comprising 17,000 islands that stretch 5000 km (3100 miles) from the Indian ... Borneo and is one of two islands that has large reserves of ...... Bangka Belitung.
Prospects for coal and clean coal technologies in Indonesia Paul Baruya CCC/148 June 2009 Copyright © IEA Clean Coal Centre ISBN 978-92-9029-468-9
Abstract Indonesia has become the largest exporter of steam coal in the world, but the long-term future of coal exports is being brought into question as domestic demand is projected to grow by a significant amount, from 40–50 Mt/y in 2007 to more than 100 Mt/y by 2013, and even higher beyond 2013. Exports reached 200–210 Mt in 2008, and are set to rise in the future. Import volumes are negligible, while indigenous production was estimated to be around 240–260 Mt in 2008. Illegal mining is being addressed and in the past could have accounted for at least 20 Mt/y of production, but obtaining reliable export and production figures as a result is therefore not straightforward. Indonesia is the fourth most populous country in the world. This fact coupled with robust GDP growth means there is more pressure on the state-controlled electricity industry to invest in, and build, adequate infrastructure to meet the rising demand for power. Part of this investment is being driven by government policy to build 10 GWe of coal-fired power by 2010 and a second tranche by 2013. However, the investment programme, commonly known as the ‘crash programme’ is more likely to be delayed by 2–3 years. Nevertheless, the likely 20–30 Mt/y or so of additional coal demand from the first tranche alone will put pressure on domestic coal producers to meet expanding demand both at home and abroad for low rank and exportable bituminous coals. This report covers four main topics, the Indonesian coal industry, the power generating sector and its use of clean coal technology, changes in coal demand and its impact on international trade, and finally a brief look at upgrading low rank coals within the country.
Acronyms and abbreviations $ ARA BAT bbl bcm bcm boe BFG bn Btu/kWh BWE °C CBM CCGT CCS CDM CHP CIF CO2 CoW dwt EIA ESP FGD FTS FY GDP GHG GJ GT GWe GWh h/d ha IBT IC IEA IEA CCC IGCC IPO JI kcal/kg km kt kWe kWh LHV LNG MEMR MJ/kg Mt Mtce Mtoe MWe MWh NOx OECD 2
US dollar Amsterdam/Rotterdam/Antwerp, a major coal hub for European coal imports best available technology barrel of crude billion cubic metres (of natural gas) bank cubic metres (of overburden removal for opencast mining) barrel of oil equivalent blast furnace gas billion (109) British thermal units per kilowatt hour bucket wheel excavator degrees Celsius (multiply by 1.8 and add 32 to convert to Fahrenheit) coalbed methane combined cycle gas turbine (also known as GTCC) carbon capture and storage clean development mechanism combined heat and power (also known as cogeneration) cost, insurance, and freight carbon dioxide Contract of Works, also referred to as Coal Contract of Works (CCoW) deadweight Energy Information Administration, US Department of Energy electrostatic precipitator (for particulate removal) flue gas desulphurisation (for SO2 removal) floating transfer station financial year gross domestic product greenhouse gas gigajoule gas turbine gigawatt of electrical output capacity (1000 MWe) gigawatt hour (1000 MWh; 106 kWh) hours per day hectare Indonesian Bulk Terminal internal combustion (typically a diesel reciprocating engine) International Energy Agency, Paris IEA Clean Coal Centre, London integrated gasification and combined cycle initial public offering joint implementation kilocalorie per kilogramme (multiply by 0.004187 to get MJ/kg) kilometre kilotonnes kilowatt of electrical output capacity kilowatt hour lower heating value liquefied natural gas, a form of natural gas at –163°C temperature and 125 kPa low temperature for the purposes of long distance bulk transportation using cryogenic ocean vessels The Ministry of Energy and Mineral Resources (Indonesia) megajoule per kilogramme (divide by 0.004187 to get kcal/kg) million metric tonnes million tonnes of coal equivalent (multiply by 0.697 to get Mtoe) million tonnes of oil equivalent megawatt of electrical output (1000 kWe) megawatt hour (1000 kWh) nitrogen oxides Organisation for Economic Cooperation and Development (see Geographical Coverage for country listing) IEA CLEAN COAL CENTRE
O&M OLC OPEC PF PPA PPI PPP PTBA R/P ROM Rp SC t/h USC SCR SO2 t tcf TFC TPES TWh UNFCCC WEC
operation and maintenance overland conveyer Organisation of Petroleum Exporting Countries (based in Vienna, Austria) pulverised fuel (hard coal) power purchase agreement producer prices index purchasing power parity PT Tambang Batubara Bukit Asam reserves to production ratio run-of-mine, typically refers to raw mined material Indonesian Rupiah supercritical (typical steam pressure 25 MPa; main steam and reheat temperatures >580°C) selective catalytic reduction (for NOx reduction) sulphur dioxide metric tonne or 1000 kg (x 0.9844 = long ton; x 1.1025 = short ton) trillion cubic feet (of natural gas or equivalent methane deposit) total final consumption total primary energy supply (includes coal, oil, gas, hydro, other renewables, nuclear power) terrawatt hour (1000 GWh, 106 MWh, 109 kWh) United Nations Framework Convention on Climate Change World Energy Council
Prospects for coal and clean coal technologies in Indonesia
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Contents Acronyms and abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Contents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 1
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 1.1 Key coal facts for Indonesia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 1.2 Geography of the Indonesian archipelago . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 1.3 A turbulent political and economic history . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 1.4 Population and the economy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
2
Energy background. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 2.1 Primary energy supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 2.2 Energy demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
3
Energy resources and reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 3.1 Oil and gas – peaking?. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 3.2 Coal – more abundant than oil, but less than gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 3.3 Coalbed methane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 3.4 Peat. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
4
Coal reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 4.1 Geographical concentration of reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 4.2 Quantity of coal reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 4.3 Summary of coal quality definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 4.4 Indonesian coal quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 4.5 Coal geology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 4.6 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
5
Structure of the Indonesian coal industry. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 5.1 Foreign ownership – a common feature of the coal industry . . . . . . . . . . . . . . . . . . . . . 21
6
PT Adaro Indonesia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
7
PT Arutmin Indonesia (BUMI Resources) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
8
PTBA (Tambang Batubara Bukit Asam Tdk). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
9
PT Berau Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
10 PT Kideco Jaya Agung . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 11 PT Kaltim Prima Coal (BUMI Resources). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 12 PT Indominco Mandiri (Banpu) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 13 PT Gunung Bayan Pratama Coal (Bayan Resources) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 14 General corporate issues. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 15 A brief history of Indonesian coal production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 15.1 The history of the Contracts of Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 15.2 The impact of forestry protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 15.3 Changes to the regulatory regime . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 16 Coal production – costs and methods. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Prospects for coal and clean coal technologies in Indonesia
5
Contents 17 Inland transport infrastructure: river barge, road, and rail . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 17.1 Barging. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 17.2 Road and rail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 17.3 Offshore loaders and trans-shipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 17.4 Port facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 17.5 Common disruptions in coal supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 18 Electricity generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 18.1 A brief history of the industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 18.2 Crisis in the power markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 18.3 Power generating capacity in Indonesia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 18.4 Nuclear power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 18.5 Utilisation and efficiency of the power station fleet . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 18.6 Generating efficiencies of the thermal fleet. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 19 Coal-fired technology in Indonesia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 19.1 The ‘crash programme’ – Phase I (2006-10) and Phase II (2009-13). . . . . . . . . . . . . . . 52 19.2 Clean coal technology and tackling climate change . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 20 Coal demand boom in the power sector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 20.1 The role of low rank coal in the power sector. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 20.2 Coal demand in industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 20.3 Projections for coal demand beyond 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 20.4 Impact of plant utilisation on future coal demand. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 20.5 Impacts of power generating efficiency on coal demand . . . . . . . . . . . . . . . . . . . . . . . . 59 21 Can domestic producers respond to rising demand? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 21.1 Export coal versus domestic market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 21.2 Coal pricing – international and domestic. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 21.3 Effects on international coal trade . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 21.4 The effect of exchange rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 22 A brief review of coal upgrading in Indonesia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 22.1 Coal liquefaction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 22.2 White Energy drying and briquetting process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 22.3 The upgraded brown coal (UBC) process to upgrade high moisture coals. . . . . . . . . . . 65 22.4 K-fuel process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 23 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 24 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69
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1 Introduction 1.1
Key coal facts for Indonesia
Total coal production (2008 estimate): Total coal demand (2008 estimate): Exports (2008 estimate): Imports (2005): Recoverable reserves (2006): Port capacities (2008 estimate):
260–270 Mt 40–50 Mt 200–210 Mt 0.1 Mt 7000 Mt 220 Mt
are regularly shipped to Europe and North America as a blend fuel. Most of the industry is operated by private companies, but under tight rules set by the national government, which allow foreign ownership but with limited concession periods of up to 30 years or so.
1.2
Geography of the Indonesian archipelago
This report is an update of a previous IEA Clean Coal Centre (IEA CCC) publication called Indonesian coal prospects to 2010 published in 1994, which reviewed the coal industry and its prospects. Since then, Indonesian coal production has grown at an astonishing rate and its steam coal trade, mainly with Asian buyers, now surpasses every other steam coal exporter in the world. Exports grew fivefold in the ten years between 1995 and 2005 rising from 30 Mt/y to more than 150 Mt/y. By 2007, steam coal exports were estimated to have reached around 194 Mt (McCloskey Statistics, 2008) while annualised estimates for 2008 could see exports reaching 211 Mt (SSY, 2008). There are some discrepancies arising from the published figures, with some experts recording much lower levels of around 160–180 Mt/y being shipped. Illegally mined coal could add 20 Mt/y or so, and it is not clear whether the officially published export data includes this coal. Typically, trade data are recorded officially for taxation purposes by customs and excise for both the exporting and importing nation, but the source of the coal is not necessarily clear as coal is blended into products from more than one mine.
The country itself is the world’s largest archipelago comprising 17,000 islands that stretch 5000 km (3100 miles) from the Indian Ocean in the west through to the islands of New Guinea in the east. Java, Kalimantan, Papua, Sulawesi, and Sumatra are the five key regions (see Figure 1). The first three regions, Java, Sulawesi, and Sumatra are completely occupied by Indonesia; the capital, Jakarta, is located on Java, the economic centre of Indonesia.
Indonesia consumes around 20% of the country’s coal output for power generation and industry; the remaining 80% is exported. The growing demand for electricity means that the prospects for domestic steam coal demand for power generation are good. One of the central tenets of the country’s energy policy over past years has been the move away from oil-fired power towards renewable, gas, and coal. In addition to the replacement programme of oil plants, the rapid growth in power demand is also demanding the need for reliable and cost-effective power, coal is seen as being able to deliver this power.
1.3
However, if Indonesia intends to retain its position as a major coal exporter, the country could face resource constraints, which may conflict with the need for more coal-fired power within the country. The country’s coal seams are mineable using opencast operations, where thick seams of low sulphur and low ash coals exist. Almost all mining operations use simple truck and shovel methods, with few exceptions. As a general rule, Indonesian coals are lower in rank and so when comparing coal qualities with that of other internationally traded coals, Indonesian coals have lower calorific values and higher moisture contents, and are thus more costly to transport over long distances on an energy basis. However, Indonesian coals Prospects for coal and clean coal technologies in Indonesia
Kalimantan and Papua are shared with neighbouring countries. Kalimantan occupies a majority of the island of Borneo and is one of two islands that has large reserves of coal; the other is Sumatra. In the north of Borneo lies the Malaysian regions of Sarawak and Sabah, while Brunei occupies a tiny coastal region whose borders are totally encapsulated by the Malaysian part of Borneo. Papua shares the island with New Guinea, hence collectively it is called Papua New Guinea. The island of Timor is split into West and East Timor, the latter occupied by Indonesia from 1975 until independence in May 2002.
A turbulent political and economic history
Indonesia has had a history of social and political upheaval, which remains in the minds of many people (Cragg, 1998). Cragg reports on the turmoil that afflicted the nation, especially during the rise of Suharto to power in 1965-66, who replaced Sukarno. This led to the death of countless Chinese and communist citizens in the so-called ‘year of living dangerously’. Ten years later, many died in East Timor following the departure of the Portuguese in 1975. In more recent years, Indonesia faced the Asian financial crisis, the end of (the late) President Suharto’s rule after more than 30 years in office (1967-98), the first free elections since the 1960s, demands for independence from restive provinces, bloody ethnic and religious conflict, and not least a most devastating tsunami that killed many thousands. Over time, Indonesia as a country has battled many social and political obstacles, which have periodically interrupted economic growth.
