

01009

0.0

06887

0.0

01623

0.0

01941

0.0

00057

0.0

01157

0.0

00574

0.0

01677

0.0

02106

0.0

02319

0.0

08351

62

Real

est

ate a

nd b

usi

ness

ser v

0.0

03400

0.0

01096

0.0

07754

0.0

00362

0.0

02976

0.0

00604

0.0

09066

0.0

01499

0.0

03020

0.0

00045

0.0

00846

0.0

02619

0.0

02166

0.0

02796

0.0

21501

0.0

09407

63

Genera

! go

vern

ment

and d

efe

n0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

64

Socia

l and c

om

munity,

serv

ice

0.0

00071

0.0

00209

0.0

00000

0.0

00306

0.0

00411

0.0

00127

0.0

00538

0.0

01118

0.0

00662

0.0

00014

0.0

00542

0.0

00613

0.0

00638

0.0

01400

0.0

00454

0.0

02528

65

Oth

er

serv

ices

0.0

06290

0.0

00915

0.0

12597

0.0

00146

0.0

17702

0.0

00603

0.0

21013

0.0

07077

0.0

04836

0.0

02831

0.0

04819

0.0

16822

0.0

04444

0.0

70529

0.0

19526

0.0

01873

66

Unsp

ecifie

d s

ecto

r 0.0

00029

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00014

0.0

00000

0.0

00000

0.0

00003

0.0

00000

0.0

00101

0.0

02230

0.0

04997

0.0

00033

Tabl

e A

2-2

(1)

Inpu

t Coe

ffici

ents

(47

sect

ors)

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

G

eoth

erm

al E

nerg

y D

evel

opm

ent i

n th

e R

epub

lic o

f Ind

ones

ia

Fina

l Rep

ort

JIC

A

W

est J

EC

AN

NEX

-2-6

Secto

r36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

M

anufa

ctu

re M

anufa

ctu

reM

anufa

ctu

reM

anufa

ctu

Man

ufa

ctu

reP

etr

ole

um

re

Man

ufa

ctu

reM

anufa

ctu

reM

anufa

ctu

Man

ufa

ctu

reM

anufa

ctu

reM

anufa

ctu

reM

anufa

ctu

re M

anufa

ctu

reM

anufa

ctu

reEle

ctr

icity,

g1

Agr

iculture

0.0

09619

0.0

00313

0.0

02375

0.0

00186

0.0

27097

0.0

00000

0.1

4094

80.0

00821

0.0

00000

0.0

00000

0.0

00000

0.0

00007

0.0

00001

0.0

0000

00.0

05657

0.0

00000

2Liv

est

ock

0.0

13426

0.0

00000

0.0

00000

0.0

00006

0.0

00385

0.0

00000

0.0

0000

30.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00001

0.0

00000

0.0

0000

00.0

03024

0.0

00000

3Fore

st0.0

00321

0.1

22984

0.0

11004

0.0

00024

0.0

01638

0.0

00000

0.0

0000

10.0

01310

0.0

00000

0.0

00000

0.0

00000

0.0

00115

0.0

00001

0.0

0016

20.0

06881

0.0

00000

23

Fis

hery

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00070

0.0

00000

0.0

0000

00.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

0000

00.0

09117

0.0

00000

24

Coal

and m

eta

l ore

min

ing

0.0

01057

0.0

00396

0.0

00621

0.0

00229

0.0

46292

0.0

00000

0.0

0082

80.0

10467

0.1

74236

0.0

09305

0.5

13807

0.0

11568

0.0

00108

0.0

0010

80.0

00255

0.0

66877

25

Cru

de o

il, n

atura

l ga

s an

d g

eo

0.0

00000

0.0

00000

0.0

01145

0.4

60171

0.1

35422

0.1

85748

0.0

3562

40.0

00599

0.0

80632

0.1

15183

0.0

00000

0.0

06517

0.0

00005

0.0

0000

00.0

00000

0.0

74421

26

Oth

er

min

ing

and q

uar

ryin

g 0.0

00000

0.0

00000

0.0

00131

0.0

15650

0.0

01085

0.0

00001

0.0

0001

60.0

51587

0.0

51741

0.0

00000

0.0

00000

0.0

00023

0.0

00017

0.0

0000

00.0

05690

0.0

00000

27

Man

ufa

ctu

re o

f fo

od p

rocess

in0.0

00007

0.0

00000

0.0

00000

0.0

00000

0.0

00036

0.0

00000

0.0

0000

00.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

0000

00.0

00090

0.0

00000

28

Man

ufa

ctu

re o

f oil

and f

at

0.0

00000

0.0

00054

0.0

00000

0.0

00002

0.0

07586

0.0

00000

0.0

0000

00.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

0000

00.0

00015

0.0

00000

29

Ric

e m

illin

g 0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00717

0.0

00000

0.0

0000

00.0

00026

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

0000

00.0

00000

0.0

00000

30

Man

ufa

ctu

re o

f flour, a

ll ki

nds

0.0

02331

0.0

02887

0.0

02908

0.0

01094

0.0

00163

0.0

00000

0.0

0000

70.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

0000

00.0

00501

0.0

00000

31

Suga

r fa

cto

ry

0.0

00000

0.0

00000

0.0

00000

0.0

00002

0.0

01009

0.0

00000

0.0

0000

00.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

0000

00.0

00000

0.0

00000

32

Man

ufa

ctu

re o

f oth

er

food p

ro0.0

01217

0.0

00000

0.0

00000

0.0

00000

0.0

01217

0.0

00000

0.0

0000

10.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00100

0.0

0000

00.0

00000

0.0

00000

33

Man

ufa

ctu

re o

f beve

rage

s 0.0

00000

0.0

00000

0.0

00000

0.0

00002

0.0

00072

0.0

00000

0.0

0000

00.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

0000

00.0

00000

0.0

00000

34

Man

ufa

ctu

re o

f cig

arett

es

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

0000

00.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

0000

00.0

00000

0.0

00000

35

Yar

n s

pin

nin

g 0.1

30282

0.0

00555

0.0

00128

0.0

00036

0.0

00263

0.0

00000

0.0

0478

20.0

00354

0.0

00234

0.0

00000

0.0

00000

0.0

01239

0.0

00260

0.0

0000

10.0

01090

0.0

00000

36

Man

ufa

ctu

re o

f te

xtile

, w

ear

in0.1

79588

0.0

03441

0.0

00404

0.0

00230

0.0

00583

0.0

00000

0.0

0335

20.0

00545

0.0

00000

0.0

00004

0.0

00009

0.0

02285

0.0

01393

0.0

0163

30.0

16029

0.0

00136

37

Man

ufa

ctu

re o

f bam

boo, w

ood

0.0

00397

0.1

40061

0.0

00861

0.0

00200

0.0

00411

0.0

00003

0.0

0037

00.0

00989

0.0

00000

0.0

00000

0.0

00000

0.0

11720

0.0

01131

0.0

0115

50.0

31329

0.0

00000

38

Man

ufa

ctu

re o

f pap

er, p

aper

p0.0

04262

0.0

02102

0.2

37434

0.0

02578

0.0

04886

0.0

00004

0.0

0366

30.0

04402

0.0

04048

0.0

00574

0.0

00324

0.0

01522

0.0

04511

0.0

0075

20.0

05304

0.0

02157

39

Man

ufa

ctu

re o

f fe

rtili

zer

and p

0.0

00009

0.0

00253

0.0

00013

0.0

01549

0.0

00448

0.0

00000

0.0

0016

60.0

00181

0.0

00250

0.0

00000

0.0

00000

0.0

00092

0.0

00129

0.0

0000

00.0

00066

0.0

00000

40

Man

ufa

ctu

re o

f chem

ical

s 0.0

30825

0.0

30028

0.0

47877

0.0

05425

0.0

39249

0.0

00227

0.0

9249

10.0

23178

0.0

00585

0.0

11160

0.0

00915

0.0

49205

0.0

24713

0.0

0346

00.0

26399

0.0

13480

41

Petr

ole

um

refinery

0.0

09692

0.0

07484

0.0

15967

0.0

05776

0.0

09325

0.0

16572

0.0

2536

10.0

83393

0.0

36445

0.0

60866

0.0

15719

0.0

29751

0.0

05987

0.0

0440

50.0

11763

0.2

03106

42

Man

ufa

ctu

re o

f ru

bber

and p

la0.0

08263

0.0

03097

0.0

03250

0.0

01193

0.0

02433

0.0

00079

0.0

6255

50.0

00349

0.0

00040

0.0

00771

0.0

00088

0.0

05675

0.0

24407

0.0

0891

60.0

34251

0.0

00004

43

Man

ufa

ctu

re o

f non m

eta

llic m

0.0

00035

0.0

02522

0.0

00031

0.0

00392

0.0

00995

0.0

00003

0.0

0057

50.0

12193

0.0

00484

0.0

00001

0.0

00017

0.0

02487

0.0

02577

0.0

0084

40.0

21543

0.0

00086

44

Man

ufa

ctu

re o

f cem

ent

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

0000

00.0

19556

0.0

01792

0.0

00000

0.0

00000

0.0

00095

0.0

00012

0.0

0000

00.0

01098

0.0

00000

45

Man

ufa

ctu

re o

f bas

ic iro

n a

nd

0.0

00091

0.0

00037

0.0

00001

0.0

00000

0.0

00000

0.0

00001

0.0

0001

00.0

03171

0.0

00000

0.0

69950

0.0

00738

0.0

71830

0.0

05072

0.0

1711

50.0

13372

0.0

00000

46

Man

ufa

ctu

re o

f nonfe

rrous

ba

0.0

00151

0.0

00363

0.0

00758

0.0

00000

0.0

00016

0.0

00001

0.0

0001

90.0

00551

0.0

00000

0.0

02751

0.0

66925

0.0

45595

0.0

05857

0.0

0343

70.0

44412

0.0

00000

47

Man

ufa

ctu

re o

f fa

bricat

ed m

et

0.0

01673

0.0

03379

0.0

01182

0.0

00088

0.0

00033

0.0

00185

0.0

0258

80.0

08245

0.0

00000

0.0

01619

0.0

01468

0.0

21925

0.0

11438

0.0

0981

30.0

23441

0.0

00376

48

Man

ufa

ctu

re o

f m

achin

e, ele

ct

0.0

12582

0.0

13440

0.0

06658

0.0

00650

0.0

04598

0.0

01121

0.0

1028

60.0

18566

0.0

00000

0.0

07815

0.0

03177

0.0

06667

0.1

36935

0.0

1430

10.0

15984

0.0

15843

49

Man

ufa

ctu

re o

f tr

ansp

ort

equi

0.0

00000

0.0

00001

0.0

00000

0.0

00000

0.0

00000

0.0

00010

0.0

0000

00.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00812

0.0

00000

0.1

8798

00.0

00000

0.0

00000

50

Man

ufa

ctu

re o

f oth

er

pro

duct

0.0

00691

0.0

01228

0.0

00197

0.0

00007

0.0

00217

0.0

00003

0.0

0127

60.0

01400

0.0

00017

0.0

00138

0.0

00037

0.0

00936

0.0

01659

0.0

0111

80.0

10447

0.0

00014

51

Ele

ctr

icity,

gas

and w

ater

supp

0.0

20996

0.0

11944

0.0

18255

0.0

03339

0.0

08970

0.0

00221

0.0

1142

30.0

23568

0.0

85928

0.0

65666

0.0

08761

0.0

20611

0.0

09613

0.0

0769

00.0

28508

0.1

51912

52

Const

ruction

0.0

02846

0.0

00446

0.0

00240

0.0

00143

0.0

01925

0.0

00213

0.0

0045

80.0

06139

0.0

04744

0.0

00590

0.0

03236

0.0

02925

0.0

01655

0.0

0098

80.0

00825

0.0

09539

53

Tra

de

0.0

47382

0.0

74826

0.0

59694

0.0

20093

0.0

41270

0.0

01348

0.0

5783

90.0

49342

0.0

35623

0.0

51750

0.0

13374

0.0

59518

0.0

71416

0.0

4666

30.0

58317

0.0

35957

54

Rest

aura

nt

and h

ote

l 0.0

01757

0.0

00289

0.0

01064

0.0

00403

0.0

01269

0.0

00328

0.0

0054

30.0

01179

0.0

03741

0.0

02981

0.0

01336

0.0

00437

0.0

00765

0.0

0139

10.0

01945

0.0

00421

55

Rai

lway

tra

nsp

ort

0.0

13188

0.0

27868

0.0

26101

0.0

05041

0.0

11287

0.0

00498

0.0

1212

80.0

19908

0.0

11734

0.0

13847

0.0

06721

0.0

14414

0.0

20273

0.0

0971

90.0

24549

0.0

06423

56

Road

tra

nsp

ort

0.0

04818

0.0

09415

0.0

05090

0.0

01792

0.0

03367

0.0

00117

0.0

0561

80.0

06690

0.0

04068

0.0

04653

0.0

01422

0.0

05338

0.0

06649

0.0

0342

00.0

09033

0.0

02333

57

Wat

er

tran

sport

0.0

01235

0.0

02580

0.0

01046

0.0

00745

0.0

01401

0.0

00128

0.0

0124

80.0

02076

0.0

02298

0.0

02540

0.0

01229

0.0

01528

0.0

01688

0.0

0095

60.0

03110

0.0

00913

58

Air t

ransp

ort

0.0

02796

0.0

05739

0.0

02371

0.0

01352

0.0

01946

0.0

00067

0.0

0300

20.0

04214

0.0

01431

0.0

05065

0.0

01157

0.0

03583

0.0

04023

0.0

0174

90.0

03804

0.0

01080

59

Serv

ices

allie

d t

o t

ransp

ort

0.0

03634

0.0

01690

0.0

04783

0.0

06302

0.0

07569

0.0

00127

0.0

0379

40.0

08706

0.0

07606

0.0

01383

0.0

05630

0.0

06420

0.0

04494

0.0

0193

40.0

05003

0.0

01092

60

Com

munic

atio

n

0.0

13063

0.0

17940

0.0

17379

0.0

05543

0.0

10023

0.0

01787

0.0

1586

50.0

14923

0.0

10693

0.0

05421

0.0

04051

0.0

16201

0.0

05596

0.0

0868

70.0

19952

0.0

08454

61

Fin

ancia

l in

term

edia

ries

0.0

05466

0.0

00985

0.0

03945

0.0

04601

0.0

05274

0.0

00595

0.0

0371

70.0

03144

0.0

02419

0.0

06629

0.0

01686

0.0

04551

0.0

02772

0.0

0220

80.0

04866

0.0

03187

62

Real

est

ate a

nd b

usi

ness

serv

0.0

06763

0.0

11612

0.0

04954

0.0

03619

0.0

05511

0.0

01314

0.0

0310

80.0

08951

0.0

02181

0.0

12590

0.0

03719

0.0

14004

0.0

19126

0.0

1348

90.0

13004

0.0

15810

63

Genera

! go

vern

ment

and d

efe

n0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

0000

00.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

0000

00.0

00000

0.0

00000

64

Socia

l an

d c

om

munity,

serv

ice

0.0

01093

0.0

00442

0.0

04229

0.0

00696

0.0

04538

0.0

00009

0.0

0069

50.0

01031

0.0

03284

0.0

00633

0.0

16482

0.0

00263

0.0

00578

0.0

0212

70.0

01916

0.0

00678

65

Oth

er

serv

ices

0.0

06667

0.0

13889

0.0

06502

0.0

01201

0.0

15801

0.0

01582

0.0

0428

90.0

09096

0.0

05849

0.0

03202

0.0

14106

0.0

07806

0.0

11188

0.0

0318

70.0

04424

0.0

01238

66

Unsp

ecifie

d s

ecto

r 0.0

00314

0.0

00537

0.0

01674

0.0

00002

0.0

00549

0.0

00015

0.0

0333

70.0

00665

0.0

00000

0.0

10651

0.0

02297

0.0

00850

0.0

00270

0.0

0000

70.0

02470

0.0

00000

Tabl

e A

2-2

(2)

Inpu

t Coe

ffici

ents

(47

sect

ors)

(con

tinue

d)

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

G

eoth

erm

al E

nerg

y D

evel

opm

ent i

n th

e R

epub

lic o

f Ind

ones

ia

Fina

l Rep

ort

JIC

A

W

est J

EC

AN

NEX

-2-7

Secto

r52

53

54

55

56

57

58

59

60

61

62

63

64

65

66

C

onst

ruction

Tra

de

Rest

aura

nt

Rai

lway

tr a

Road

tra

nsp

Wat

er

tran

sA

ir t

ransp

orS

erv

ices

allC

om

munic

aFin

ancia

l in

tReal

est

ate G

enera

! go

vSocia

l an

d c

Oth

er

serv

icU

nsp

ecifie

1A

gric

ulture

0.0

0000

00.0

1683

20.0

2351

30.

0000

030.

0006

370.

0000

020.

0000

000.

0000

00

0.0

00000

0.0

00000

0.0

00059

0.0

03190

0.0

52389

0.0

02702

0.1

54094

2Liv

est

ock

0.0

0000

00.0

3377

30.0

5878

50.

0000

420.

0006

640.

0000

430.

0000

000.