1.4
Population and the economy
Estimates for the country’s population range from 222 to 246 million and growth rates are low at around 1.3%/y (EIA, 7
Introduction
Manado
Sangkulirang Samarindia
Pontianal
Kalimantan
Sumatra
Sorong
Balikpapan
Kolonodale
Palemaang
Sulawesi
Banjarmasin Bengkulu
Makassar
Jakarta Java
Figure 1
Surabaya Bali
Labuhanbajo
Major islands of Indonesia
2007; IMF, 2008). Regardless of the overall level, Indonesia is the fourth most populous nation in the world behind China (1300 million), India, (1100 million), and the USA (299 million). More than 40–45% of the population live in urban areas, which still leaves more than half living in rural locations. More than 60% of the population live on the island of Java. Java also accounts for more than 70% of the energy demand, indicating the importance of this island as the centre for economic activity at the present time. Parts of Java, and much of Kalimantan, Papua, Sulawesi and Sumatra are mountainous, volcanic and densely forested. These conditions make building extensive infrastructure costly in economic and environmental terms. Illegal logging and mining activities affect both the economy and the environment, which has marred the image of these industries. Foreign companies operating in these regions may face increasing pressure to satisfy corporate and social responsibility demands in Indonesia, in order to continue a long-term sustainable business in locations that are potentially sensitive to large-scale extractive operations. The country’s gross domestic product (GDP) for 2007 was $433 billion, equivalent to the economies of Belgium or Switzerland in current dollars, making Indonesia the 20th largest economy in the world (in GDP terms). When adjusted for purchasing power parity, the economy becomes the 16th largest. Given the massive population, Indonesia’s per capita GDP in 2007 was estimated at $1925, just 116th in the world. In purchasing power parity (PPP) terms per capita GDP rises to $3724, but its position worsens to 121st in the world. The global financial crisis of 2008-09, if prolonged, could affect funding for planned generating capacity, as well as funding for new production capacity in the mining sector. Few reports seem to highlight this, but the effects may be felt as 8
Papua Timika
demand for goods and services across the world could fall, and so eventually have an impact on Indonesia indirectly if not directly. Indonesian economic policy moves forward but at a relatively sluggish pace according to international analysts (EIA, 2007). However, the government does not prohibit western style policy. Taxation and labour laws move slowly through the government before becoming law. Trade unions across industry remain vehemently opposed to changes in restrictive labour laws. Parliament has considered changes to mining laws for several years and, as a result, mining firms are reluctant to start new projects. Elections in 2009 will mean reforms are not likely to be passed until after 2009. Fiscal policy revolves around subsidised energy prices. Oil products and power prices are kept artificially low. Recovering costs of production of energy are therefore almost impossible, and so while low tariffs keep demand high, the supply of energy is constrained by the lack of funding available to improve the energy infrastructure, and government funding for subsidies remain under pressure. In May 2008, end-consumer fuel prices were raised by an average of 29%. The government’s original budget for 2008 assumed an oil price of 60 $/barrel ($/bbl), a price at which fuel subsidies during 2008 would amount to Rp 46 trillion ($5 bn or 5% of total expenditure). The massive escalation in oil price in 2008 meant that the subsidy cost would rise to Rp 127 trillion ($13.7 bn), and this was based on an oil price of 95 $/bbl. This raised the government spend on fuel subsidies to 13% of the budget. Price escalations to 135 $/bbl has led the government to revise subsidies again to account for a 2008 average price of 110 $/bbl. Estimates in the middle of the year stood at Rp 132 trillion ($14 bn), 286% more than allowed for by any original budget. As the country is a net importer of oil, Indonesia does not benefit from the massive rise in oil prices experienced in recent years. In fact, the rising cost of oil IEA CLEAN COAL CENTRE
Introduction products has had a major impact on the cost of production in Indonesia, as it has across the world. However, a subsequent fall in the world price of crude in 2009 will ease this pressure. Inflation has been running well above the target of 4-6% for most of 2008. The consumer price index increased by 10.5% in 2005 and 13.1% in 2006, although dropped to 6.4% in 2007. Despite criticism of the slowness of government to tackle subsidies and labour reforms, politically it would have been difficult to make such decisions during periods of high inflation where the GDP per capita is so low. High prices and the burden of subsidies could greatly impair growth within the country. The Indonesian economy is still feeling the effects of the East Asian financial crisis which started in July 1997 in Thailand when the currency (baht) was decoupled from the US$ and floated. Thailand was already carrying a heavy burden of foreign debt and the financial and economic collapse affected the currencies, stock markets, and other asset values across the whole of Southeast Asia, raising fears of a global economic meltdown. Prior to the crisis, the Southeast Asian economies attracted a vast amount of short-term financial capital partly through high interest rates and attracting high returns for foreign investors. The large inflow of money drove up the price of assets, such as real estate, and GDP growth across the region was high, in many cases as high as 8–12%/y. In Indonesia, private current account deficits were growing and maintaining fixed exchange rates encouraged further borrowing from external sources, exposing the financial and corporate sectors to exchange rate risk more than ever. While ‘hot money’ flowed into South East Asia attracted by high interest rates and rising asset values, it was just as quick to flow out again as the US raised its own interest rates. Overvalued assets started to devalue, and bankruptcies and failure to meet debt obligations from a correction of asset values caused a credit crisis. While Asian currencies were collapsing, interest rates were raised in a desperate attempt to attract money back into the region, but confidence by that time had been lost and high interest rates began to damage the domestic markets. The massive outflow of ‘hot money’ from Indonesia led to a devaluation of the Rupiah in 1998 and a contraction of GDP by a massive 13% (based on constant Rupiah prices). In US dollar terms the impact was phenomenal. IMF data show GDP in US dollar terms (at current prices) contracting by –56% in 1998, although GDP rebounded by +47% the following year. The economy continues to experience a surprisingly robust growth, with GDP averaging more than 5%/y since 2004, and achieving 6.3% in 2007 and an estimated 6.1% in 2008. Foreign direct investment and imports of capital goods are growing, despite a rise in prices. Domestic cement sales, a proxy for construction investment, also seem to remain robust, and the pressure on the Central Bank from the reduction in subsidies signals a move away from central control.
Prospects for coal and clean coal technologies in Indonesia
9
2 Energy background This section introduces the trends in total energy supply and consumption in the major economic sectors, as well as briefly discussing the interesting trend in biomass use which remains strong.
2.1
Primary energy supply
Indonesia is the world’s eighth largest producer of coal and also the eighth largest producer of natural gas. The country’s ranking of 21st largest producer of oil seems less impressive, although it still produces 1000 barrels per day, equivalent to a tenth of that of Saudi Arabia. Indonesia is a significant exporter of natural gas and steam coal. In recent years, natural gas exports rapidly became major earners of foreign exchange and Indonesia became a leading exporter of liquefied natural gas alongside Malaysia. Indonesia is a net importer of oil and has spurred the government to consider other avenues for export revenues. The demise of oil exports from Indonesia brought into question the eligibility of Indonesia as a member of OPEC and as of 2008, Indonesia left OPEC. It is the gas and coal industries which are now major export businesses. Although domestic gas and coal demand is rising, production overwhelmingly outstrips consumption. In 2006, the Indonesian economy consumed around 250–260 Mtce of energy (170–180 Mtoe), while producing around 440 Mtce (308 Mtoe) of primary energy in the form of coal, gas, oil (and oil products), and combustible renewable or waste biomass (see Figure 2). Geothermal power and hydroelectricity are also produced domestically.
Roughly 37% of the primary energy supply was oil. Coal accounted for around 14% of the supply and natural gas 17%. Interestingly, the use of traditional fuels such as combustible renewables and waste is large at 28%, equivalent to 50 Mtce. Almost 90% of this traditional fuel is consumed in the residential sector; the accuracy of this figure could be queried since the metering of wood fuels across the many islands is problematic. Yet according to statistics, biomass consumption has changed little over the last twenty years or so.
2.2
Energy demand
The growth in energy consumption has been driven largely by the rise in economic growth, despite the setbacks experienced during the 1990s. Before the currency crisis in 1997, GDP growth of 7–8%/y was not uncommon; but it was only after 2000 that GDP increased steadily, averaging some 5%/y. Population growth has been more modest at just 1.3%/y, but with a population of 220 million, population growth remains an important driver for energy demand. Since 2000, while GDP growth has steadied at 5%/y, the growth in the primary energy supply has dropped to 2.8%/y (see Table 1). The moderating of energy growth in recent years is seen clearly in the industrial, residential, commercial (and public), and agricultural sectors which have all contributed to the drop in overall demand for energy within the economy. Interestingly, this curtailment of rising demand has occurred despite the fact that energy prices domestically are still subsidised to varying degrees. Figure 3 illustrates a consistent pattern between per capita GDP and total primary energy consumption. As wealth per capita increases, the primary energy supply to the economy increases linearly. Furthermore, Indonesia has an interesting consumption profile as is shown in Figure 4 with a notable lack of conventional supplies especially electricity and natural gas in some sectors. In the residential sector, electricity usage is limited to lighting and small appliances and accounts for a very small proportion of the overall residential consumption. Almost no natural gas is consumed. The industrial and commercial sectors also have a limited penetration of electricity and gas. Instead, there is a considerable amount of combustible renewables and waste (which could be generally termed as biomass, although there are stricter definitions).
coal 14% oil and oil products 37% gas 17% hydroelectricity 1% geothermal, solar, wind and tidal 3% combustible renewables and waste 28%
Figure 2
10
Total primary energy supply for Indonesia 2006 (IEA, 2007)
Residential energy demand is the single largest market for energy. In 2005, 80 Mtce (56 Mtoe) was consumed by this sector which itself is dominated by a single energy source, biomass (see Figure 4). The chief sources of biomass are wood or wood-based fuels such as charcoal. Different biomasses will be used in rural and urban locations. Rural populations may make use of a mix of forest wood and animal waste, while urban biomass might consist of managed wood sources and wood fuel products. IEA CLEAN COAL CENTRE
Energy background Table 1
Long-term economic and energy trends
Growth rates of GDP, population, and primary energy, %/y 1971-80
1981-90
1991-2000
2001-06
GDP at 2000 Rp
5.2
3.6
4.9
Population
1.9
1.3
1.3
Primary energy production
6.3
3.1
2.7
4.6
Total primary energy supply
5.3
6.1
3.8
2.8
Industry
17.3
9.8
6.4
2.2
Residential
2.7
1.7
2.3
1.3
Commerce and public services
13.4
9.7
11.3
6.1
Agriculture/forestry
10.9
5.2
8.8
1.3
In many developing countries, oil products such as kerosene are used widely for cooking. However in Indonesia, biomass still appears to be the fuel of choice. This dependence may be partly due to a reluctance to switch to alternatives. Wood is convenient and the technology for burning the fuel is easily understood. Alternative technologies and the availability of fuels may by limited in many parts of Indonesia. Whether residential households take up coal products such as briquettes is questionable due to the health implications of switching from one smoky (or fuming) fuel to another, a problem already experienced with wood and oil products.
Total primary energy supply, Mtoe
200 160 120 80
40 0 0
500
1000
1500
2000
2500
3000
3500
4000
GDP per capita, (US$ purchasing power)
Figure 3
Per capita GDP versus total primary energy supply
The industrial sector consumed 49 Mtce (34 Mtoe) in 2005 and offers considerable growth prospects. Industry uses a balanced mix of fuels, which includes about 14 Mtce (10 Mtoe) of coal, and the same quantity again of oil. Combustible renewables and waste contribute 9 Mtce (6 Mtoe), more than that from natural gas. Here again, the
90 80
Energy consumption, Mtce
electricity 70
combustible renewables and waste
60
natural gas
50
petroleum products coal
40 30
20 10 0 Industry sector
Figure 4
Transport sector
Residential
Commercial and public services
Agriculture / forestry
Nonspecified
Nonenergy use
Total final end-user consumption of energy in 2005 (IEA, 2007)
Prospects for coal and clean coal technologies in Indonesia
11
Energy background contribution of biomass cannot be understated. Village industries such as charcoal, brick, ceramics and tile making, and lime burning use woodfuel and could account for a significant proportion of the biomass consumed in industry. The impact on deforestation that these industries have due to biomass consumption probably does not compare with that arising from paper, pulp and logging industries. These activities are directly involved with forest wood consumption, but also supply a large proportion of waste from their activities to the biomass and wood fuel into the larger economy. In part, the biomass fuel feed for domestic and industrial uses requires a great deal of waste wood. Half the volume of logs that are cut on an industrial basis for the wood industry are waste; some reports suggest that 1.2 Gt of waste wood is produced every year (Budiono, 2005). This volume is aside from the amount of wood that may be felled specifically for wood fuel. Sustainable practice for logging and paper and pulp production is of course desired in Indonesia and, within this, a suitable collection of wood waste and its supply to industry and households. However, attempts to change the logging and paper industries in terms of deforestation should also be coupled with efficiency improvements in the utilisation of wood waste to ensure that the demand for wood fuel is effectively managed. Indeed, projects to improve efficiency in cooking stove design have long been implemented. For the time being, the role of biomass in the domestic economy allows conventional energy forms such as natural gas and coal to be exported. Despite the ethical and environmental aims of operating extractive industries to reduce pollution and emissions, there is still a need to provide affordable energy for low income people and to develop an energy management strategy. Part of this is through a target to improve energy efficiency and introduce renewable energy sources. In doing so, the government aims to ensure that at least 13% of the total power capacity (including geothermal power) uses renewable energy by 2020 and 15% by 2025 (Hayes, 2008; MEMR, 2008). The transport sector is the third largest consuming sector at 37 Mtce (26 Mtoe) for 2005. The transport sector is unsurprisingly dominated by oil products which consist of 53% motor gasoline and 41% diesel (the remainder being jet fuel for aviation). However, in the early part of the 20th century, coal was widely used in the boilers of ships. Subsequent IEA data revisions show how the total final end-user consumption of energy in 2006 remained at around 190 Mtce (134 Mtoe), almost no change on 2005. Despite little change in the overall level, energy prices clearly had an impact on fuel switching, especially among industrial customers. In total, some 5 Mtce less oil and gas was used by Indonesian end-users; almost all of it was replaced with coal.
12
IEA CLEAN COAL CENTRE
3 Energy resources and reserves While this report focuses on coal, it is important to note that the massive export business in both gas and coal resembles some of the earlier trends in oil production and consumption. This could provide a useful indicator of the future of coal and gas production in Indonesia towards the middle of the 21st century if the rise in consumption continues.
3.1
Oil and gas – peaking?