0000

00

0.0

00000

0.0

00000

0.0

00001

0.0

00000

0.0

16790

0.0

00636

0.0

00000

3Fore

st0.0

1599

90.0

0010

30.0

0041

60.

0000

000.

0000

000.

0000

000.

0000

000.

0000

00

0.0

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0.0

00000

0.0

00040

0.0

00053

0.0

00049

0.0

00750

0.0

00000

23

Fis

hery

0.0

0000

00.0

0684

50.0

0962

30.

0000

000.

0002

830.

0000

240.

0000

000.

0000

00

0.0

00000

0.0

00000

0.0

00242

0.0

00000

0.0

05718

0.0

00000

0.0

00000

24

Coal

and m

eta

l ore

min

ing

0.0

0000

00.0

0000

00.0

0085

80.

0000

000.

0000

000.

0000

000.

0000

000.

0000

00

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

25

Cru

de o

il, n

atura

l ga

s an

d g

eo

0.0

0000

70.0

0000

00.0

0000

00.

0000

000.

0000

000.

0000

000.

0000

000.

0000

00

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

26

Oth

er

min

ing

and q

uar

ryin

g 0.0

5333

60.0

0001

40.0

0000

00.

0000

000.

0000

000.

0000

000.

0000

000.

0000

00

0.0

00000

0.0

00000

0.0

00000

0.0

05038

0.0

02648

0.0

00000

0.0

00000

27

Man

ufa

ctu

re o

f fo

od p

rocess

in0.0

0000

00.0

1252

20.0

2087

80.

0000

000.

0042

890.

0001

070.

0000

000.

0000

00

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

03743

0.0

00000

0.0

00000

28

Man

ufa

ctu

re o

f oil

and f

at

0.0

0000

00.0

0382

50.0

0294

10.

0000

000.

0003

830.

0000

160.

0000

000.

0000

00

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00270

0.0

00022

0.0

00000

29

Ric

e m

illin

g 0.0

0000

00.0

1769

40.0

2589

20.

0000

000.

0030

640.

0002

210.

0000

000.

0000

00

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

39012

0.0

00000

0.0

00000

30

Man

ufa

ctu

re o

f flour, a

ll ki

nds

0.0

0000

00.0

0493

70.0

1286

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0000

000.

0070

690.

0003

100.

0001

970.

0000

82

0.0

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0.0

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0.0

00000

0.0

00000

0.0

01850

0.0

00111

0.0

00000

31

Suga

r fa

cto

ry

0.0

0000

00.0

0135

30.0

1008

00.

0000

000.

0022

110.

0000

530.

0000

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0000

00

0.0

00000

0.0

00000

0.0

00000

0.0

00000

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01838

0.0

00046

0.0

00000

32

Man

ufa

ctu

re o

f oth

er

food p

ro0.0

0000

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10.0

3028

90.

0001

260.

0042

050.

0005

560.

0000

800.

0000

00

0.0

00062

0.0

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0.0

00274

0.0

00000

0.0

13777

0.0

13168

0.0

00000

33

Man

ufa

ctu

re o

f beve

rage

s 0.0

0000

00.0

0158

80.0

1332

00.

0000

000.

0025

320.

0018

190.

0009

750.

0000

00

0.0

00654

0.0

02077

0.0

00000

0.0

00000

0.0

00145

0.0

00515

0.0

00000

34

Man

ufa

ctu

re o

f cig

arett

es

0.0

0000

00.0

0504

40.0

0330

40.

0000

000.

0009

960.

0008

720.

0000

000.

0000

00

0.0

00000

0.0

00004

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

35

Yar

n s

pin

nin

g 0.0

0000

50.0

0000

00.0

0000

00.

0000

000.

0000

000.

0000

000.

0000

000.

0000

00

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00119

0.0

00011

0.0

00000

36

Man

ufa

ctu

re o

f te

xtile

, w

ear

in0.0

0023

80.0

0624

40.0

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80.

0013

200.

0019

330.

0004

890.

0022

490.

0007

26

0.0

00190

0.0

00874

0.0

03465

0.0

04321

0.0

04479

0.0

06535

0.0

01535

37

Man

ufa

ctu

re o

f bam

boo, w

ood

0.0

3368

40.0

0138

60.0

0004

70.

0000

500.

0000

000.

0000

290.

0003

620.

0000

27

0.0

00013

0.0

00033

0.0

00135

0.0

00963

0.0

00336

0.0

00420

0.0

01051

38

Man

ufa

ctu

re o

f pap

er, p

aper

p0.0

0222

40.0

1140

60.0

0395

60.

0029

860.

0013

310.

0032

540.

0032

780.

0078

11

0.0

11798

0.0

04109

0.0

19186

0.1

61561

0.0

28749

0.0

01425

0.0

01499

39

Man

ufa

ctu

re o

f fe

rtili

zer

and p

0.0

0000

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0004

40.0

0038

10.

0000

500.

0000

640.

0000

110.

0000

100.

0000

00

0.0

00000

0.0

00003

0.0

00528

0.0

00270

0.0

00224

0.0

00383

0.0

00000

40

Man

ufa

ctu

re o

f chem

ical

s 0.0

0584

60.0

0223

80.0

0366

40.

0020

470.

0029

540.

0007

990.

0010

310.

0001

07

0.0

00930

0.0

00519

0.0

05499

0.0

27783

0.0

54027

0.0

06202

0.0

01970

41

Petr

ole

um

refinery

0.0

4422

90.0

1530

90.0

2206

20.

1689

630.

1863

390.

0743

330.

0037

790.

0022

62

0.0

01290

0.0

01472

0.0

04512

0.0

05372

0.0

05529

0.0

01172

0.0

11992

42

Man

ufa

ctu

re o

f ru

bber

and p

la0.0

1318

60.0

0611

60.0

0019

40.

0124

350.

0001

830.

0180

510.

0061

300.

0002

91

0.0

03434

0.0

00586

0.0

02244

0.0

01852

0.0

03285

0.0

73926

0.1

98649

43

Man

ufa

ctu

re o

f non m

eta

llic m

0.0

3453

90.0

0036

50.0

0069

40.

0000

750.

0000

420.

0000

140.

0000

090.

0000

25

0.0

00014

0.0

00056

0.0

00863

0.0

00550

0.0

00125

0.0

00700

0.0

00000

44

Man

ufa

ctu

re o

f cem

ent

0.0

3355

40.0

0000

00.0

0000

00.

0000

000.

0000

000.

0000

000.

0000

000.

0000

00

0.0

00000

0.0

00000

0.0

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0.0

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0.0

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0.0

00000

0.0

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45

Man

ufa

ctu

re o

f bas

ic iro

n a

nd

0.0

2260

40.0

0000

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0000

00.

0000

000.

0000

000.

0000

000.

0000

000.

0000

00

0.0

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0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

01669

0.0

00000

46

Man

ufa

ctu

re o

f nonfe

rrous

ba

0.0

0632

20.0

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00.0

0000

00.

0000

000.

0000

000.

0000

000.

0000

000.

0000

43

0.0

00000

0.0

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0.0

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0.0

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0.0

00000

0.0

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0.0

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47

Man

ufa

ctu

re o

f fa

bricat

ed m

et

0.0

7604

10.0

0026

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90.

0000

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0001

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0000

560.

0006

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0003

20

0.0

04787

0.0

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0.0

05034

0.0

02166

0.0

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0.0

03809

0.0

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48

Man

ufa

ctu

re o

f m

achin

e, ele

ct

0.0

2307

00.0

0136

00.0

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70.

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610.

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150.

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0076

670.

0081

19

0.0

04637

0.0

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0.0

14181

0.0

05416

0.0

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0.0

20913

0.0

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49

Man

ufa

ctu

re o

f tr

ansp

ort

equi

0.0

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0000

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0000

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440.

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130.

0008

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0.0

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0.0

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0.0

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0.0

88246

0.0

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50

Man

ufa

ctu

re o

f oth

er

pro

duct

0.0

0039

90.0

0055

90.0

0029

20.

0001

490.

0008

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0000

880.

0000

01

0.0

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0.0

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0.0

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51

Ele

ctr

icity,

gas

and w

ater

supp

0.0

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90.0

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30.0

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70.

0028

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740.

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0126

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0.0

06630

0.0

02491

0.0

12346

0.0

08641

0.0

07278

0.0

13264

0.0

04528

52

Const

ruction

0.0

0101

90.0

1315

60.0

1715

80.

0024

680.

0069

140.

0008

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0889

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46

0.0

06802

0.0

62656

0.0

39454

0.0

21749

0.0

08399

0.0

03459

0.0

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53

Tra

de

0.0

8381

90.0

4002

10.0

6254

80.

0316

470.

0589

970.

0727

270.

0067

110.

0046

24

0.0

06787

0.0

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0.0

53107

0.0

40844

0.0

54817

0.0

46622

0.0

42240

54

Rest

aura

nt

and h

ote

l 0.0

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20.0

0153

20.0

0158

60.

0010

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0033

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0029

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0022

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0006

74

0.0

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0.0

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0.0

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0.0

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0.0

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0.0

01975

0.0

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55

Rai

lway

tra

nsp

ort

0.0

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00.0

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20.0

0824

20.

0124

520.

0072

470.

0050

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0041

200.

0024

18

0.0

04129

0.0

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0.0

16669

0.0

13682

0.0

08395

0.0

07905

0.0

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56

Road

tra

nsp

ort

0.0

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90.0

0243

60.0

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00.

0023

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0070

330.

0023

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0030

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0009

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0.0

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00172

0.0

02272

0.0

03039

0.0

03483

0.0

03751

0.0

02643

57

Wat

er

tran

sport

0.0

0152

60.0

0428

90.0

0194

60.

0054

960.

0011

080.

0293

900.

0040

960.

0019

93

0.0

02235

0.0

02283

0.0

21116

0.0

02338

0.0

02057

0.0

01013

0.0

00396

58

Air t

ransp

ort

0.0

0220

10.0

0173

70.0

0318

00.

0095

320.

0770

120.

0629

110.

0408

370.

0008

11

0.0

00223

0.0

00971

0.0

03990

0.0

01434

0.0

01656

0.0

01496

0.0

01180

59

Serv

ices

allie

d t

o t

ransp

ort

0.0

0470

50.0

1520

80.0

0863

00.

0128

540.

0135

280.

0083

160.

0521

460.

0621

53

0.0

15671

0.0

05992

0.0

11442

0.0

05100

0.0

11653

0.0

06266

0.0

06186

60

Com

munic

atio

n

0.0

0771

60.0

2406

60.0

0340

80.

0055

240.

0056

100.

0070

280.

0034

070.

0109

74

0.1

91344

0.0

24704

0.0

19354

0.0

13864

0.0

05172

0.0

05932

0.0

00000

61

Fin

ancia

l in

term

edia

ries

0.0

0470

10.0

4892

80.0

0418

10.

0225

350.

0194

950.

0212

170.

0058

140.

0152

08

0.0

23844

0.0

26932

0.0

21868

0.0

05635

0.0

11004

0.0

29373

0.0

00000

62

Real

est

ate a

nd b

usi

ness

serv

0.0

2586

10.0

1092

30.0

1344

10.

0104

820.

0131

640.

0234

400.

0389

660.

0101

32

0.0

22349

0.0

21341

0.0

08637

0.0

14300

0.0

15835

0.0

06199

0.0

06501

63

Genera

! go

vern

ment

and d

efe

n0.0

0000

00.0

0000

00.0

0000

00.

0000

000.

0000

000.

0000

000.

0000

000.

0000

00

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

64

Socia

l an

d c

om

munity,

serv

ice

0.0

0332

20.0

0105

90.0

0472

70.

0010

350.

0016

770.

0021

220.

0052

210.

0048

65

0.0

03121

0.0

02303

0.0

07594

0.0

13346

0.0

23812

0.0

04914

0.0

00000

65

Oth

er

serv

ices

0.0

0246

90.0

1265

90.0

0509

10.

1974

100.

0084

020.

0091

760.

0315

850.

0154

51

0.0

08502

0.0

10060

0.0

59330

0.0

15607

0.0

10435

0.0

16621

0.0

00000

66

Unsp

ecifie

d s

ecto

r 0.0

0005

00.0

0200

40.0

0000

00.

0000

000.

0000

000.

0000

000.

0000

000.

0000

19

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00000

0.0

00060

0.0

08433

Tabl

e A

2-2

(3)

Inpu

t Coe

ffici

ents

(47

sect

ors)

(con

tinue

d)



ANNEX-3 Impact Analysis of passing through Feed-in Tariff to Consumers

In Chapter 8, it is described that the general electric tariff of PT. PLN will increase by

2.48% when the cost of Feed-in Tariff to purchase geothermal power is passed through to general

consumers, and that this electricity price hike will increase producer’s price and consumer’s price by

0.10% and 0.08% respectively. This Annex shows the calculation process of this impact.

1. Price Analysis by Input-Output Table The electricity price hike impact on the whole sectors of the economy can be analyzed by using

Input-Output Table. In this price analysis case, we use the relations in the vertical direction (column)

of the Input-Output Table. Specifically, the following equations can be formed for the column of

each industry.

nnnnnnn

nn

nn

pvapapap

pvapapappvapapap

=++++

=++++=++++

K

M

K

K

2211

222222121

111212111

(A3.1)

Where, jp ：Producer’s price in the j-th industry,

ija ：Input coefficients

jv ：Value-added ratio of the j-th industry.

In order to analyze the impact of price hike in the k-th industry (i.e. the electricity

industry), the price of the k-th industry should be considered as exogenous. When kp is exogenous,

the equations of (A3.1) are transformed into as follows:

nnknknnnnkknkknn

kkkkkknnkkkkkkkk

kkkkkknnkkkkkkkk

kknnkkkk

kknnkkkk

pvapapapapapap

pvapapapapapappvapapapapapap

pvapapapapapappvapapapapapap

=++++++++

=++++++++

=++++++++

=++++++++

=++++++++

++−−

++++++++−−++

−−−−−++−−−−−

++−−

++−−

)(

)()(

)()(

,11,112211

111,1,1,111,111,221,11

111,1,1,111,111,221,11

22222,112,11222121

11111,111,11212111

LK

M

LK

LK

M

LK

LK

(A3.2)

They can be described as follow using matrix expression:

***** )( pvapAp kkd =++ (A5.3)



Where *p is a row vector consisted of the producer’s price of each industry jp : namely

),,,,,( 1121*

nkk pppppp LL +−= . *dA is a matrix which is made by deleting the k-th row and

the k-th column from the original input coefficient matrix of dA : namely,

=+

+

++

−

−+++

−+−

+

+

−−−−

−

−

nn

nk

kn

kk

knnn

kkkk

nk

n

n

kk

k

k

kkkk

k

k

d

a

a

a

a

aaa

aaaa

aa

a

aa

aaa

aaaaaa

A

M

M

L

M

M

L

M

M

L

MMMM

MMMM

L

M

L

M

L

L

M

L

MMMM

L

L

,1

1,

1,1

1,21

1,12,11,1

,1

2

1

1,1

1,2

1,1

1,12,11,1

1,22221

1,11211

*

*ka is a row vector consisted of the k-th row of the original input coefficient matrix of dA except

the k-th input coefficient itself: namely, ),,,,,( 1,1,21*

knkkkkkkk aaaaaa LL +−= . *v is a row

vector consisted of the value-added ratio of each industry except the k-th industry: namely,

),,,,,( 1121*

nkk vvvvvv LL +−= . kp is a scalar.

From the formula (A3.3), *p can be solved as follow: (I is a unit matrix. ）

1**** ))(( −−+= dkk AIvapp (A3.4)

Therefore, the price change in each industry induced by the price change of kp∆ can be described

as follow:

1*** )( −−∆=∆ dkk AIapp (A3.5) 2. The Impact of Electricity Price Hike on the Whole Economy

In Chapter 8, it is described that the general electric tariff of PT. PLN will increase by

2.48% when the cost of Feed-in Tariff to purchase geothermal power is passed through to general

consumers. In order to analyze this impact, the formula (A3.5) is adapted to the Input Output Table

of 2005 (47 sectors). The electricity, gas and water supply industry (sector No.51) is taken as the

exogenous k-th industry.