In the past, Indonesia has been described as rich in energy resources. However, a massive rise in production of oil and coal has shortened the lives of the country’s reserves dramatically, and the country itself is painfully aware of the looming crisis for the long-term future of the energy business in Indonesia. In 2006, the BP statistical review gave a state of proven reserves in 2006 for the major fossil fuels. Crude oil had a life of just 11 years, while the life of coal was 25 years. The reserves of natural gas had increased and stood at 35 years. In 2008, the R/P ratio for oil had moved up to 12.4 years, hardly a leap in confidence. Coal remained at 25 years while natural gas improved rather more substantially to 45 years.
life of 40–50 years, the R/P ratio remains more positive than that for coal and crude oil. Oil is a different story, with reported reserves in 2008 being 15% below those of ten years ago. The decline in oil production throughout the 1990s has meant that the R/P ratio is at its highest now than for more than ten years, albeit at a critical level of just 10–15 years. According to MEMR (2007), there still exists the possibility of increasing the reserves base because only 16 out of 60 hydrocarbon basins have been producing oil, while eight basins have been explored but are not yet in production. Of the remaining 36 basins, 14 basins have been explored but evidence of economic reserves has not yet been found. None of the other 22 basins have been explored. Most of the unexplored basins are located at depth offshore in the eastern part of Indonesia. The government enhanced seismic survey activities and has encouraged private sector companies to conduct 2D and 3D seismic surveys which are ongoing. Figure 6, Figure 7, and Figure 8 show the long-term trend in production, consumption, and reserves of the major fossil 25
1800 oil production
1600
Reported natural gas reserves have increased by 40% since 1998 (see Figure 5). Natural gas production has been changeable, but remains higher than in the 1990s. Yet, with a
800 10 600
natural gas
0.4
oil coal
0.2 0
0
1980
Figure 6
70
0.6
5
0
1.4
0.8
R/P ratio - years
200
80
1
15
oil consumption
1000
400
Natural gas, billion m3
Indices of reserves
1200
1.6
1.2
20
1400 Barrels per day, ’000
Oil and gas deposits are found mainly on the island of Sumatra and its continental shelf. The deposits are located on the eastern side of the island in Aceh province. The Arun gas field was discovered in 1971 in the Province of Aceh. The field straddles the coastal plain between the Barisan Mountains and the Strait of Malacca. Condensate-rich gas is found in reef and associated carbonate facies of Lower and Middle Miocene Age that exceeds 300 m in thickness in places. These carbonates occur near the base of a Tertiary Age sedimentary section with a thickness of more than 3000 m (JSCE, 2005).
1985
1990
1995
2000
2005
Long-term oil resource trends (BP, various issues) 80 R/P ratio - years
60
70 60
gas production
50
50
40
40
30
30
20
20 gas consumption
10
10
0 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
Figure 5
Energy reserve trends in Indonesia (BP, 2008)
Prospects for coal and clean coal technologies in Indonesia
0 1982
Figure 7
1986
1990
1994
1998
2002
2006
Long-term natural gas resource trends (BP, various issues) 13
Energy resources and reserves 180
15
resources (for example, land restrictions for wind and hydro exploitation). The WEC publication, the Survey of World Energy Resources, is probably the only globally comprehensive publication to examine the resource limits of all forms of energy resources, despite criticisms made by bodies which represent renewable energy supplies.
10
3.3
25
160 20
Coal resources, Mtce
140 R/P ratio - years 120 100 80 production
40 consumption
5
20 0
0 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007
Figure 8
Long-term coal resource trends (BP, various issues)
fuels. In the late 1980s and 1990s, the R/P ratios of natural gas and oil have been subject to major sudden downward revisions, a probable result of changes made to the data and/or definitions of the reserves. For example, between 1991 and 1997, BP reported Indonesia to have 32,063 Mt of coal, nearly all of which was lignite and subbituminous. Yet in 1998, this figure dropped to 5220 Mt. Clearly, an 84% reduction in reported reserves is not due to the physical disappearance of coal, but the change in definition, or opinion, of what is economically recoverable coal. Since the late 1990s, reported figures have been more consistent, but with the exception of natural gas, coal and oil reserves have been decreasing.
3.2
Coalbed methane
60
Coal – more abundant than oil, but less than gas
This section discusses briefly the life of the country’s coal reserves, while a more detailed discussion on coal qualities and reserves distribution is done in Chapter 4. While coal reserves are healthier than those of oil (the R/P ratio being 20–30 years), the future trend is questionable. The meteoric rise in coal production has put pressure on reserves, which have fallen by 17% since 1998. The R/P ratio unsurprisingly shows a dramatic fall from more than 80 years in 1998, to just 25 years as reported in 2008. The coal R/P ratio does not appear to take an upward trend at any point in the near future unless further coal resources are made economically viable, or production takes a steep decline; both scenarios are possible over the long term. The following chapter looks at the coal reserves and resources in more detail and questions the possible lack of accuracy associated with coal reserves data that could mean Indonesia possesses more coal than perhaps the headline figures.
While not strictly a coal product, coalbed methane, commonly referred to as CBM, co-exists as a separate energy resource contained in and around coal seam structures. Indonesia has potential resources of CBM of some 12,300 billion cubic metres (bcm) making Indonesia one of the largest CBM resources in the world. Compared to natural gas reserves of 3000 bcm, the potential for CBM to supplement existing gas reserves is immense. The reserves to production ratio of natural gas is 45 years; the addition of CBM could more than treble the country’s R/P ratio of methane gas. Some 92% of Indonesia’s CBM gas reserves are classified as highly prospective and located largely in South Sumatra (5200 bcm), Barito (2900 bcm), Kutai (2200 bcm), and Central Sumatra (150 bcm) amongst other areas. The geographical spread of CBM could make it a potentially valuable resource for diversifying energy production across the islands of Indonesia. Recently, CBM has attracted increasing interest in Indonesia. The first project was given to a joint venture between PT Medco E&P Indonesia and PT Ephindo in 2008. Two more projects were signed in the same year, while five more underwent joint evaluation or feasibility studies. Forty-five more applications were also undergoing government review in 2008 (Jakarta Post, 2008c). The Sendawar CBM Project is located within the Mahakam River area of the Kalimantan province, some 190 km inland and 50 km south of Mahakam River. Sendawar was guaranteed a first-of-kind licence granted directly by the Indonesian Government. The potential reserve is 140 bcm of gas (Mazak, 2008).
3.4
Peat
Indonesia has the third largest peat deposits in the world with 270,000 km2 worth of reserves (WEC, 2007). Peatlands are largely found in the subcoastal lowlands of Kalimantan and Sumatra, in common with the deposits of coal. A feasibility study was carried out in the late 1980s regarding using peat for electricity generation in central Kalimantan, but little development resulted from this work.
Energywatch (2007) published a highly critical study of the work done by the World Energy Council (2007) which would also apply to the annual BP Statistical Review. Energywatch focuses entirely on the lack of firm data for coal reserves, but interestingly, no organisation applies the same analysis to any other form of energy, including finite aspects of renewables 14
IEA CLEAN COAL CENTRE
4 Coal reserves This chapter discusses the distribution and quality of coal reserves in the major coal bearing regions of Indonesia. Coal production is discussed in more detail in Chapter 15 and in Chapter 16.
4.1
While most Indonesian coals are low or moderate in ash content, there is wide variability in moisture content. This can influence the calorific value of coals mined and utilised in the country. As such, when discussing reserves and resource data, the true energy value of the reserves or resources could be considerably less than the mass in terms of million tonnes. However, it is normal convention to discuss reserves and resources of coal in mass tonnage terms and so, for the purposes of this chapter, the convention is maintained.
Geographical concentration of reserves
The main coal reserves in Indonesia are found on just two major islands, Sumatra and Kalimantan (Indonesian Borneo). The distribution of reserves is shown in Table 2 by province and in Figure 9 by region. While the figures themselves may be subject to interpretation, the representation of geographical spread is accurate. A little under half of the country’s coal reserves are located in Sumatra, with the balance located mostly in Kalimantan.
Table 2
Kalimantan is the centre for hard coal production from which nearly all the main export business is located, particularly the regions of East and South Kalimantan. The largest reserves in Kalimantan belong to Kaltim Prima and Arutmin, each of which has some 1.0 Gt of mineable reserves. Sumatra has large quantities of mainly lower rank coals. This
Indonesian coal resources by province (CDIEMR, 2007; MEMR, 2007) Resources
Province
Reserves Hypothetical
Inferred
Indicated
Measured
Total
Banten
5.47
5.75
0.00
2.09
13.31
0.00
West Java
0.00
0.00
0.00
0.00
0.00
0.00
Central Java
0.00
0.82
0.00
0.00
0.82
0.00
East Java
0.00
0.08
0.00
0.00
0.08
0.00
Nanggroe Aceh Darussalam
0.00
346.35
13.40
90.40
450.15
0.00
North Sumatra
0.00
7.00
0.00
19.97
26.97
0.00
Riau
12.79
467.89
6.04
1,262.89
1,749.61
1,926.24
West Sumatra
19.70
475.94
42.72
181.24
719.60
36,07
Bengkulu
15.15
113.09
8.11
62.30
198.65
21,12
190.84
1,462.03
36.32
173.20
1,862.39
9.00
13,298.35
9,222.21
13,700.32
12,495.59
48,716.47
11,910.19
0.00
106.95
0.00
0.00
106.95
0.00
42.12
482.60
1.32
1.48
527.52
0.00
122.72
956.01
5.08
194.02
1,277.83
48.59
0.00
5,517.81
334.48
3,435.79
9,288.08
1,684.56
3,224.44
13,696.70
2,540.69
5,669.66
25,131.49
3,075.48
South Sulawesi
0.00
144.93
33.09
53.10
231.12
0.00
Central Sulawesi
0.00
1.98
0.00
0.00
1.98
0.00
North Maluku
0.00
2.13
0.00
0.00
2.13
0.00
89.40
61.86
0.00
0.00
151.26
0.00
0.00
2.16
0.00
0.00
2.16
0.00
17,020.98
33,074.29
16,721.57
23,641.73
90,458.57
18,654.06
Jambi South Sumatra Lampung West Kalimantan Central Kalimantan South Kalimantan East Kalimantan
West Irian Jaya Papua Total
Prospects for coal and clean coal technologies in Indonesia
15
Coal reserves
70
reserve
60
resource (hypothetical, inferred, indicated, measured)
Coal reserves, Gt
50
40
30
20
10
0 South Sumatra
South Kalimantan
East Kalimantan
Figure 9
Indonesian coal reserves by region, Gt (MEMR, 2008a,b)
Table 3
Estimated mineable reserves in Indonesia by coal type
Other
Resources
Of which are reserves
Coal type
Heating value, MJ/kg
Lignite
29.8
0
464
11
188
663
59
0
0
Total as of 2005
3680
33826
12239
10770
60515
7007
0
0
Total as of 2006
17021
33074
16722
23642
90458
18654
13411
5300
Hypothetical Inferred
Indicated
places Indonesia in a dilemma as transporting low rank coals, such as lignite, is costly on a per tonne basis due to the lower heating value. However, solutions to this problem are well under way with coal upgrading to improve the coal quality (see Chapter 22), and generating power closer to the minemouth. Electricity is transmitted via high voltage links (up to 3 GWe) to the island of Java. Indonesia still has the prospect of fuelling its future needs with vast low rank coal reserves that are difficult to transport to the demand centres, and so rendering those coal reserves sterile. Practically all of the reserves in South Sumatra are less than 21.4 MJ/kg (5100 kcal/kg) although resources of up to 25.5 MJ/kg (6100 kcal/kg) have been measured, indicated or inferred, so clearly greater exploration in South Sumatra could give rise to higher rank and higher quality coals over the long term. The provinces of note are South Sumatra, East Kalimantan, and South Kalimantan. However, all other deposits of any 16
Total Total Measured resources reserves and reserves
Probable reserves
Proven reserves
significance are in other provinces of the same islands of Sumatra and Kalimantan. None of the other islands appear to have any reserves of significance. When looking at the level of resources, the picture is much the same, with Kalimantan and Sumatra being the key regions in which coal resides. What is of more interest is the amount of coal that exists in South Sumatra. In fact, most of the coal under the geographical category of ‘Other’ is mainly in Sumatran provinces. Although small resources could exist in some of the other island regions, these are insignificant in comparison to those in the Sumatra and Kalimantan regions.
4.2
Quantity of coal reserves
In terms of quantity, official figures published by the Center for Energy and Mineral Resources in the Handbook of Energy and Economic Statistics of Indonesia show a substantial IEA CLEAN COAL CENTRE
Coal reserves reserves base of 18.7 Gt. A potential of 90.5 Gt of resources is also estimated, but this consists largely of coal that is not yet proven to be recoverable (see Table 3). If only coal that is recoverable is considered (using existing economic and operating conditions), then the reserves base could be as little as 4.3 Gt (WEC, 2007; BP, 2008). Coincidentally, this figure of 4.3 Gt is also equal to the reported mineable reserves belonging to the top five producers in Indonesia alone. As such, it is possible that these reserves figures are grossly underestimated. Given the nature of delay for data acquisition and publication, it is likely the reserves figures published in 2007 by the WEC refer to data for 2005 at best. New surveys and further exploration may well give rise to an upward revision of the country’s economically recoverable reserves. Official figures published by ICMA (2006) and later by MEMR (2008) suggest that in 2005 Indonesia had almost 7 Gt of ‘mineable’ reserves, which include proven and probable reserves. Later publications by MEMR (2008b) suggest that there are 18.7 Gt of reserves (as of 1 January 2007), of which 5.3 Gt is proven and 13.4 Gt is probable. Therefore, the latest figures would suggest that both proven and probable reserves have increased in recent years, contrary to the trend in reported reserves over the long term. However, pinning down an accurate set of reserves figures by coal rank (for example anthracite, bituminous, lignite, and subbituminous) is less straightforward. MEMR presented a comprehensive table of coal qualities in the Indonesian Coal Book 2006/2007 to the IEA in Paris in February 2008 (ICMA, 2006; MEMR, 2008a). Both references refer to reserve levels in 2005, and while dated, provide a useful indicator of how much Indonesia has of each coal. Table 3 shows the amount of coal that Indonesia had in 2005 by each major coal type. Whether the same coal-split is applied to the recently published resource and reserve figures for 2006, and are significantly higher than those in 2005, is not certain, since total reserves have risen from 7 Gt to 18.7 Gt (both proven and probable). This rise is substantial, and while there has been criticism of the lack of exploration in the coal business for new reserves in the past, clearly there are efforts to exploit the high prices seen in 2005-08, as well as interest from companies like Reliant Energy of India, to develop new facilities and develop concessions.