The price change in each industry induced by kp∆ =2.48% is shown in Table A3-1 and

Fig. A3-1. Taking the each industry’s weight in the intermediate demand, the price change of each



No. Sector PriceIncrease Rank Producer

Weight

ProducerPriceIncrease

Consumer Weight

ConsumerPriceIncrease

1 Agriculture 0.005% 45 0.08152 0.000% 0.06058 0.000%2 Livestock 0.013% 39 0.01948 0.000% 0.03146 0.000%3 Forest 0.009% 42 0.00805 0.000% 0.00132 0.000%

23 Fishery 0.008% 44 0.00899 0.000% 0.02514 0.000%24 Coal and metal ore mining 0.014% 38 0.01902 0.000% 0.00000 0.000%25 Crude oil, natural gas and geothermal mining 0.001% 47 0.06162 0.000% 0.00000 0.000%26 Other mining and quarrying 0.010% 41 0.01373 0.000% 0.00001 0.000%27 Manufacture of food processing and preserving 0.033% 28 0.00673 0.000% 0.02227 0.001%28 Manufacture of oil and fat 0.011% 40 0.01325 0.000% 0.01252 0.000%29 Rice milling 0.008% 43 0.00925 0.000% 0.05149 0.000%30 Manufacture of flour, all kinds 0.028% 30 0.00701 0.000% 0.01747 0.000%31 Sugar factory 0.023% 33 0.00367 0.000% 0.00630 0.000%32 Manufacture of other food products 0.021% 35 0.01637 0.000% 0.02965 0.001%33 Manufacture of beverages 0.051% 18 0.00097 0.000% 0.00547 0.000%34 Manufacture of cigarettes 0.021% 34 0.00305 0.000% 0.03486 0.001%35 Yarn spinning 0.159% 4 0.01254 0.002% 0.00020 0.000%36 Manufacture of textile, wearing apparel and leather 0.105% 7 0.01662 0.002% 0.03686 0.004%37 Manufacture of bamboo, wood and rattan products 0.052% 16 0.01320 0.001% 0.00515 0.000%38 Manufacture of paper, paper products and cardboard 0.083% 9 0.02699 0.002% 0.00645 0.001%39 Manufacture of fertilizer and pesticide 0.015% 36 0.00743 0.000% 0.00111 0.000%40 Manufacture of chemicals 0.039% 24 0.05494 0.002% 0.02021 0.001%41 Petroleum refinery 0.001% 46 0.06377 0.000% 0.01724 0.000%42 Manufacture of rubber and plastic wares 0.054% 15 0.02134 0.001% 0.02127 0.001%43 Manufacture of non metallic mineral products 0.079% 10 0.00944 0.001% 0.00230 0.000%44 Manufacture of cement 0.223% 3 0.00731 0.002% 0.00000 0.000%45 Manufacture of basic iron and steel 0.226% 2 0.02243 0.005% 0.00000 0.000%46 Manufacture of nonferrous basic metal 0.038% 26 0.00841 0.000% 0.00000 0.000%47 Manufacture of fabricated metal products 0.107% 6 0.02722 0.003% 0.00458 0.000%48 Manufacture of machine, electrical machinery and apparat 0.065% 11 0.05371 0.003% 0.04237 0.003%49 Manufacture of transport equipment and its repair 0.058% 14 0.03527 0.002% 0.04522 0.003%50 Manufacture of other products not elsewhere classified 0.107% 5 0.00334 0.000% 0.00534 0.001%51 Electricity, gas and water supply 2.480% 1 0.02182 0.054% 0.01543 0.038%52 Construction 0.050% 21 0.01759 0.001% 0.00000 0.000%53 Trade 0.050% 20 0.08871 0.004% 0.19650 0.010%54 Restaurant and hotel 0.062% 12 0.00348 0.000% 0.00973 0.001%55 Railway transport 0.028% 31 0.02556 0.001% 0.03796 0.001%56 Road transport 0.051% 19 0.01196 0.001% 0.00650 0.000%57 Water transport 0.038% 25 0.00724 0.000% 0.02090 0.001%58 Air transport 0.095% 8 0.01022 0.001% 0.00804 0.001%59 Services allied to transport 0.041% 23 0.01478 0.001% 0.02774 0.001%60 Communication 0.029% 29 0.03234 0.001% 0.02533 0.001%61 Financial intermediaries 0.015% 37 0.02795 0.000% 0.03645 0.001%62 Real estate and business service 0.051% 17 0.04135 0.002% 0.00681 0.000%63 Genera! government and defense 0.048% 22 0.00057 0.000% 0.00109 0.000%64 Social and community, services 0.034% 27 0.00616 0.000% 0.05099 0.002%65 Other services 0.059% 13 0.03246 0.002% 0.05022 0.003%66 Unspecified sector 0.027% 32 0.00117 0.000% -0.00052 0.000%

190 Total 1.00000 0.098% 1.00000 0.077%0.10% 0.08%

industry results in 0.10% increase in the producers price index. Likewise, taking the each industry’s

weight in the final consumption demand, the price change of each industry results in 0.08% increase

in the consumers price index.

Table A3-1 Price change in each industry when electric price increases by 2.48%



0.00% 0.50% 1.00% 1.50% 2.00% 2.50%

AgricultureLivestock

ForestFishery

Coal and metal ore mining Crude oil, natural gas and geothermal mining


Manufacture of food processing and preserving Manufacture of oil and fat

Rice milling Manufacture of flour, all kinds

Sugar factory Manufacture of other food products


Manufacture of cigarettes Yarn spinning

Manufacture of textile, wearing apparel and leather Manufacture of bamboo, wood and rattan products

Manufacture of paper, paper products and cardboard Manufacture of fertilizer and pesticide

Manufacture of chemicals Petroleum refinery

Manufacture of rubber and plastic wares Manufacture of non metallic mineral products


Manufacture of basic iron and steel Manufacture of nonferrous basic metal

Manufacture of fabricated metal products Manufacture of machine, electrical machinery and

apparatus Manufacture of transport equipment and its repair

Manufacture of other products not elsewhere classified Electricity, gas and water supply

Construction

Trade Restaurant and hotel

Railway transport

Road transport Water transport

Air transport Services allied to transport

Communication Financial intermediaries


Genera! government and defense Social and community, services

Other services Unspecified sector

Price Increase (%)

Fig. A3-1 Price change in each industry when electric price increases by 2.48%



ANNEX-4 Cost and Benefit Analysis of Geothermal Development Incentives

(In the case of excluding the Fuel Export Value)

Chapter 13 has discussed the cost and benefit analysis of three (3) kinds of geothermal development incentives, i.e., (i) the Feed-in Tariff incentives, (ii) the Tax Reduction and Feed-in Tariff combination incentives, (iii) the Geothermal Development Promotion Survey (GDPS) and Feed-in Tariff combination incentives. This ANNEX discusses the cost and benefit analysis of these incentives with excluding the Fuel Export Value. The Study Team believes that the Fuel Export Value, which is the value obtained from exporting the fuels which would have been consumed in thermal power plants if geothermal has not been developed, is one of the most important benefits of geothermal energy. However, since the request of excluding the Fuel Export Value from the benefits to government and society comes from Fiscal Policy Office, the counterpart of this Study, this ANNEX discusses the analysis with excluding the Fuel Export value. This ANNEX follows suit of the style of Chapter 13 for easy comparison.

1. Long-Term Geothermal Development Forecast The geothermal development forecast is the same as in Chapter 13, i.e. as shown in Table 13.1-1 in Chapter 13.

(1) Beneficiary projects of the Feed-in Tariff incentives The beneficiary projects of the Feed-in tariff incentives are the same as in Chapter 13,

i.e. as shown in Fig. 13.1-1 in Chapter 13.

(2) Beneficiary projects of the Tax Reduction and Feed-in Tariff combination incentives The beneficiary projects of the Tax Reduction and Feed-in tariff combination

incentives are the same as in Chapter 13, i.e. as shown in Fig. 13.1-2 in Chapter 13.

(3) Beneficiary projects of the Governmental Geothermal Development Promotion Survey (GDPS) and Feed-in Tariff combination incentives

The beneficiary projects of the Geothermal Development Promotion Survey (GDPS) and Feed-in tariff combination incentives are the same as in Chapter 13, i.e. as shown in Fig. 13.1-3 in Chapter 13.

2. Feed-in Tariff Incentives (1) Costs and Benefits of the Feed-in Tariff Incentives (a) Costs to Government

The costs to government are the same as in Chapter 13. (b) Benefits to Government



FIT Scheme

Costs

Benefits


Benefits


Government

Price Gap Subsidy




Tax Value

Environmental value

The benefits to government are the ones which excludes the Fuel Export Value from the benefits to government in Chapter 13. Therefore, they are the sum up of (i) the Fuel Save Benefit to PT PLN and (iii) the Tax and Royalties Value. These benefits are as shown in Table A4.2-1.

Table A4.2-1 Benefits and beneficiaries in geothermal development (in the case of excluding Fuel Export Value) (USD Cents/kWh)

（Assumed Oil Price 100 USD/barrel, CO2 20 USD/ton）

Value Beneficiary

Energy Value

Fuel Cost Reduction

Value

Fuel Export Value

Tax & Royalties

Value

Environmental Value

Total

PLN 8.2 8.2

Government 0.3 0.0 1.6 1.9

Society 0.0 1.9 1.9

Total 8.2 0.3 0.0 1.6 1.9 12.0

(c) Costs to Society

The costs to society are the same as in Chapter 13. (d) Benefits to Society

The benefits to society are the sum of the above-mentioned government benefits plus

(v) the Environmental Value（CO2 reduction value）. The above-mentioned connections are as shown in Fig. A4.2-1. Fig. A4.2-1 Costs and benefits in the Feed-in Tariff incentives case

(in the case of excluding Fuel Export Value)



0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

2048

2050

2052

2054

Year

Ann

ual C

ost/B

enef

its (m

$)


(2) Evaluation of the Feed-in Tariff incentives As shown in Table A4.2-1, the government’s benefit is 1.9 USD Cents/kWh when the

oil price is 100 USD/barrel. The annual amount of the government’s total benefit can be calculated by multiplying by 1.9 USD Cents/kWh the amount of annual energy generated at 90% of capacity, as assumed in Fig. 13.1-1. By comparing this benefit with the cost (the amount of the subsidy), government fiscal balance can be sought as shown in Table A4.2-2 and Fig. A4.1-2.