4.3
Summary of coal quality definitions
Indonesia has reserves of coals that range from bituminous, subbituminous, and lignites. Although anthracite is mined, the quantities are relatively small. This wide range in coal rank across the country’s coal deposits gives rise to a cautionary note when looking at coal reserves figures in Indonesia. The data published by the Ministry of Energy and Mineral Resources (MEMR) comes in several aggregated and disaggregated forms. Provincial reserves (for 21 provinces) of coal are published in the Handbook of Energy & Economic Statistics, as well as the Key Indicators of Indonesia Energy and Mineral Resources (CDIEMR, 2007; MEMR, 2007). Aggregated data tables for both six major regions and national Prospects for coal and clean coal technologies in Indonesia
reserves are also available which split the reserves by coal heating value (ICMA, 2006; MEMR, 2008a). The discrete ranges of (assumed net) calorific value used by these publications are associated with the most appropriate lignite category as follows: MEMR classification, kcal/kg
Approx MJ/kg equivalent*
Likely rank
30 anthracite * for a more exact MJ/kg, multiply kcal/kg by 0.004187 These ranges are broadly consistent with definitions for the major coal rank types, but are not exact and do not include other quality parameters such as ash, sulphur and moisture. Where there might be some limited data on peat, it probably belongs to the lignite category of being less than 21 MJ/kg, but is not likely to be significant. The International Coal Classification system devised by the ECE and approved by the ISO uses a series of classes ranging 0 to 15 (anthracite to lignite). Soft coals have a gross calorific value of less than 23.8 MJ/kg (5684 kcal/kg; moist ash free), and therefore hard coals are above this threshold. They are defined by their calorific value at equilibrium moisture content together with tar yield on a dry ash free basis. Australian classification adopts a similar approach. The classification of different rank coals is based on a combination age, but moisture content is a useful indicator of rank for low rank coals (see Figure 10). The most difficult classification is probably subbituminous which overlaps with both lignite and bituminous coals, and is the most abundant coal in Indonesia. Consequently, it is no surprise that pinpointing exact reserves figures by rank is not straightforward, and may be why the MEMR uses the method of coal heating value. From this summary, some subbituminous coals have moisture contents in the range of 10–35%, and heating values can be as high as some bituminous coals. Lignite coals seem to have a moisture content of 35–75% by volume (as mined). Heating values are typically less than 15 MJ/kg (3600 kcal/kg), while the coals also possess higher content of volatile matter making them potentially hazardous for storage and transportation. They must be handled with some caution to avoid uncontrolled combustion. High volatile content products can be modified by blending with lower volatile bituminous coals. Coal classification acts as a mere guide to assessing the potential market and use of a particular coal. Ultimately, coal sampling analysis throughout the supply chain acts as a verification when performed by certified third parties. More detailed knowledge of ash properties, trace elements and the physical nature of the coal are important aspects, aside from the headline figures of heating values, sulphur content, and moisture content. Prior to formal supply agreements it is 17
Coal reserves
anthracite 30
LHV, MJ/kg as mined
low volatile 20
bituminous high volatile
Indonesian coals are low in sulphur, but have high volatile matter and moisture contents compared with, say, Australian coals. Impediments to the coal’s use in power plants are its high grinding hardness of 40–50 HGI (Hardgrove Grindability Index) and a propensity for spontaneous ignition.
10 subbituminous lignite
Moisture, % as mined
0
Higher rank such as bituminous and subbituminous coals do not generally require preparation, and simple crushing and screening will suffice to make a marketable product. In general, Indonesian coals have no, or only minimal, coking properties, so – with few exceptions – can only be used as steam coals. Only some higher rank coals are suitable as pulverised coal injection (PCI) feedstock.
100
50
0 Rank
Figure 10 LHV and moisture content of coal of various ranks (IEA CCC, 1983) common for coal to be tested in boilers to understand all these aspects of a coal’s behaviour and to ensure compatibility with the end-user’s equipment. The difference between low rank coal (which has undergone less coalification than higher rank coals) and a low grade coal (which may have a high ash content and consequently a lower heating value) is important. Low grade coals may indeed be of bituminous rank such as those found all over the world such as countries like India. Indonesian coals, being low ash and low sulphur, are probably not considered low grade, but lower in rank compared with perhaps the average bituminous coal that is traded internationally today.
4.4
Indonesian coal quality
Indonesia is unique in that coal exports often border on the low-mid rank qualities of subbituminous coals. According to official reports, half of the Indonesian coal reserves are considered to be of lignite quality, with bituminous and subbituminous each accounting for a quarter of the reserves. The remainder consists of subbituminous coals, which still have a value on the export market due to the ultra-low sulphur content of many of these coals. Indonesian export coals are low in ash, but also low in 18
calorific value due to high moisture content. Heating values average approximately 19–23 MJ/kg as received (4600–5500 kcal/kg), although some anthracites are mined which have heating values in excess of 29 MJ/kg (7000 kcal/kg air-dried basis). However, these are not typical of the bulk of the output. Indonesian coals are therefore notably lower in heat content than most seaborne traded coals, but nevertheless, are attractive to buyers looking to reduce the sulphur content in their blends. The blending also compensates for the lower heating value of the Indonesian coals. At the lower end of the heating value range, coals that are less marketable as export products are sold to domestic industrial consumers and power stations.
Indonesian export coals generally have a 31–47% volatile content, with 1–12% ash and typically 10–23% moisture. The sulphur content is below 1% and, in extreme cases, as low as 0.1 %. South Sumatran coals have heating values as low as 15 MJ/kg (3640 kcal/kg) mined by Adimas Batujara Cemerlang, while PTBA produces a range of coals in Sumatra some of which are anthracite with heating values of 33.5 MJ/kg (8000 kcal/kg). On average however, South Sumatran coals lie within a 21–27 MJ/kg (5000–6500 kcal/kg) range and generally have very low sulphur contents, so are generally not lignites in quality. Characteristically, ash contents also are low ranging from 1% to 15%. However, moisture contents can exceed 60% in some coal blocks, while for the anthracites and bituminous coals it is 2–17%. In Kalimantan, the bulk of reserves and production are located in the East and South Provinces. The development of mines in Central Kalimantan is ongoing along with the exploration of deposits. East Kalimantan has a higher proportion of higher rank coals with heating values of 25.5–29.7 MJ/kg (6100–7100 kcal/kg). Over the long term, the resource that is yet to be proven (as a reserve) is of lower rank 21.4–25.5 MJ/kg (5100–6100 kcal/kg), and so the long-term future of East Kalimantan is likely to be based on medium quality coals. The coal quality is universally better than that found in South Sumatra, with good common traits such as low sulphur content and low ash, while the higher rank nature of the coals means moisture contents are little more than 20% for the larger producers. Interestingly, the larger producers have rights to coals that average less than 25 MJ/kg (6000 kcal/kg) such as Berau, KPC, and Kideco. Indominco Mandiri, and Kartika Selabumi Mining and a number of smaller operators IEA CLEAN COAL CENTRE
Coal reserves have reserves of coals of more than 25 MJ/kg making them favourable prospects. South Kalimantan is where PT Adaro operate and the Envirocoal brand is mined. Here the coals are mainly medium quality with heating values of 21.4–25.5 MJ/kg (5100–6100 kcal/kg). The resource base is of similar quality and so the longer-term future production will probably consist of the same quality coals as are mined today. The extremely low sulphur and ash contents make the coal very attractive to international buyers looking to improve emissions and waste.
mineable (economically recoverable) reserves. Efforts to explore further reserves are needed to firm the published reserves figures. Those coals that are exploited are invariably low in sulphur and ash content by world standards, but can also be low in heating value due to high moisture contents, especially amongst the lignites and subbituminous coals found in Sumatra. Low sulphur coals that are exported from Kalimantan are regularly shipped to blend with higher sulphur coals around the world.
Arutmin has reserves of coal with heating values of less than 4400 kcal/kg while being branded as ultra low sulphur. The products which are mined at Asam Asam and Mulia (Ecocoal brand), remain acceptable for transportation due to these low sulphur contents. Moisture contents are low across almost all coals in South Kalimantan, as is the average ash content.
4.5
Coal geology
Indonesian coals are present in relatively shallow formations, and so identifying coal resources should be reasonably straightforward compared with identifying resources located deep underground. However, this does not mean that shallow reserves are necessarily easier to mine, since faulting, fragmentation, and steeply dipping seams of shallow reserves might be more difficult and more costly to mine than an undisturbed underground seam. One of the main features of Indonesian coal reserves is that seam dip angles are generally low, but can increase to as much as 85° in seams at the Kideco Roto South Mine. Faulting has brought some deeper seams closer to the surface making mining easier. Mining coal in Indonesia is therefore extremely attractive, and geologically more favourable than mining in many other parts of the world where deep mining is more commonplace. Indonesian coal deposits are perfect for opencast extraction since the coal deposits are characterised by thick shallow seams. Coalfields in Kalimantan are accessible to tidewater, which facilitates transport to deep water loading jetties. According to Walker (2000) only a small proportion of Kalimantan coal resources has been explored in any detail, hence the wide range in quoted resource/reserve figures. Future developments will be in less accessible areas, but could still benefit from existing installed infrastructure. These future resources must be exploited to preserve the long-term future of coal supply in Indonesia.
4.6
Summary
In summary, Indonesian coal is found on the islands or Kalimantan and Sumatra. Kalimantan is the main hub of production which contains coals of internationally tradeable quality. Sumatra is the key resource for low rank and high moisture coals, which will best serve domestic markets. The reserves of coal in the whole country are difficult to quantify with any certainty, with figures ranging from 4.3 Gt to 7 Gt of Prospects for coal and clean coal technologies in Indonesia
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5 Structure of the Indonesian coal industry The coal mining industry in Indonesia developed in the 1980s and has since flourished into a leading export industry. The market was opened up to foreign investment and expertise, which spearheaded the massive drive to exploit the nation’s rich reserves in Kalimantan. Private sector investment has taken place within a framework of government licences covering coal production. Within this framework, licences permit exploration, development and production for a set period of up to 30 years. The influx of foreign firms into the Indonesian coal sector has increased domestic expertise in mining to some extent, although mining consultants and contractors are invariably foreign companies themselves. This is discussed later in the chapter. Until changes that occurred in 2008/09 (see Section 15.3), production licences were issued under Law No 11/1967 on the Basic Provision of Mining, which regulates enterprises when conducting mineral exploration, development, and production in Indonesia. Coal production is split into four distinct groups, they are discussed as follows: 1.
The holders of coal contracts of work (CCoW) or contracts of work (CoW) and mining licences – comprise companies formerly owned by foreign multinationals and/or Indonesian private companies that produce the bulk of the country’s coal through a series of three generations of contracts that were licensed in 1984, 1994, and 1997. These have subsequently been named First, Second and Third Generation contracts respectively The history of these contracts is discussed in Section 15.1. The licence is granted once for all stages of survey, feasibility, construction and operation. The maximum area permitted for these activities is 100,000 ha and must be clearly delineated in the application. Up to 25% must be relinquished at the end of the exploration period. First Generation producers are of great significance as they constitute the bulk of the country’s current production, and will do so until around 2014-15 when most licences will either expire or be extended (under the current rules). The remainder of the production is from Second and Third Generation contracts, which are Indonesian companies – in strong contrast to the foreign domination of the earlier years of the First Generation producers.
2.
PTBA – PT Tambang Batubara Bukit Asam, the one state-owned company operating two mines in Sumatra. PTBA is discussed in more detail in Chapter 8.
3.
Kuasa Pertambangan (KP) mining authorisation holders – Before 2009 KP licences were reserved only for national private companies: these provide licences to survey a maximum 5000 ha, explore a maximum 2000 ha, and exploit a maximum 1000 ha. Regional autonomy now permits local governors, regents, or
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mayors to award KP licences and will replace the CoW, permitting foreign companies to hold KPs (see Section 15.3). 4.
Cooperative units (KUDs) – consisting of local village cooperatives that do not mine for export.
In 2006, First Generation producers still accounted for an estimated 80% of planned production making these early contracts the dominant players in the market. Originally, there were ten First Generation contractors; they are listed in alphabetical order: I. II. III. IV. V. VI. VII. VIII. IX. X.
Adaro Indonesia Allied Indocoal Arutmin Indonesia Berau Coal Indominco Mandiri Kaltim Prima Coal Kendilo (now ceased operation) Kideco Jaya Agung Multi Harapan Utama Tanto Harum
The ‘contractors’ undertake to prospect for and explore the coal deposits located in their concession area, and possibly to engage in mining development. In return, they are granted exclusive rights for a term of 30 years subject to a royalty (free mine) of 13.5% of proceeds. The contractors are also obliged to offer Indonesian investors at least 51% of the mining stock after a ten-year operating period. In 2001, this provision affected two foreign investors (Rio Tinto/BP and BHP-Billiton). Most of the companies are based on First Generation CCoWs, representing over 140 Mt, Second Generation CCoWs with about 50 Mt, and Third Generation CCoWs with a mere 10 Mt. Holders of any licence have a number of rights and obligations that set out the conditions for each stage from survey to production, particularly those operators holding CCoWs. Either the licencee or the issuing authority can withdraw at any stage if the conditions are breached. Some of the conditions on the part of the contractor also include the provision of expenditure. In Kalimantan, contractors must commit to spending 3 $/ha at the survey stage, and 10 $/ha during exploration. This must be done within a set period of 12–24 months. Feasibility and construction stages require more detail and set out the intention to exploit specific commercially viable deposits and environmental impact assessments. Operation is typically fixed at 30 years, although it is possible to apply for extensions. The CCoW licences also oblige the holder of the licence to make a number of payments to the state: ● minimum of 13.5% of annual production to the government which includes the royalty; ● US$100,000 lump sum regional tax; and ● 35% corporate tax on income for the first ten years, and then 45% thereafter. IEA CLEAN COAL CENTRE
Structure of the Indonesian coal industry KP licence holders have a different regime, but nonetheless include payments of land lease, royalties, and state levies. Typically, the royalty structure is more lenient, with KP producers being levied just 7%, instead of the 13.5% for CCoW licence holders. However, this may change under the new Mining Law announced in 2008. Interestingly, the CCoW holders of First Generation contracts are nearing the end of the 30 year licence, or are within ten years of expiration. Perhaps it is a combination of rising market prices to record levels, plus the finality of the licence that drove the industry to ramp up production between 2000 and 2008. Moves to either consolidate or nationalise the industry cannot be ruled out over the long term although there is no indication that this is being contemplated. Sovereignty of mineral reserves may be seen as strategically more important to serve local demand rather than the export business. However, with steam coal trading at record prices, coal exportation is clearly not a strategic decision the government wants to abandon immediately. The uncertainty about changes in the regulations for mineral production might be encouraging contractors to exploit reserves as quickly as possible, especially as the reserves are some of the lowest cost in the world market, and relatively easy to extract. However extraction is becoming harder for many operations. The current status of industry is in flux and is discussed at the end of this chapter.