Table A4.2-2 and Fig. A4.2-2 indicate that there are the government benefits from 2012 to 2054 while the government costs are required from 2012 to 2039. When the oil price is 100 USD/barrel, the total government costs become USD 20,958 million (Net Present Value1 in 2009 USD is USD 3,490 million.). The annual government costs culminate in USD 1,136 million in 2025 (USD 185 million in NPV). On the other hand the annual government benefits of the same year are USD 765 million (USD 125 million in NPV) and there are net benefits of minus USD 371 million (minus USD 60 million in NPV). The government annual net benefits are negative until 2035 but turn to be positive afterwards due to the reduction of costs. The total net benefits of the government fiscal balance during the period are USD 1,990 million. The Net Present Value of this amount is minus USD 1,152 million because the benefits are obtained in the second half of the period. Since the net benefits remain in negative in many parts of the period, the FIRR (Financial Internal Rate of Return) of the government fiscal balance is not available.

Fig.A4.2-2 Costs and benefits in the Feed-in Tariff incentives case

(in the case of excluding Fuel Export Value) 1 Net present value is converted by using a discount rate of 12%. As for 12%, refer to footnote in page 2-8.

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

Geo

ther

mal

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rgy

Dev

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the

Rep

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of I

ndon

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Fina

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-4-4

FIT

Sche

me

Eval

uatio

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ash

flow

of G

over

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t Fis

cal B

alan

ce

Cas

h flo

w o

f Soc

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enef

its

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Pric

eTa

x ra

teFI

T FI

RR

Gov

tBe

nefit

NP

VFu

nd E

IRR

Soci

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nefit

NPV

US$

100

32.5

%#D

IV/0

!-1

,152

m$

#DIV

/0!

1,35

3m

$N

et B

enef

it

Year

New

Cap

acity

(cum

.)(M

W)

Gen

.by

Gre

enG

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P(G

Wh)

Ave

rage

Gre

en G

eoP

P P

rice

(Cen

t/kW

h)

Coa

l PP

Pric

e(C

ent/k

Wh)

Pric

e G

ap(C

ent/k

Wh)

Pric

e G

apS

ubsi

dy C

ost

(m$)

Gov

t Cos

t(m

$)

Fuel

Cos

tR

educ

tion

Ben

efit

(C$/

kWh)

Expo

rtB

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it fo

rG

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(C$/

kWh)

Tax

Ben

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(Cen

t/kW

h)

Tota

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Gov

tB

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its (m

$)

Gov

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nefit

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Flow

(m$)

Gov

t Cas

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ow (N

PV)

(m$)

Soc

ial C

ost

(m$)

Fuel

Cos

tR

educ

tion

Ben

efit

(C$/

kWh)

Exp

ort

Bene

fit(C

$/kW

h)Ta

x Be

nefit

(Cen

t/kW

h)

Envi

ronm

ent

Ben

efit

(Cen

t/kW

h)

Tota

lB

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its(C

ent/k

Wh)

Soc

ial

Ben

efit

(m$)

Soc

ial N

etBe

nefit

(m$)

Soc

ial N

etB

enef

it (N

PV

)(m

$)

ab=

a*87

60h*

0.9

cd

e=c-

df=

e*b

g=f

hi=

s*0.

325

jk=

h+i+

jl=

k*b

m=l

-fn=

m/(1

+dis

c.r

ate)

^nq=

gr=

hs

t=j

uv=

r+s+

t+u

w=v

*bx=

w-q

y=x/

(1+d

isc.

rate

)^n

2009

00

2010

00

2011

00

2012

300

2,36

511

.98.

23.

787

870.

30.

01.

61.

945

-42

-30

870.

30.

01.

61.

93.

890

32

2013

600

4,73

011

.98.

23.

717

417

40.

30.

01.

61.

990

-83

-53

174

0.3

0.0

1.6

1.9

3.8

180

64

2014

900

7,09

611

.98.

23.

726

026

00.

30.

01.

61.

913

5-1

25-7

126

00.

30.

01.

61.

93.

827

010

520

1590

07,

096

11.9

8.2

3.7

260

260

0.3

0.0

1.6

1.9

135

-125

-63

260

0.3

0.0

1.6

1.9

3.8

270

105

2016

1,50

011

,826

11.9

8.2

3.7

434

434

0.3

0.0

1.6

1.9

225

-209

-94

434

0.3

0.0

1.6

1.9

3.8

450

167

2017

1,50

011

,826

11.9

8.2

3.7

434

434

0.3

0.0

1.6

1.9

225

-209

-84

434

0.3

0.0

1.6

1.9

3.8

450

167

2018

2,10

016

,556

11.7

8.2

3.5

584

584

0.3

0.0

1.6

1.9

311

-273

-98

584

0.3

0.0

1.6

1.9

3.8

626

4215

2019

2,40

018

,922

11.7

8.2

3.5

656

656

0.3

0.0

1.6

1.9

354

-303

-97

656

0.3

0.0

1.6

1.9

3.8

713

5718

2020

2,70

021

,287

11.6

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Soc

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Tabl

e A4.

2-2

Cos

ts a

nd b

enef

its in

the

Feed

-in T

ariff

ince

ntiv

es c

ase

(in th

e ca

se o

f exc

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ng F

uel E

xpor

t Val

ue)



-5,000

0

5,000

10,000

15,000

20,000

60 70 80 90 100 110 120 130 140Oil Price ($/bbl)

Net

Pre

sent

Val

ue (m

$)

FIT (Govt Benefit)

FIT (Social Benefit) Oil Price($/bbl) FIRR

FIT (GovtBenefit) EIRR

FIT (SocialBenefit)

NPV (m$) NPV (m$)60 － -3,694 － -1,18970 － -3,160 6.6% -65580 － -2,621 10.8% -11690 － -1,822 24.9% 683

100 － -1,152 － 1,353110 6.3% -486 － 2,019120 17.9% 316 － 2,821130 76.6% 982 － 3,487140 ＋ 1,641 － 4,146

(Note) - : IRR is unable to calculate due to too many negative numbers. + : IRR is unable to calculate due to too many positive numbers.

Next is the comparison of Social Costs and Benefits. Social Benefits remain above the Social Costs throughout the period and their total amount is USD 27,605 million (USD 1,353 million in NPV). The EIRR (Economic Internal Rate of Return) is not available since the balance remains in the black all the time. As a result, provided that the oil price stays at 100 USD/barrel, the Feed-in Tariff incentives bring negative effect to the government but bring significant benefits to society.

Table A4.2-3 and Fig. A4.2-3 show the sensitivity of the governmental and the social benefit to oil price variation. When the oil price comes down, the Benchmark price becomes lower while the selling price of geothermal energy is unaffected. Therefore the amount of subsidy will increase. As a result, the social benefits turn negative when the oil price falls below 80 USD/barrel. On the other hand, if the oil price rises to 140 USD/barrel, the benefits to government will turn positive.

Table A4.2-3 Sensitivity analysis of the Feed-in Tariff incentives

Fig.A4.2-3 Sensitivity analysis of the Feed-in Tariff incentives

3. Tax Reduction and Feed-in Tariff combination incentives (1) Costs and benefits of the Tax Reduction and Feed-in Tariff combination incentives (a) Costs to Government

The costs to government are the same as in Chapter 13. (b) Benefits to Government

The government’s benefits are the same as for the case of the Feed-in Tariff incentives, which are the sum of (i) the Fuel Save Benefit of PT PLN and (iii) the Tax and Royalties Value. (c) Costs to Society

The costs to society are the same as in Chapter 13.



Tax Reduction Scheme (5% Corporate Tax rate for 15 years)

Costs

Benefits


Benefits


Government

Reduction of Tax Income




Tax Value

Environmental value

Price Gap Subsidy

(d) Benefits to Society Social benefits are the above-mentioned government benefits plus (v) Environmental

Value（CO2 reduction value）. These connections are shown as in Fig. A4.3-1.

Fig. A4.3-1 Costs and benefits in the Tax Reduction and Feed-in Tariff combination incentives case (in the case of excluding Fuel Export Value)

(2) Evaluation of the Tax Reduction and Feed-in Tariff combination incentives The estimated impact of this incentive case is shown as Table A4.3-1 and Fig. A4.3-2.