5.1
Foreign ownership – a common feature of the coal industry
While the state is pondering whether to maintain or modify the regulations that govern the coal industry, there is no shortage of interest from foreign-owned corporations. Interestingly, the involvement of the global mining giants such as Rio Tinto and is not as high profile as elsewhere around the world, except in perhaps the trading of Indonesian coals. Japanese and South Korean firms are well established within the Indonesian coal industry, but it is the Chinese, Indian and now Middle Eastern firms which seem to be emerging. One notable example is the Indian power generator Reliance purchased three coal concessions in South Sumatra to supply power plants in India, including the 4000 MWe Krishnapatnam plant which is expected to consume 12–15 Mt/y (MCIS, 2008c). Some 25 Mt/y could feed this and a number of other power projects in India. The additional production arising from these new concessions represents a significant increase on today’s output. The concessions are located at greenfield sites with little or no infrastructure and are surrounded by hilly terrain. Reliance is planning to spend $1 bn on shipping and logistics infrastructure including four Capesize and four Panamax vessels. Shipping between Sumatra and the port of Krishnapatnam (due for completion in 2009) takes two days less than vessels sailing from Kalimantan. The shorter distance therefore means two fewer days of charter rates and a delivered price of 10–15% less Prospects for coal and clean coal technologies in Indonesia
than the price that Tata pays to buy coal from its mines at Kaltim Prima and Arutmin – where Tata has a 30% stake in the mines’ parent company BUMI Resources. The Krishnapatnam power plant will be commissioned in 2013, so while production at the mine may start by 2009, it is not scheduled to reach design capacity until the power station starts operating. In the interim, production might be low, perhaps supplying the export market, or smaller tonnages to other units operated by Reliance. The East Kutai mining project in East Kalimantan could supply coal to Indian and Chinese power stations. The potential to secure contracts from such coal dependent economies and the high returns earned during a period of high coal prices led UK firm Churchill Mining plc to acquire a majority 75% stake in the project (Mazak, 2008). What makes this significant is that the Pakar coal discovery, located 55 km southwest of East Kutai, has a reserve base of 270 Mt, and could potentially be one of the largest producing mines in Indonesia. However, production could be increased to anywhere between 5 and 20 Mt/y within a few years of operation (which started in 2008). While the coal qualities are suitable for customers in China and India, the company also signed an agreement with the Indonesian power utility PT Ridlama Bangun Mandiri (PT RBM) to supply coal for 30 years to feed two power plants that are being built in Kalimantan. The agreement will secure 840,000 t/y at a 5% discount to the prevailing market price. Based on these figures the power plants are unlikely to be much greater than 250 MWe each, but the 30-year contract is seen by financial analysts as promising because it demonstrates the quality of the coal (Emery, 2008). PT RBM is investigating the potential of building other, larger power plants within Kalimantan. Another company seeking to expand its presence in Indonesia is the Singapore-based business Straits Asia Resources. The company has already acquired the Sebuku mine which produces 2–3 Mt/y in South Kalimantan. Sebuku coal sells for a price of 70 $/t (26 MJ/kg or 6300kcal/kg air-dried basis), though unusually 1.5 Mt was contracted for 2008 at prices of around 45 $/t. This means that Straits Asia Resources will have committed to 2008 tonnage at prices perhaps 60% below the world market price. By the end of 2007, Straits agreed a deal to acquire a 100% interest in the Jembayan coal mine in East Kalimantan for $350 million (MCIS, 2007b). Production at Jembayan was 4 Mt/y in 2007 with the potential to produce 7.5 Mt/y with some additional capital expenditure. Straits Asia Resources acquired the shares which previously belonged to Anugerah Bara Kaltim (82%) and Mitsui Matsushima (18%). The operation is just 70 km from the coast and produces low sulphur, low ash subbituminous coal, similar to that produced by Adaro, Kideco, and Kaltim Prima. The following chapters are brief descriptions of the larger coal producers in Indonesia and the information was the best available at the time of writing. However, ownership and production can change frequently. Chapters 6 to 13 describe the major corporations that make up much of today’s coal industry in Indonesia that (mostly) operate under the CCoW licence regime, with the exception 21
Structure of the Indonesian coal industry of the state controlled PTBA (Chapter 8) . This chapter also accompanies the infrastructure maps for major export operations illustrated by Figure 12 for Kalimantan and Figure 13 for South Sumatra found in Chapter 17.
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6 PT Adaro Indonesia Key Facts Main mine location: South Kalimantan, Borneo Status: First Generation CoW Production in 2007 (rank): 36 Mt (2nd) Approximate production to date (1992-2008): 289 Mt Estimated mineable reserves in 2008 (R/P): 336 Mt (9–10 years) Coal resources, Mt: 2069 Mt As of 2007, PT Adaro was the second largest producer of coal in Indonesia, although this could change in the future. Adaro produced 36 Mt in 2007, up from 34 Mt in 2006 but down from a previous forecast of 37 Mt (MCIS, 2008a). In 2006, Adaro’s production was almost fully contracted under term or annual agreements. The rest was sold on the spot market. Long-term contracts secure 25% of sales and supply. The supplier is targeting production of at least 38 Mt in 2008, rising to 42–43 Mt in 2009. Given the company’s mineable reserves, more exploration and development will be needed. It is likely that the coal reserve figures have not been revised and given the company’s expansion plans for production, a great deal more coal must exist in economically recoverable reserves than these numbers suggest. PT Adaro Indonesia is part of the Adaro Energy group of companies. The parent company underwent a corporate change with an initial public offering (IPO) of shares in 2008, the proceeds of which were used to buy a number of companies along the supply chain. This gave Adaro greater control over its entire export operation. As of 2008, the ownership structure of PT Adaro Indonesia was not clear, due to the share issue of the parent company Adaro Energy. Some 34.8% of Adaro Energy was sold under the IPO, but while the IPO helped in infrastructure development funding, it also provided funding for a buyback of foreign-owned interests in Adaro Energy such as those held by Farallon Capital and the Government of Singapore Investment Corp. Prior to the IPO, the investment arm of Adaro Energy called Alam Tri-Abadi owned 60% of PT Adaro Indonesia, the coal production wing. Now, Alam Tri-Abadi has been partially sold, it is not clear how the structure currently stands. However, PT Adaro Indonesia has a concession, which is in operation until October 2022. There is the potential for an extension of the contract for another term under a mutual agreement with the government.
largest single coal mine in the country. Wara is under development while Paringin has ceased producing. Overburden and interburden removal is done using hydraulic shovel and truck. Coal is also extracted by shovel and trucks. The stripping ratio is very low (4:1). Stripping ratios refer to the volume of overburden (topsoil, earth and overlying rock) that needs to be removed to yield a single tonne of coal (ROM). Stripping ratios are examined in detail by Baruya (2007). Adaro uses four contractors to carry out mining activities at the Tutupan area. ROM coal is stockpiled adjacent to the pit before being taken by truck 80 km to the Kalanis barge loading facility where the coal is also processed. The road is all weather and, like the mining, the haulage is contracted to third party companies. At the Kalanis barge loading facility, coal is screened to a size of 50 mm; any oversized coal is crushed to 50 mm. The coal is then transferred by a conveyor to one of two stockpiles each holding 200,000 t, or is loaded directly to barge. Conveyors transfer the coal to the barge at a rate of 2000 t/h. Barge loading takes on average five hours for barges of between 6000 dwt and 14,000 dwt. The barge is then towed by tug for 200 km down the Barito River to the river mouth where coal is transferred in any of the following ways: ● 14 km offshore to a trans-shipment facility at Taboneo; ● 250 km south east to Pulau Laut where the PT Indonesia Bulk Terminal (IBT) is sited; or ● direct to Indonesian customers. The trans-shipment facility is a floating crane barge or self geared vessels. Three loading cranes are each capable of 10,000 and 15,000 t/d. Capesize vessels of 100–200,000 dwt can be loaded. The PT Indonesian Bulk Terminal (IBT) is a common user port facility located off the south east coast of Kalimantan on the island of Pulua Laut. It has a sheltered deep water location for bulk carriers where coal is stockpiled for transfer to ships. Pulau Laut also provides the opportunity to blend coals for the final consumer. Adaro’s expansion plans include a massive 32 km conveyor system that will link the Wara mine within 36 km of the Kalanis Barge Terminal. Adaro plans to increase production from 36 Mt to 80 Mt/y by 2011 making Adaro the biggest coal producer in the country.
The main reserves are located on the north-eastern margin of the Barito Basin which is up to 250 km wide. The coal deposits were laid down in the Eocene to Pliocene age. There are eight separate deposits which are all surface mineable. Coal deposits are found in three areas, Paringin, Tutupan, and Wara, but production is concentrated in the Tutupan mine, the Prospects for coal and clean coal technologies in Indonesia
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7 PT Arutmin Indonesia (BUMI Resources) Key Facts Main mine location: South Kalimantan, Borneo Status: First Generation CoW Production in 2007 (rank): 15 Mt (4th) Approximate production to date (1990-2007): 163 Mt Estimated mineable reserves in 2005 (R/P): 1300 Mt (60 years) Coal resources, Mt: 3726 Mt Arutmin is one of the major mining companies owned by BUMI Resources, the single largest coal mining group in Indonesia. BUMI is part-owned by the powerful Bakrie family conglomerate whose industrial empire spreads across a range of industries including telecommunications. According to the corporate website (www.bumiresources.com), as of July 2008 more than 81% of BUMI was publicly owned, with some 7% owned by the PT Bakrie & Brothers, and the remaining 12% owned by various US banking interests. BUMI plans to boost output from all of its operations from 60 Mt to 100 Mt by 2011 (MCIS, 2008b). The coal products from the two major production companies, Arutmin and Kaltim Prima, are treated as distinctly different brands by the trade press and publications, and so these two companies are treated separately. In 2006, Arutmin exported 12.5 Mt. By 2007, the company produced 15.3 Mt making it the fourth largest behind its sister company PT Kaltim Prima, PT Adaro, and PT Kideco Jaya Agung. Australia’s BHPB plays an important role marketing Arutmin’s products worldwide while Indonesia’s Enercorp Limited markets the coal domestically.
government in December 1990. Senakin (Arutmincoal) coals lie in gently dipping deposits (5–15°), and mining in the past has taken place in three locations along the coal seam. Coal is crushed and washed to lower the sulphur content. Satui (Arutmincoal) coals are crushed but remain unwashed due to the low ash content. The Ecocoal mined in Asam-Asam and Mulia is extremely low ash and low sulphur and needs only crushing. The seams lie in shallow ground and so have the advantage of having low strip ratios. The seams are also thick which makes production straightforward using the usual truck and shovel methods. Overburden and coal extraction require minimal drilling and blasting which reduces costs. Coal is not transported directly to port, but rather goes through several steps before finally ending up at Arutmin’s main port on the island of Pulau Laut. From the mines, coal is hauled by truck to the barge ports at Sembilang, Muara Satui, and Air Tawar 2. The distances to these ports are short, typically 27 km; the longest is 50 km which is still not excessive. Coal is stockpiled at the barge ports and crushed where necessary. At the barge ports, Arutmin operates a fleet of eight custom-built, self-discharging barges of 7000 and 3500 dwt capacity. These barges either take the coal to domestic and regional customers directly, or transfer it to the North Pulau Laut Coal Terminal (NPLCT) or trans-shipment point. NPLCT is a deep water port capable of accommodating 160 vessels of Capesize capacity up to 180,000 dwt every year. Arutmin is the operator of the port. While the vessels remain stationary in port, loading can continue using conveyor systems that run along the length of the ship.
Most of the business is contracted for a year or longer, although stocks are capable of supplying short-term spot trades. Arutmin produces two major brands of coal, Arutmincoal (bituminous) and Ecocoal (subbituminous). The former has low sulphur, low ash and high heating values, but the Ecocoal is the increasingly popular brand with what is considered ultra low sulphur, averaging just 0.13% (compared with Arutmincoal at 0.51–0.85%). The volatile content and calorific content of the Ecocoal is lower than the Arutmincoal product. PT Arutmin operates a concession area known as Kalimantan Block 6 located across several narrow strips in the south east of Kalimantan and north west of Pulau Laut Island. The company’s lease covers an extensive reserves base of bituminous and subbituminous coals which shall maintain production levels for up to 30 years. However, at the current rate of production the reserves could feasibly extend to more than 50 years. The current reserves base is located in just 6% of the original concession area, 94% of which was relinquished to the 24
IEA CLEAN COAL CENTRE
8 PTBA (Tambang Batubara Bukit Asam Tdk) Key Facts Main mine location: South Sumatra, West Sumatra Status: First Generation CoW Production in 2007 (rank): 11 Mt (7th) Approximate production to date (1992-2007): 150 Mt Estimated mineable reserves in 2005 (R/P): 1500 Mt (120 years) Coal resources, Mt: 3726 Mt PTBA is a state-owned company established in 1981 with an overarching mission to support and implement government programmes for the coal mining sector. The company’s reserves consist largely of lignite (60%), subbituminous coal (37.1%), and bituminous coal (40%), and so PTBA’s interests are largely in lignite and subbituminous production. The company’s activities include general survey, exploration, exploitation, production, refining, transportation and trading, maintenance of special coal port facilities for internal and external needs, operation of steam power plants and providing consulting services related to the coal mining industry. PTBA has two subsidiaries, PT Batubara Bukit Kendi and PT Bukit Asam Prima, which are engaged in coal mining and coal trading respectively, and three inactive subsidiaries, PT Bukit Asam Metana Ombilin, PT Bukit Asam Metana Enim and PT Bukit Asam Metana Peranap. The company runs two mining units, the Tanjung Enim in South Sumatra, and the Ombilin Mining Unit in West Sumatra. Coal is also purchased from its subsidiary PT Batubara Bukit Kendi which operates in Kalimantan. Coal from Bukit Kendi is blended with coal from Tanjung Enim due to the low calorific value of the Kalimantan coal. Coal produced in Sumatra may be subject to supply disruption on the rail link between the Tanjung Enim mine and the Tarahan Terminal, and so contracts exist to purchase coal from other Kalimantan producers to supplement production from Sumatra. By 2012, a railroad upgrade is expected to be completed in Sumatra that should allow PTBA to increase exports of steam coal from Tanjung Enim by an estimated 0.5 Mt/y. Among PTBA’s domestic customers are the Suralaya coal-fired power plant and the Bukit Asam minemouth power plant PT Semen Baturaja. Coal exports are shipped through the Tarahan Port with a throughput capacity of 6.8 Mt (figures for 2005), and also the Kertapati pier. However, it is apparent that transportation problems are a regular occurrence and whether PTBA has a growth future will be questionable. Since production started in 1992, PTBA successfully increased output from 7.1 Mt to almost 12 Mt in 2000. However, output has since dropped and barely recovered to just 11 Mt.
Prospects for coal and clean coal technologies in Indonesia
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9 PT Berau Coal Key Facts Main mine location: East Kalimantan, Borneo Status: First Generation CoW Production in 2007 (rank): 12 Mt (5th) Approximate production to date (1994-2007): 77 Mt Estimated mineable reserves in 2005 (R/P): 1235 Mt (102 years) Coal resources, Mt: 2927 Mt PT Berau Coal is almost half owned by foreign corporations, the Dutch Company Rognar Holding BV (39%) and Sojitz Corp (10%). Berau is in the fortunate position of having some of the country’s largest reserves of economically recoverable (mineable) coal. It has some 1235 Mt. Berau Coal produces a range of subbituminous coals, which benefit from low ash and sulphur contents, and moderate heating values which make the coals suitable for most thermal applications, but also capable of export when blended. The coal is mined in opencast mines using truck, shovel, and bulldozers for overburden removal and coal extraction. The mining is done by contractors under long-term agreements. Three mines (Lati, Binungan, and Sambarata) use hydraulic excavators. Coal from each mine is then hauled a short distance (4.5–13 km) to a coal processing plants. Each processing plant has crushing facilities which reduce the size of the coal to 50 mm. Coal blending is carried out at the port areas. The three ports serving the mines are Lati, Sambarata, and Saran. The ports have a stockpile capacity of 140,000 t, 75,000 t, and 200,000 t respectively, and are equipped with conveyor facilities to load coal onto barges.
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10 PT Kideco Jaya Agung Key Facts Main mine location: East Kalimantan, Borneo Status: First Generation CoW Production in 2007 (rank): 21 Mt (3rd) Approximate production to date (1993-2007): 144 Mt Estimated mineable reserves in 2005 (R/P): 979 Mt (37 years) Coal resources, Mt: 3772 Mt
distances between mine, crushing plant and coal export terminal are short. Around 60 trucks haul the coal 39 km between crushing plant and the export terminal. As of 2005, TMCT was capable of stockpiling 700,000 t with throughput capacity of 14 Mt/y. Three coal loaders load 8000–12000 dwt barges which transport coal 58 km to the Adang Bay trans-shipment point off the coast of East Kalimantan. Loading can be done by two floating cranes with an annual loading capacity of 3.5 Mt and Capesize (80–180,000 dwt) vessels are readily berthed, as the trans-shipment point is located in deeper water.
Kideco supplies both international and domestic markets. The domestic power market accounts for roughly a third of the company’s tonnage produced (around 5–6 Mt out of 19 Mt). A major domestic customer is the Paiton power plant units 5 and 6 of Phase II, and units 7 and 8 of Phase I. Other power plants include Suralaya, Newmont Nusa Tenggara. Most of Kideco’s international business is with Asian and European utilities as a blend fuel to lower sulphur in other bituminous coals. PT Kideco is similar to PT Berau in that it is 49% owned by foreign companies. Samtan Co Ltd of South Korea owns the entire 49%. Korea-Indonesia Resources Development Co Ltd (Kideco) was set up in 1982 and included other industrial and transportation interests. Kideco employs 5000 contractors, while the permanent staff include 38 Korean nationals, and 468 Indonesian workers. Mining started in 1993 after several years of exploration and feasibility studies. One of the original minority shareholders, Samhock Consolidated Coal Mining, took overall control through its parent company, Samtan Co Ltd. As with all foreign interests, after ten years more than 50% of shares must be held by the government or Indonesian companies (PT companies). Over the same time, Kideco’s concession area has reduced to around 50,400 ha. Within this area, Kideco has four producing areas at Roto, Samu, Susubang, and Pinang Jatus. At the company’s Pasir coal mine, seam thicknesses measure 5–60 m. Pits are being developed in Roto North and the South and Samarangu areas. In common with the rest of Indonesia, the coals have generally modest calorific values averaging 22–25 MJ/kg (5250–5980 kcal/kg) for Kideco’s products, but also low sulphur (0.24%), very low ash (3.1%), and moisture (19.8%). Coal is produced using opencast methods of truck and hydraulic shovel for overburden removal. Kideco employs the contractor PT Thiess. Initially, Thiess provided plant equipment, but the contract has since progressed to a full coal hauling agreement. Coal is crushed in a nearby plant capable of processing 48,000 t/d. Coal is not washed as the ash content is low, but crushed and sized, and stockpiled before transportation by truck to the Tanah Merah Coal Terminal (TMCT). Truck is the most suitable form of transport as the Prospects for coal and clean coal technologies in Indonesia
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11 PT Kaltim Prima Coal (BUMI Resources) Key Facts Main mine location: East Kalimantan, Borneo Status: First Generation CoW Production in 2007 (rank): 39 Mt (1st) Approximate production to date (1991-2007): 268 Mt Estimated mineable reserves in 2005 (R/P): 1300 Mt (36 years) Coal resources, Mt: 3726 Mt KPC is a First Generation CoW producer operating in East Kalimantan. Production started in 1991, with 2 Mt produced in the first year. Within 24 months the operation was producing 7 Mt/y. In 2003, PT BUMI Resources Tbk acquired KPC and has subsequently spearheaded a massive rise in production. In 2007, KPC was the largest producer of coal in Indonesia with production of 38.9 Mt.
Provided the weather conditions are good, loading can occur all year. The ships are capable of moving 4700 t/h. Also at Tanjung Bara is a barge loading facility with barge capacities of up to 7500 t, which take roughly 7–8 hours to load. Trans-shipping loading systems are carried out 1km offshore by two systems. The first trans-shipper is a geared vessel located at Tanjung Bara or Lubuk Tutung anchorage. This is capable of trans-shipping 10,000 t/d. The second trans-shipper is a gearless vessel capable of transferring enough coal to load Capesize vessels. This is done by a floating transfer station (FTS) that can load at 1000 t/h, transferring coal from barges to ships using twin grabs that transfer the coal to conveyors which feed directly into the vessels.
More than 95% of the coal from KPC operations is exported, mostly to Japan and Taiwan, but some goes to China, South Korea and Europe. Production occurs in two major areas, Bengalon and Sengatta, which lie within a total concession area of some 91,000 ha. Some of the seams that exist within the company’s agreement area have thicknesses ranging 1–15 m, although most are 2.4–6.5 m. The seam dip is fairly low, in the range 3–20°. The coal is typically low in ash at approximately 5% as received, with sulphur contents of no more than 0.6%. The calorific value (as received) is measured at 22–28 MJ/kg (5350–6700 kcal/kg). The opencast mining operations are all truck and hydraulic shovel capable of shifting 335 bcm/y. Some 1 Mt of material is moved every day, although this may well rise where deposits of the coal dip deeper below the surface level. Coal preparation is primarily based on sizing using crushers to reduce the size to 50 mm for transportation. From Sengatta, the raw coal is moved to KPC’s Tanjung Bara coal port. The coal is transported 13 km to the port’s stockpiles by a single staged, covered overland conveyor (OLC) which has a capacity of 4200 t/h. Bengalon coal is hauled on a raw basis by truck for 27 km to the crushing station located at a dedicated barge loading facility at the Lubuk Tutung Barge Terminal (LTBT). Most of the ROM production requires little extra preparation. Some 1.4 Mt of coal that is ‘dirty’ is processed through a dense medium cyclone plant. The Tanjung Bara Coal Terminal is the key exit point for KPC coal, 96% of which is sold for export. Here the coal is stockpiled before reclaimers load the coal onto conveyors. Coal is also loaded directly from the OLC from the mine. The conveyor then runs offshore along a causeway for 2 km into deep water where vessels of up to 210,000 dwt can berth. 28
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12 PT Indominco Mandiri (Banpu) Key Facts Main mine location: East Kalimantan, Borneo Status: First Generation CoW Production in 2007 (rank): 12 Mt (6th) Approximate production to date (1997-2007): 70 Mt Estimated mineable reserves 62 Mt (limited at 2005 in 2005 (R/P): reserve level) Coal resources, Mt: 284 Mt Indominco is a government run company previously privately-owned by the Sallim Group. In 1998, ownership was transferred to the government to repay debts. A small percentage was transferred to PT Kitadin Corp, PT Trubaindo Coal Mining, and PT Bharinto Ekatama. These four companies were then sold to PT Centralink Wisesa International in March 2001 via the IBRA (bank restructuring agency). Centralink is an Indonesian registered company controlled by Banpu plc (Thailand). Mining is by opencast methods using excavators and trucks. Within the mineyard, the coal is stockpiled and crushed. Coal is transported to port stockpiles by truck. Road haulage is only possible as the distances between mine and port is a mere 56 km, little more than an hour’s drive. Indominco operates a deep water terminal, the Bontang Coal Terminal. The coal terminal is linked to barge and Panamax loaders with a 6 km conveyor link. Indominco started production in 1997 at just 1 Mt and within ten years production reached an estimated 11.7 Mt.
Prospects for coal and clean coal technologies in Indonesia
29
13 PT Gunung Bayan Pratama Coal (Bayan Resources) Key Facts Main mine location: East Kalimantan, Borneo Status: First Generation CoW Production in 2007 (rank): 8 Mt (8th) Approximate production to date (1998-2005): 33 Mt Estimated mineable reserves 450 Mt (limited at 2005 in 2005 (R/P): reserve level) Coal resources, Mt: n/a
excavation and truck machinery, as well as increasing the haulage capacity of opencast operations. However in 2006, Gunung Bayan started a trial of underground mining to determine ground support needs. It appears that high stripping ratios are rendering opencast mining less economically attractive due to the massive volumes of overburden removal required for every tonne of coal extracted (typically ROM). Long-term plans will therefore include the commercial exploitation of what are considered underground seams.
Gunung Bayan is the chief coal mine operation of Bayan Resources and is expected to produce 4.5 Mt in 2008, up from 4.1 Mt in 2007. Bayan Resources includes four other mines each producing 0.5 Mt/y, although the potential for each mine is closer to 2.5 Mt. The company buys an additional 0.5 Mt – primarily Kideco material – for blending. The most recent mines at Bahama and Tegu Sinar Acadia became operational in December 2007. Bahama, which mines a 28.5 MJ/kg (6800 kcal/kg GAD) and 0.5% sulphur material, is targeted to hit 2.5 Mt in 2008. Teguh Sinar Abadi is expected to produce 0.5 Mt of product with a heating value of 26–27 MJ/kg gross air dried. The original target was close to 1.4 Mt, but the mine started up later than planned. Bayan is currently owned by Indonesian based companies; however, divestment to foreign ownership is under way. The Bayan group has been involved in seeking bids for an 80% stake in the company; an Indian conglomerate (possibly Tata) has shown interest with a US$1.8 bn (Castano, 2008). However, other reports suggest that Bayan intends to float only 10–25% of the company out of a total estimated value of US$3 bn (Aglionby, 2008; MCIS, 2008d). Total production by Bayan Resources reached 8 Mt/y in 2007. Production may well increase to 10.5 Mt in 2008 (MCIS, 2008b). Block I consists of 14 seams in a concession area of 8856 ha. The coal quality is good, with high heating values in excess of 7000 kcal/kg. In Block II, there are also 14 seams with similar quality coal. The stripping ratio in both blocks is quite high at roughly 12:1 (12 bcm of overburden to 1 t of coal). All the coal is extracted using opencast means. The company uses its own personnel and equipment. Almost all the coal is mined clean in a ROM state and little requires washing (just 5% of output is washed). Coal is then hauled from the mine to one of two barge loading facilities – Manau, some 20–25 km away or Tepian Ulak, 37–42 km away. Ahead of the planned IPO, Bayan Resources upgraded its reserve estimate to 450 Mt from the current 350 Mt. New reserves are derived in part by moving to very high stripping ratios of up to 18:1 at the flagship Gunung Bayan mine. Those ratios are believed to be economically viable given the current high market prices. Production has increased in recent years by deploying extra 30
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14 General corporate issues One of the major developments in recent years has been the corporate changes occurring among major coal producers or the parent companies. There is no end to the interest in new mining concessions as evidenced by the spate of initial public offerings (IPO) of some of the majors, with others expressing interest to follow. However, the banking and financial markets downturn since 2008 could impair future interest in IPO until economic confidence returns to the financial markets. Nevertheless, in recent years there has been a flurry of activity and interest in the private sector involving share ownership of coal companies. Indonesian coal assets are traded widely across the private sector, which indicates that private industry both within and outside the country has confidence in the regulatory regime of the mining sector in Indonesia over the short-to-medium term. A question being asked by some in government is whether a high proportion of private sector foreign ownership in the coal industry operates with Indonesia’s long-term interests in mind, or whether it will deplete the reserves at a pace that is not sustainable over the long term. The Mineral and Coal Act combines with the Investment Law to formalise the investment climate, and provide support for the coal industry to increase production to 300 Mt within five years (Coaltrans, 2008). The key question is whether retaining sovereignty over the exploitation of coal reserves will be beneficial to the energy security of Indonesia. The government has an extremely sensitive dilemma. While the industry has some degree of protection through the limits on foreign ownership, increasingly the foreign ownership is by countries with an increasing appetite for internationally traded coals, especially the high quality products sourced from the low sulphur and low ash deposits in Kalimantan.