Likewise as the case of the Feed-in Tariff incentives case, there are the government benefits from 2012 to 2054 while the government costs are required from 2012 to 2039. When the oil price is 100 USD/barrel, the total government costs become USD 20,242 million (USD 3,389 million in NPV). The annual government costs culminate in USD 1,100 million in 2025 (USD 179 million in NPV). On the other hand the annual government benefits of the same year are USD 765 million (USD 125 million in NPV) and there are net benefits of minus USD 335 million (minus USD 54 million in NPV). The government annual net benefits are negative until 2034 but turn to be positive afterwards due to the reduction of costs. The total net benefits of the government fiscal balance during the period are USD 2,709 million. The Net Present Value of this amount is minus USD 1,051 million because the benefits are obtained in the second half of the period. Since the net benefits remain in negative in many parts of the period, the FIRR (Financial Internal Rate of Return) of the government fiscal balance is not available.

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240

1TO

TAL

(Nom

inal

)1,

348,

164

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686,

874

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4222

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2,70

6－

20,2

4248

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28,3

21－

TOTA

L (in

200

9 U

SD)

131,

840

2,40

398

63,

389

2,33

8-1

,051

-1,0

513,

389

4,84

31,

454

1,45

4

Soci

al B

enef

itsG

ovt C

osts

G

ovt B

enef

itsC

ash

Flow

Soci

al C

ost s

Tabl

e A4.

3-1

Cos

ts a

nd b

enef

its in

the

Tax

Red

uctio

n an

d Fe

ed-in

Tar

iff c

ombi

natio

n in

cent

ives

cas

e (

in th

e ca

se o

f exc

ludi

ng F

uel E

xpor

t Val

ue)



0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

2048

2050

2052

2054

Year

Annu

al C

osts

/Ben

efits

(m$)

Govt Benefits (m$)

Govt Cost (m$)

Tax Reduction


TaxReduction

& FIT(Govt EIRR

TaxReduction

& FIT(Social

NPV (m$) NPV (m$)60 － -3,593 － -1,08870 － -3,059 7.2% -55480 － -2,520 11.8% -1590 － -1,722 28.9% 783

100 － -1,051 ＋ 1,454110 7.2% -386 ＋ 2,119120 20.4% 408 ＋ 2,913130 ＋ 1,028 ＋ 3,533140 ＋ 1,568 ＋ 4,073


-5,000

0

5,000

10,000

15,000

20,000

60 70 80 90 100 110 120 130 140

Oil Price ($/bbl)

Net

Pre

sent

Val

ue (m

$)

Tax Reduction & FIT (Govt Benefit)

Tax Reduction & FIT (Social Benefit)

Fig.A4.3-2 Costs and benefits in the Tax Reduction and Feed-in Tariff combination incentives case (in the case of excluding Fuel Export Value)

Next is the comparison of Social Costs and Benefits. Social Benefits remain above the

Social Costs throughout the period and their total amount is USD 28,321 million (USD 1,454 million in NPV). The EIRR (Economic Internal Rate of Return) is not available since the balance remains in the black all the time. As a result, provided that the oil price stays at 100 USD/barrel, the Tax Reduction and Feed-in Tariff combination incentives bring negative effect to the government but bring significant benefits to society.

Table A4.3-2 and Fig. A4.3-3 show the results of sensitivity analysis of the net benefit to governmental and society to variation in oil prices. If the oil price goes below 80 USD/barrel, the NPV of the society becomes negative. On the other hand, if the oil price rises to 120 USD/barrel, the benefits to government will turn positive.

Table A4.3-2 Sensitivity analysis of the Tax Reduction and Feed-in Tariff combination incentives Fig.A4.3-3 Sensitivity analysis of the Tax Reduction and Feed-in Tariff combination incentives



Geothermal Development Promotion Survey (GDPS) Fund Scheme

Expenditure

Income

Financial Evaluation of Fund 10 year-installment with 6.5% interest

Costs

Benefits

Financial Evaluation of Government (FIRR)Benefits


Government

Price Gap Subsidy




Tax Value

Environmental value



4. Geothermal Development Promotion Survey (GDPS) and Feed-in Tariff combination incentives (1) Scheme of promotion

The scheme of this incentives case is the same as in Chapter 13. The relations in this case are as shown in Fig. A4.4-1.

Fig. A4.4-1 Costs and benefits in the GDPS and Feed-in Tariff combination incentives case (in the case of excluding Fuel Export Value)

(2) Evaluation of GDPS Fund Since the GDPS Fund is assumed to be independent of the government budget, the

discussed results in Chapter 13 are not affected even when the Fuel Export Value is excluded. Therefore, the evaluation results of GDPS Fund are the same as in Chapter 13.

Stud

y on

Fis

cal a

nd N

on-f

isca

l Inc

entiv

es to

Acc

eler

ate

Priv

ate

Sect

or

Geo

ther

mal

Ene

rgy

Dev

elop

men

t in

the

Rep

ublic

of I

ndon

esia

Fina

l Rep

ort

JIC

A

Wes

t JEC

AN

NEX

-4-1

0

Geo

ther

mal

Dev

elop

men

t Pro

mot

ion

Surv

ey (G

DPS

) Fun

d Sc

hem

e Ev

alua

tion

Cas

h flo

w o

f Gov

ernm

ent F

isca

l Bal

ance

C

ash

flow

of S

ocia

l Ben

efits

Oil

Pric

eG

DPS

Cos

t

GD

PSsu

cces

sra

teIn

ters

t rat

eTa

x ra

teFI

RR

Gov

tB

enef

itN

PVEI

RR

Soci

alB

enef

itN

PV

US$

100

35M

$1.

06.

50%

32.5

%#D

IV/0

!50

0m

$25

.6%

1,35

8m

$

Year

Exis

ting

(MW

)Ad

ditio

nal

(MW

)

New

Cap

acity

(cum

.)(M

W)

Gen

.by

Bro

wn

Geo

PP

(GW

h)

Aver

age

Brow

n G

eoPP

Pric

e(C

ent/k

Wh)

Coa

l PP

Pric

e(C

ent/k

Wh)

Pric

e G

ap(C

ent/k

Wh)

Pric

e G

apSu

bsid

y (m

$)G

ovt C

ost

(m$)

Fuel

Cos

tR

educ

tion

Bene

fit(C

$/kW

h)

Expo

rtBe

nefit

for

Gov

t(C

$/kW

h)Ta

x Be

nefit

(Cen

t/kW

h)

Tota

lBe

nefit

s(C

ent/k

Wh)

Gov

tBe

nefit

s(m

$)

Gov

tBe

nefit

sC

ash

Flow

(m$)

Gov

t Cas

hFl

ow (N

PV

)(m

$)

Pric

e G

apSu

bsid

y(m

$)So

cial

Cos

t(m

$)

Fuel

Cos

tR

educ

tion

Bene

fit(C

$/kW

h)

Expo

rtBe

nefit

(C$/

kWh)

Tax

Ben

efit

(Cen

t/kW

h)

Envi

ronm

ent

Ben

efit

(Cen

t/kW

h)

Tota

lBe

nefit

s(C

ent/k

Wh)

Soci

alBe

nefit

(m$)

Soc

ial N

etBe

nefit

(m$)

Soci

al N

etBe

nefit

(NP

V)(m

$)

a1a2

ab=

a*87

60h*

0.9

cd

e=c-

df=

e*b

g=f

hi=

s*0.

325

jk=

h+i+

jl=

k*b

m=l

-fn=

m/(1

+dis

c.ra

te)^

np=

fq=

p+ (g

of

Fund

)r=

hs

t=j

uv=

r+s+

t+u

w=v

*b+

(oof

Fun

d)x=

w-q

y=x/

(1+d

isc.

rate

)^n

2009

935

2010

935

2011

1,10

011

70

-117

-93

2012

1,10

011

70

-117

-83

2013

1,10

017

50

-175

-111

2014

1,10

011

723

-94

-53

2015

1,10

011

723

-94

-48

2016

1,10

060

060

04,

730

8.9

8.2

0.7

3434

0.3

0.0

0.8

1.1

5218

834

150

0.3

0.0

0.8

1.9

3.0

208

5826

2017

1,10

00

600

4,73

08.

98.

20.

734

340.

30.

00.

81.

152

187

3415

00.

30.

00.

81.

93.

021

767

2720

181,

100

300

900

7,09

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88.

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125

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100

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417

055

2020

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100

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100

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8.5

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353

38

2047

2,40

018

,922

0.0

0.0

0.0

00

0.3

0.0

0.6

0.9

174

174

20

00.

30.

00.

61.

92.

853

353

37

2048

2,10

016

,556

0.0

0.0

0.0

00

0.3

0.0

0.6

0.9

149

149

20

00.