Prospects for coal and clean coal technologies in Indonesia
31
15 A brief history of Indonesian coal production One of the first major projects to get under way in Indonesia was also an extremely steep learning curve for the industry although less successful in commercial terms. In the early 1980s, the World Bank supported the Indonesian Government in a move to diversify the country’s energy sources. A loan of $185 million in 1982 supported the development of the Air Laya mine at Bukit Asam in South Sumatra. The lignite coal mined at Air Laya was destined to supply the Suralaya power station with a ‘captive’ takeoff agreement of 3 Mt/y by 1987 to be fired in the first two 400 MWe units. According to the World Bank (2001) report from which these figures were derived, observations suggested that the project lacked a firm and coherent management structure for the coordination of production, infrastructure and shipping, which were at the time governed by different ministries. One of the major mistakes proved to be the selection of a bucket wheel excavator (BWE) as the method of mining, which subsequently proved to be the wrong technology for PTBA. The BWE is inflexible in operation and requires a high degree of planning which in turn requires technical staff with advanced training. A large inventory of 14,000 different components and the remoteness of the mine made parts and equipment difficult to obtain. The rainy climate made BWE risky to use, leading to a shortfall in excavation rates. Costs were inflated while the downside risk of a low coal price was not properly considered. The geology and feasibility of production methods were not fully evaluated and environmental water pollution was not properly addressed during the construction phase or thereafter. The project was delayed by four years, the mine produced 20% below the 3 Mt/y expected and the financial return was negative. Overall, the World Bank and the Indonesian Government learned valuable lessons. Since the Air Laya project, subsequent mine projects have almost universally adopted the truck and shovel method of extraction. Even PTBA truck and shovel operations were operating at 29% of the cost of Air Laya and proved to be highly profitable. However, it is important to note that with a greater emphasis on high moisture coal reserves for future projects, BWE should not be excluded from consideration if the geology of the seams and its cost-effectiveness mean it is appropriate to use.
15.1 The history of the Contracts of Work Around 1984, First Generation CoW were awarded by Presidential Decree, followed ten years later by the Second Generation CoW contracts. Soon after came the Third Generation CoW, awarded in 1997. The First Generation contracts had the right to mine the bulk of the country’s reserves and still represent the leading producers and exporters. Second Generation contracts represented just 2 Gt of the country’s reserves, while Third Generation contracts applied to concessions in areas that contained a potential 32
13.5 Gt. While the royalty rates were the same for all contracts, the investors received different taxation treatment. By 1999, Indonesia’s Ministry of Mines and Energy realised the potential for Indonesia’s coal mining industry and provided new incentives to encourage the development of low quality coal in the more remote areas of Indonesia. The incentives included the introduction of lower royalties for coal mining activities during a period of slumped coal prices in 1999 (AJM, 1999). The price of some high quality coals were 25 $/t free-on-board (FOB) on which royalties of 13.5% were paid. Lower quality products were being sold for 10–20 $/t. Holders of First Generation contracts operated mines that became the core business of the Indonesian coal industry, serving mainly the international market. While the export market grew stronger, developments occurred in January 2004 in the background, when Indonesia adopted a new National Coal Policy, which sought to promote the development of the country’s coal resources to meet domestic requirements, since oil and gas reserves were declining. The policy included Indonesia’s Coal Development Programme which is summarised as follows: ● greater utilisation of low rank coal; ● development of minemouth coal-fired power plants; ● coal liquefaction and coal gasification to produce substitute fuels for diesel; ● upgrading of brown coal (lignite); ● conversion of 7753 MWe of diesel-fired power plants to coal-fired plants; ● construction of 10,000 MWe capacity of new coal-fired plants in 2009-10; ● better use of coal briquettes for small industry and household applications; ● development of an Integrated Coal Transportation System to link coal mines and export terminals, which are located in the southern part of Sumatra, and in Kalimantan. The updated scheme has added more sophistication to the domestic coal contracts. It stipulates that contracts with local end-users can be renegotiated on a more regular basis depending on the prevailing price of internationally traded coal. It also accounts for the quality of coal and the remoteness of the mine location. While the government revenue from royalties could drop initially, it was anticipated that revenues would pick up as low rank coal production increased in more remote regions. By 2005, Indonesia had overtaken Australia as the leading exporter of steam coal. The Indonesian coal industry registered an average annual growth of 10%/y from 2000. This outstripped the average growth rate of both international seaborne coal and domestic demand. Practically, all the production in Indonesia was driven by export demand from power stations and industries in other major Asian economies (see Table 4). Throughout the period since 2000, Indonesia seemed to break IEA CLEAN COAL CENTRE
A brief history of Indonesian coal production Table 4
Largest coal producing organisations in Indonesia 2007 (MCIS, various issues)
Producing group
Mt
BUMI, of which is:
54.2 PT Kaltim Prima
38.9
PT Arutmin
15.3
PT Adaro
36.1
PT Kideco Jaya Agung
20.5
Banpu, of which is:
17.7 PT Indominco Mandiri
11.5
PT Berau
12.1
PT Tambang Batubara Bukit Asam (PTBA)
11.0
PT Bayan Resources
8.0
PT Anugerah Bara Kaltim
4.0
PT Jorong Barutama Greston*
3.0
Total *
166.5
refers to 2005
its export record every year due to strengthening prices and higher demand. The rupiah exchange rates with the US$ had settled somewhat, and exports were boosted when China withheld its own export tonnage from the world market (due to strong internal demand). Furthermore, a strengthening in the Australian currency reduced Australian export competitiveness. In 2005-06, infrastructure problems in Australia created supply bottlenecks to the export loading ports preventing Australian producers from exploiting the extra demand in the Asian market. These reductions in exports from Australia and China thus created a supply gap in the AsiaPacific market, which Indonesian exporters were quick to fill. Interestingly, a considerable amount of coal in Indonesia had been reported to be mined illegally and exported to take advantage of the high prices arising between 2005 and 2008. According to government reports, 20 Mt of coal was produced and exported illegally every year during this period, and could continue if the price of coal remains attractive. Most of the illegally mined coal came from operations adjacent to existing legal operations. Some unauthorised operations were allegedly issued illegitimate permits by local governments that did not gain the necessary authorisation from the central authorities. The 20 Mt business accounted for a massive 10% of production, losing the government the equivalent of $270 million in revenue from taxes and royalties, had prices remained around 100 $/t FOB (Coal Age, 2008).
15.2 The impact of forestry protection The international coal trade press writes little about Prospects for coal and clean coal technologies in Indonesia
environmental protection and its impact on coal production in Indonesia. Most reported events include force majeure or transportation bottlenecks that affect short-term supply. However, what is often overlooked in coal reports is the importance of Indonesia’s environment, most notably that of Kalimantan (Indonesian Borneo), and the same may well apply to Sumatra. This may be due to the fact that the coal industry faces few impediments regarding environmental regulation, yet Borneo is home to an extremely diverse ecosystem that is rich in tropical flora and fauna. However, the Engineering and Mining Journal (E&MJ, 2008a) published an article covering this issue, describing how much of the important forest grows above mineral deposits. The impact of mineral mining, in this case coal, is not surprisingly opposed by some government officials, environmental non-government organisations (NGOs), and local communities. Although it is commonplace for coal producers to work with parties to resolve environmental issues, environmental law will continue to place pressure on developers of opencast mines, and coal producers will need to adapt to any changes and ever stricter working conditions over the long term. Back in 1999, a year after former President Suharto left office, a major law was passed, the Forestry Law 41. Under this law, certain categories of forest were designated for protection. Certain economic activities could be undertaken depending on the forest category to help ensure that the forests were not irrevocably damaged or changed. So, while mining companies could gain necessary permits from the Ministry of Mines and Energy Resources to mine concessions, any concession that contains forest also required a ‘borrow to use’ permit from the Department of Forestry. Law 41 is somewhat confusing, and in some cases seems irrelevant. Article 38 of Law 41 prohibits opencast mining in areas designated as protected forests. This poses a particular hindrance since coal seams generally lie in shallower formations in Indonesia, and underground mining is almost impossible in areas where the terrain is soft. However under Article 19, coal producers also have the opportunity to change the status of a forest, making opencast mining possible. So while well-intended, Law 41 could be adapted to suit the mining industry under certain circumstances, although not always. Law 41 became effective enough to discourage a number of mine developments. Out of 22 companies that have applied for mining licences since the adoption of Law 41, thirteen successful licences were granted concessions in areas with protected forests (E&MJ, 2008a). Some companies were still awaiting verdicts from the Department of Forestry by 2008, and this uncertainty reduced the number of companies applying for mining permits. In 2004 the government responded. In a decree, President Megawati Sukarnoputri declared that mining contracts signed for areas that were designated as protected will be allowed to proceed, despite Law 41 (Lezard, 2004). This initiative was a bid to restore confidence in the mining sectors that were previously discouraged by Law 41. The Ministry of Forestry came under criticism, particularly 33
A brief history of Indonesian coal production from the mining lobby which claimed that the tree logging industry has become exempt from paying the same indemnity as mining companies for using natural forest for commercial purposes. According to a survey by PriceWaterhouseCoopers, conflict between mining and forestry interests ranked as some of the most serious obstacles facing mining investment in Indonesia, so clearly there were continuing efforts by the Department of Forestry and interest groups to put pressure on mine developers (Forbes, 2007). Interestingly, the law appears to have been diluted by a presidential decree issued on 4 February 2008. It states that mining firms will pay into a compensation fund during the contract period, and the funds would be used to replant forests. Firms were able to pay between Rp 1.8–2.4 million ($200–265) per hectare for forest land. As well as opencast mining, other activities that would be subject to the decree include oil and gas companies, power transmission, hydroelectric projects, geothermal power, toll road operators, housing, and waste dumps (Azhari and others, 2008). Previously, mining firms had to provide new land to compensate for the use of forest areas, at twice the scale of the mining area. Unsurprisingly the decree faced criticism from opposition groups, but cautious support from the mining sector.
15.3 Changes to the regulatory regime Indonesia’s mining regulations have undergone a long awaited revision, but received a muted response from the main coal producers. In late 2008, the government announced a series of changes to the concession permit scheme which decentralised the decision-making process away from central government and towards the local and provincial authorities. It also changed the terms of CoWs. Some of the key changes involving the shift of authority have led to some legal uncertainty due to overlapping authority between local and regional governments. As a result, according to a brief analysis by the Oxford Business Group (OBG, 2009), the past decade saw only one new CoW issued to an international mining company, while some international investors, such as Australian firm BHP Billiton, have chosen to abandon their large-scale commitments altogether. Some critical changes to concession are the upper limits for areas of exploration. For existing First Generation concessions, these were set at 100,000 ha per operation, but under the new law, coal operations may only have access to 50,000 ha of land per operation for coal mining (and 100,000 ha for metal mining). This new limit should promote more diversity in the number of operations, but could encourage more illegal mining and less control over enforcing environmental rehabilitation, although these criticisms are speculation in these early days of the new law. Another fundamental change is the limit to the amount of time allowed for extraction which has been revised down to 20 years, with two possible 10-year extensions. The previous law permitted CoW to be valid for 30 years with one possible 34
20-year extension. Even within this period, revisions could have been enforced if the terms and conditions of the concession were broken. According to OBG (2009), analysts believe that big investors need economies of scale and time to ensure a guarantee on their investments, and that the new terms may be insufficient. While the government has stated that the restriction on land usage is aimed at encouraging the growth of smaller local investors, many warn that the new rules will deter larger foreign investments critical to the industry’s expansion. These new laws are seen to be applicable to CoW, but not to smaller KP contracts. While there is some resolution on the way mining laws have changed, initial discussions during the drafting stage earlier in 2008 suggested the direction the government could take in the future. These include discussions between government officials and coal producers about reserving 30–35% of lower heating value coal for the domestic market, with smaller measures applying to producers of higher heating value coal. An early draft of the new regulations also suggested that the domestic market obligation (DMO), could be set on an annual basis (MCIS, 2008). This has major implications as it sets out a firm commitment for the government on energy security and preserving solid growth in the domestic coal market, particularly for the oft mentioned power generation. Further to these discussions, there is also a sentiment that the industry may well consolidate and a raft of new suppliers could replace the current industry structure. Castano (2008) reported on the increasing support for greater state control and could see the CoW being replaced, but this remains a vision rather than a reality at the moment. Nevertheless, Castano (2008) detailed ideas that included some form of staged expansion of current CoW reserves, which would require a CoW licence renewal on a more regular basis. Even as the CoWs remain in place, there have been calls by government members to raise taxes and royalties from the coal companies, and to formalise an agreed price formulation upon which tax revenues are calculated. Currently, the government would prefer to avoid changing the structure of the industry fundamentally at a time when the coal industry as it stands could expand operations and infrastructure on their own. Shortening the CoWs from 30 to 20 years could mean the expiry of CoWs within the next 5–10 years. Within the detail of any agreement, the regulatory environment must consider whether more or less state control serves the national interest. For example, China is positively encouraging Indonesian exports by signing longer-term agreements with producers. Under this type of market condition, Indonesia is under pressure to produce more, while facing a reduction in the reserves of internationally-traded coals. Meeting the needs of overseas supply contracts almost forces the government to resort to lower rank and less economically transportable coals in Sumatra to meet domestic needs. Whether this is good for security of supply is not certain. The government is working to introduce a DMO to allocate a IEA CLEAN COAL CENTRE
A brief history of Indonesian coal production certain amount of production for domestic energy needs. Jakarta is planning to bring 35 new coal-fired power plants on stream by the end of 2009 to help supply the growing demand from industrial sectors. However, tying Indonesia to local coals reduces fuel diversity. It may also subject Indonesia to potential risks of power shortage in the possible event of force majeure or industrial action; importing low rank coals to compensate is less feasible due to the high costs of transporting a low calorific value fuel.