30.

00.

61.

92.

846

446

46

2049

1,80

014

,191

0.0

0.0

0.0

00

0.3

0.0

0.6

0.9

125

125

10

00.

30.

00.

61.

92.

839

539

54

2050

1,80

014

,191

0.0

0.0

0.0

00

0.3

0.0

0.6

0.9

125

125

10

00.

30.

00.

61.

92.

839

539

54

2051

1,50

011

,826

0.0

0.0

0.0

00

0.3

0.0

0.6

0.9

103

103

10

00.

30.

00.

61.

92.

832

832

83

2052

1,20

09,

461

0.0

0.0

0.0

00

0.3

0.0

0.6

0.9

8181

10

00.

30.

00.

61.

92.

826

126

12

2053

600

4,73

00.

00.

00.

00

00.

30.

00.

50.

839

390

00

0.3

0.0

0.5

1.9

2.7

129

129

120

5460

04,

730

0.0

0.0

0.0

00

0.3

0.0

0.5

0.8

3939

00

00.

30.

00.

51.

92.

712

912

91

TOTA

L (N

omin

al)

709,

560

281

281

6,76

36,

482

－28

12,

031

22,7

3420

,703

－TO

TAL

(in 2

009

USD

)59

,931

9292

592

500

500

869

2,22

71,

358

1,35

8

Gov

t Cos

tsN

et B

enef

itG

ovt B

enef

itsS

ocia

l Ben

efits

Cas

h Fl

owS

ocia

l Cos

ts

Tabl

e A4.

4-1

Cos

ts a

nd b

enef

its in

the

Geo

ther

mal

Dev

elop

men

t Pro

mot

ion

Surv

ey a

nd F

eed-

in T

ariff

com

bina

tion

ince

ntiv

es c

ase

(in th

e ca

se o

f exc

ludi

ng F

uel E

xpor

t Val

ue)



(3) Costs and Benefits of the GDPS and Feed-in Tariff combination incentives (a）Costs to Government

Costs to government are the same as in Chapter 13. (b) Benefits to Government

These are the same as in the previous cases: (i)the Fuel Save Benefit accruing to PT PLN and (iii) the Tax and Royalties value.

(c）Costs to Society Costs to society are the same as in Chapter 13.

(d）Benefits to Society Society’s benefits are the sum of the repayment income of the GDPS Fund plus the

above mentioned governmental benefits and (v) the Environmental Value（CO2 reduction value）.

(4) Evaluation of the GDPS and Feed-in Tariff combination incentives Table A4.4-1 and Fig. A4.4-2 show the results of the calculation of benefits and costs

to government and to society in this incentive case. The government costs of this case become small and the period necessary for the subsidy is calculated to be from 2016 to 2022. On the other hand, the benefits to government occur during the operation period of geothermal power plants, i.e. from 2016 until 2054. These benefits bring about large net benefits to government as shown in Table A4.4-1 and Fig.A4.4-2. When oil price is 100 USD/barrel, the total government costs are USD 284 million (USD 92 million in NPV), and the total government benefits are USD 6,763 million (USD 592 million in NPV). Therefore the total net benefits to government become USD 6,482 million (USD 500 million). Since the balance remains in surplus throughout the period, the FIRR (Financial Internal Rate of Return) of the government fiscal balance is not available.

As for the social benefits and costs, the net benefits to society remain in the red until 2015 because the GDPS costs are required from 2011 and there is no significant income until 2015. However, after 2016 when the first projects start operation and begin to repay the survey costs to the Fund, society begins enjoying certain benefits and the balance goes into the black and stays there during the rest of the period. The total amount of society’s net benefits reaches USD 20,703 million (USD 1,358 million in NPV) and its EIRR is 25.6%. As such, where the oil price stays at 100 USD/barrel, the incentives pay off for the government and allow society to reap a considerable benefit.

Table A4.4-2 and Fig. A4.4-3 show the sensitivity of the Net Present Value of the benefits to government and society to oil price variations. A decline of oil price leads to lower benefits to government and society. The NPV of the benefits to government turns to be in the



0

100

200

300

400

500

600

700

800

2016

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

2048

2050

2052

2054

Year

Ann

ual C

osts

/Ben

efits

(m$)

Govt Benefits (m$)

Govt Cost (m$)

Govt GDPS Fund


GDPS(Govt

Benefit) EIRR

GDPS(SocialBenefit)

NPV (m$) NPV (m$)60 － -520 15.8% 33970 － -281 18.3% 57780 9.4% -45 20.6% 81390 59.5% 287 23.6% 1,146

100 ＋ 500 25.6% 1,358110 ＋ 632 27.1% 1,491120 ＋ 772 28.2% 1,630130 ＋ 832 28.6% 1,690140 ＋ 892 29.0% 1,750


-5,000

0

5,000

10,000

15,000

20,000

60 70 80 90 100 110 120 130 140Oil Price ($/bbl)

Net

Pre

sent

Val

ue (m

$)

GDPS (Govt Benefit)

GDPS (Social Benefit)

red when the oil price drops below 80 USD/barrel. However, society can enjoy the benefits even with the oil price at 60 USD/barrel. Fig.A4.4-2 Costs and benefits in the GDPS and Feed-in Tariff combination incentives case

(in the case of excluding Fuel Export Value)

Table A4.4-2 Sensitivity analysis of the GDPS and FIT combination incentives

Fig. A4.4-3 Sensitivity analysis of the GDPS and FIT combination incentives

LIST OF REFERENCES


JICA West JEC

R-1

List of References Chapter 2 JICA, Geothermal Development Master Plan Study in Indonesia, September, 2007 Lund (2007), Effectiveness of policy measures in transforming the energy system,

Energy Policy Central Research Institute of Electric Power Industry, CRIEPI Review No.45 2001 Nov. International Energy Agency (IEA), World Energy Outlook 2008 PT.PLN, Electric Power Development Plan (RUPTL 2009-2018) Chapter 3 Dwipa SJAFRA (2004), Current State of Geothermal Development in Indonesia, 2004 JICA, Geothermal Development Master Plan Study in Indonesia, 2007 September Chapter 6 Brandon Owens (2002), An Economic valuation of a Geothermal Production Tax Credit,

National Renewable Energy Laboratory, April 2002, Deloitte (2008), Geothermal Risk Mitigation Strategy Report, DOE, February, 2008

Chapter 7 JICA, Power Sector Study for Optimum Power Development in Indonesia, August, 2002 Central Research Institute of Electric Power Industry, CRIEPI Review No.45 2001 Nov. IPCC, Guideline for National Greenhouse Gas Inventories, 2006

Chapter 8 US Energy information Agency (EIA) Non-Hydraulic renewable energy promotion policy in

UAS and Other Countries, (Feb., 2005) Arne Klein et al, Evaluation of different feed-in tariff design options, The World Future Council Ing.H.Kreuter (2008), Feed-in Tariff in Germany, German Geothermal Society, June,2008 Chapter 10 Ministry of Energy and Mineral Resources. Recent Developments in Indoensia’s Mining Industry

Situation and Policy (Information to IEA), Feb. 2008 Ministry of International trade and Industry, Ministry of Economy, Trade and Industry, Annual Report

on Power Development in Japan, White, Halbert (1980), A Heteroskedasticity-Consistent Covariance Matrix Estimator and a

Direct Test for Heteroscedasticity, Econometrica, Vol.48, 1980 Chapter 11 Japan Thermal and Nuclear Power Engineering Society, Current Situation of Geothermal

Development (2007) Iikura Jou (1996), Current Situation and Challenges of Geothermal Development, Geothermal,


JICA West JEC

R-2

Voi33 No.2, 1996 E.A. DeMeo, J.F.Galdo (1997), Renewable Energy Technology Characterizations, DOE/EPRI,

1997 Ken Williamson, UNOCAL, Geothermal Power, Workshop on Sustainable Energy Systems,

Nov.29, 2000, Atlanta, USA Mario Ragwitz et al (2007), Assessment and Optimization of Renewable Energy Support

Schemes in the European Chapter 12 IGES(2009), CDM Information “Indonesia” (2009） The Institute of Energy and Economics, Japan, A Study on the Data related to Global Warming

Issue, Ministry of Economy, trade and Industry (2005) Central Environment Council, On the Economics Analysis on Environment Taxes, Ministry of

Environment, Japan, August, 2005 Central Environment Council, Green taxes and their Economics Analysis, Special Technical

Committee, Ministry of Environment, August, 2005 Satoh Yuri (2004), Economic Restructuring of Indonesia, Asia Economic Research Institute

(2004) Mishima Kouhei (2004), A study on procurement patterns of Japanese motorcycle

manufacturers in Thailand, Indonesia and Vietnam, Vietnam Development Forum (2004)

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