Prospects for coal and clean coal technologies in Indonesia
35
16 Coal production – costs and methods Indonesian coal is some of the cheapest to produce in the world, and while this statement embodies coals mined mainly for export, it could also apply to future low rank coal operations. Early research by Neil (2005) suggests that the cost of producing coal in Indonesia can range from 17 $/t to more than 30 $/t. Baruya (2007) estimated that in 2005, the average FOB cash cost of Indonesian thermal coal was around 26 $/t (28 $/t on a 6000 kcal/kg or 25 MJ/kg basis). Of this, 20 $/t was the cost ex-mine, 4 $/t was inland transport, and 2 $/t was port costs. The cost of supplying steam coal to the world market is reviewed in a report by Baruya (2007) which draws on work published by Devon (2005) and Neil (2005).
production costs can remain less than straightforward due to the wide range of coal qualities. The higher rank coals may be more expensive to mine (on a heating value basis), but the cost of all mining operations have risen in the years between 2005 and 2008. One example is how the cost of materials and fuel have driven up costs of production for BUMI’s operations in Indonesia. In their first quarter financial report for 2008 (1Q2008), BUMI experienced a cost averaging 31 $/t, while in the whole financial year of 2007 (FY2007), the cost of mined coal was just 26 $/t. For the industry as a whole, equipment and spare parts, such as truck tyres, were in short supply and the order books were such that lead times were very long. Also, the removal of fuel subsidies meant that the cost of diesel fuel for trucks pushed up operating costs. This was particularly problematic for the Indonesian coal industry which uses trucks extensively throughout its entire coal mining industry. These all indicated an upward shift in the supply cost curve for Indonesian coals.
The cost curve shown provides a good framework from which it is possible to derive a more up-to-date range based on further evidence. Such evidence is provided by Marston (2008) and press reports (see Figure 11) which shows that the cash costs of getting coal loaded onto an ocean-going vessel can range between 20 S/t and 50 $/t (unadjusted for heating values). Assuming 34 $/t is the midpoint of this range (average cash cost in 2007), the cost of supplying coal to the export market rose 33% between 2005 and 2007. A commercially sensitive report suggested that the FOB cash cost of coal in 2008 averaged closer to 46 $/t (unadjusted for heating values), indicating a further increase of 33% on 2007 levels (>77% above 2005).
JP Morgan carried out a share value assessment of Banpu-owned IMT, and speculated that IMT would enjoy higher realised coal prices until 2009/10, but higher prices received would be accompanied by higher costs. Mine contracting, coal transportation and direct fuel usage accounted for nearly 70% of the company’s cash operating costs in FY2007. All of these major cost items are linked to fuel (mainly diesel) costs. JP Morgan concluded that as oil prices rise, so would ITMG’s production costs. In their forecasts, they project cash operating costs to rise from 24 $/t in FY2007 to 30 $/t in FY2008 (+24%) (Chawalitakul, 2008).
The cost range for steam coals can be as low as 20 $/t for low rank coals to 46 $/t, and as high as 118 $/t for metallurgical coals. While most Indonesian coal operations have common characteristics, namely opencast methods of truck and shovel mining, low dipping thick seams, and so forth, coal
Venezuela
Colombia
South Africa
Indonesia
Queensland
New South Wales
0
10
20
30
40
50
60
70
FOB vessel cash cost, US$/t
Figure 11 Cash cost of export steam coal in 2007 (Marston, 2008) 36
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Coal production – costs and methods Looking industry-wide, this trend would have a greater impact on some operations more than others, especially less productive ones, such as those operating under increasingly difficult geological conditions. For example, overburden removal (and transport) for opencast mining becomes one of many important cost components. Some of the largest producers have long enjoyed mining thick seams with relatively shallow dips and low stripping ratios for some years. As mentioned earlier, stripping ratios refer to the volume of overburden (topsoil, earth and overlying rock) that needs to be removed to yield a single tonne of coal (ROM). Stripping ratios are examined in detail by Baruya (2007). In the meantime, according to Neil (2005), stripping ratios can range from 2.5:1 for Adaro to 8.5:1 for Indominco. While these stripping ratios are relatively low, some operations are as high as 14:1. Estimates from company data suggest that productivity is likely to be around 6000–12,000 t/man-year; the upper end of this range is comparable with good performing mines in the Hunter Valley, Australia. Some accuracy may be lost in assessing labour productivity figures due to the data for staff not employed directly by the mine owners. Third parties, namely contractors, carry out mine operations in Indonesia and contract staff numbers may not be recorded accurately by the owner. The use of mining contractors has increased substantially over the years. In 1994, contractors were responsible for 62% of total coal production (Nye, 2005). By 2004, contract firms carried out 83% of production. Recent reports suggest that contract firms now account for 95% of Indonesian coal production (E&MJ, 2008b). Contractors are able to operate in a number of mines, moving expertise from one to another wherever it is appropriate. Many mining assets are written down at the end of the contract tenure, and handed over to the government. Contractors therefore have the flexibility to either continue operating in the same mine, or shift the workforce to another site. This use of contractors simplifies operations for the mine owner since contractors decrease exposure to fixed costs, such as upfront capital expenditure and future depreciation, as well as managing mine staff and production. This means that the mines can be exploited by the owner on a more certain cost basis. Neil (2005) uses two specific examples of company operations that make large use of contractors and consultants. These companies are some of the largest operators in the country and include BUMI (owner of Arutmin and Kaltim Prima) and PTBA. Contractor costs can account for 50–60% of production costs and on average would translate to 10–15 $/t (2005 figures). As well as contractors, mining consultants provide expertise in technical assistance to both contractors and the owner operators. In the case of BUMI, consultants can add a further 14%. In total, using third party firms could account for 10–17 US$/t on average. Personnel costs are becoming greater with a shortage of skilled labour in the mining industry worldwide. As such, the rise in contractor rates will put further pressures on production costs (Nye, 2005). Prospects for coal and clean coal technologies in Indonesia
37
17 Inland transport infrastructure: river barge, road, and rail Due to the number of producers and numerous transport routes in Kalimantan, coal export links between mines and ship loading terminals do not seem as concentrated as they are in exporting countries that rely on one or two large ports such as Richard’s Bay Coal Terminal (South Africa), Qinghuangdao (China), and to a lesser degree the Australian terminals. Somehow, Indonesia has expanded export capabilities using proven and simple methods that would be the envy of many coal exporting countries. This is largely due to the proximity of coal mines to navigable rivers and coastlines that favour Indonesia’s export industry. Figures 12 and 13 chart the locations of the major coal operations along with the main methods of inland transportation and export terminals for Kalimantan and Sumatra. These maps accompany the following discussion as well as Chapters 6 to 13. A great deal of the following section cites two reports both of which are available in the public domain: the Indonesian Coal Industry Book (ICMA, 2006) and the RWE World Market for Hard coal (Ritschel and Schiffer, 2007) as well as a number of other sources. Coal is moved in a variety of ways from mine to port or end-user. Indonesian coal can be moved via a combination of road trucks and river barges, while other operations make use of large conveyor belts (covered and uncovered) for distances of a few km to a lengthy 32 km (see Chapter 6). The completion of Adaro’s conveyor belt between the Wara mine (South Kalimantan) and closer to the Kalanis Barge Terminal will be one of the longer OLC’s operating in the world today. Kaltim Prima uses a conveyor belt to take coal 13 km to its Tanjung Bara coal port in East Kalimantan. At most Indonesian mines, coal is trucked directly to coal processing/barge loading facilities located on tidewater or on a barge-navigable river. Although truck is an expensive means of transporting coal, the distances involved are extremely short, usually 10–25 km. A few mines may need to truck the coal to coastal points as far as 75 km away. Trucks provide increased mobility. Meanwhile, building a new railway infrastructure to cover short distances of just 50–70 km would prove more costly than the methods adopted today. In 2004, 90 Mt of coal was transported by barge to domestic customers, terminals, or anchorage trans-shipment points; a further 40–50 Mt was transported almost exclusively by truck. According to the Indonesian Coal Book (2006), the barge loading, trans-shipment, and port facilities in Indonesia as of 2005 were able to handle 160 Mt of coal per year, although maximum throughput was a feasible 174 Mt/y. In 2005, 129 Mt was reported to have been exported from Indonesia (MCIS, 2008) suggesting that the export facilities were 80% utilised. By 2006, coal exports had reached 183 Mt (MCIS, 2008), so expansion was clearly not a problem. Today, export capacity is well in excess of 300 Mt (see Table 5, page 42). Lower rank coals from both Kalimantan and Sumatra are less suitable for transport due to the high moisture content and a 38
higher tendency to spontaneously combust due to the volatile content. Spontaneous combustion could be inhibited by inert gas blanketing and suitable compaction techniques, but generally the transportation of low rank coals is minimised. Reducing the moisture content by rewatering for example could prevent higher transport costs per unit of energy. Various techniques for upgrading low rank coals in Indonesia are discussed in more detail in Chapter 22. Most Sumatran coals are less amenable to being transported long distances than Kalimantan coals due to the higher unit costs of transportation. Nevertheless, in Sumatra some coals are moved by rail. For example, coal produced by PTBA has a long rail route to the Kartapati port near Pelambang and also Tarahan Port by Tanjungkarang. Plans to upgrade the rail system in Sumatra is at the tendering stage and the planned $1 billion investment could boost the amount of coal sent by rail from 12 Mt to 50 Mt (CANZ, 2009). Transport costs are recognised as being a major factor in the future development of coal within Indonesia. In general, the weighted distance to ports will tend to increase as reserves near the coast are mined out.
17.1 Barging Barging has proved to be key to providing effective coal movements in Indonesia. Barges are an extremely cost-effective method of getting the coal from the mine to the coast, either to a port or to offshore ship loaders. The average unit cost of barging ranges from 0.5 to 3.0 $/t (Neil, 2005). This makes barging considerably cheaper than practically any other alternative. In South Kalimantan, operations operated by Adaro Indonesia transport coal via barge on the Barito River from the Kalanis Barge Terminal to be loaded using trans-shippers to bulk carriers at the Taboneo anchorage point. This river is essential to Adaro’s plans to expand coal production in this region, and is discussed later in the chapter. Coal operations in East Kalimantan use the Mahakam River to barge coal to ports such as Balikpapaan. Barges are used extensively for trans-shipping coal from rivers to coastal loading points for exports, as well as for domestic trade from Kalimantan and Sumatra to power stations located in Java. Self-propelled barge transport across the Jawa (Java) Sea is common practice, and deliveries are made by barge to some export destinations within south east Asia, such as neighbouring trade partners Malaysia and Thailand. Barges with capacities of between 3500–14,000 dwt move coal from the shore to offshore loaders or nearby ports capable of loading Capesize (80–180,000 dwt) vessels. Economies of scale have meant that barge capacity can IEA CLEAN COAL CENTRE
Inland transport infrastructure: river barge, road, and rail
port coal terminal (operating company) maximum deadweight
Tarakan Island (Mandisi Inti Perkasa) 7500 dwt
anchorage point for offshore loading (operating company) max deadweight capacity river terminal
Berau
Muara Pantai (Berau Coal) 15,000 dwt
coastal terminal company name
location of main concession inland transportation link
Kaltim Prima
Tanjung Bara (KPC) 210,000 dwt * overland transport via conveyor
East Kalimantan
Bontang/Tajung Meranggas (Indominco) 90,000 dwt Muara Berau (Berau Coal) 8000 dwt
Indominco
Bayan Belora and Lao Tebu river terminals (each 8000 dwt)
Samarinda
Central Kalimantan Balikpapan 65,000 dwt
Kideco
Tanah Merah (Kideco) 60,000 dwt Apar Bay 6000 dwt
Adaro
Makassar Strait
Kelanis river terminal (Adarol) 10,000 dwt
Arutmin Sembilang and Air Tawar river terminals, each 7500 dwt South Kalimantan Tanjung Permancingan 8000 dwt Satui river terminal 5000 dwt Taboneo (Adaro) 15,000 dwt Arutmin
N. Pulau Laut (Arutmin and common user) 150,000 dwt Sebuku (Bahari Chakruwala/Straits) 6000 dwt Tanjung Pantang 8,000 dwt
Jorong Jorong (Banpu) 7000 dwt S. Pulau Laut (common user) 200,000 dwt Muara Satui (Arutmin and common user) 7500 dwt
Figure 12 Coal export map of Kalimantan currently reach 14,000 dwt, more than double the capacity of similar barges used in the 1980s. Even in today’s market, these massive barges can compete on short haul voyages to domestic and nearby regional export markets, while smaller 10,000 dwt barges are useful for trans-shipment operations. Indonesia currently has the largest infrastructure of barge and Prospects for coal and clean coal technologies in Indonesia
offshore trans-shipment for dry bulk in the world. A continuing drive for productivity and cost reduction is being pursued in the Indonesian barge industry, where the massive volumes compensate for the high costs of trucking from many Indonesian export producers (Pitch, 2005). 39
Inland transport infrastructure: river barge, road, and rail Rantaubarangin port coal terminal (operating company) maximum deadweight Riau anchorage point for offshore loading (operating company) max deadweight capacity Allied Indo and PTBA
river terminal coastal terminal
Solok company name
Teluk Bayur 35,000 dwt
location of main concession inland transportation link
West Sumatra Jambi Sungaipenuh
Kertipati (PTBA) 7,000 dwt Bengkhulu
South Sumatra
Palembang
Lahat Pulau Baai 40,000 dwt
PTBA
Lampung
Bandar Lampung
Tarahan (PTBA) 40,000 dwt
Figure 13 Coal export map of South Sumatra Productivity gains could be increased by a significant margin following the dredging work carried out at the Barito river. This could lift the river’s capacity from 40–60 Mt/y to a massive 200 Mt/y, and is being exploited by Adaro, one of the main producers of the region. Previously some 15 km of the river was capable of only single-lane barge traffic of 13,000 dwt barges. In addition, when fully laden these barges were only capable of sailing at high tide. Dredging works have since permitted two-lane traffic in this difficult stretch of river, and operation through low tide periods means access is possible 24 hours a day (as opposed to just 12 hours). Users transporting coal through the channel are charged 0.3 $/t (MCIS, 2008).
17.2 Road and rail Road haulage is used widely, for either transporting coal to river barge terminals, or in the case of many operations in East Kalimantan, trucks are used to take coal directly from the mine to coastal terminals. Vehicles range in capacity from 10 t dump trucks using local roads to 160 t road trains. Trucking between the mine to coastal onshore terminals is higher than that for barges, averaging around 4–7 $/t, but over a relatively short distance it remains an extremely cost-effective method of moving coal to export terminals. The combination of barges and trucks has proved a highly
40
IEA CLEAN COAL CENTRE
Inland transport infrastructure: river barge, road, and rail economic and flexible system of transportation when compared to the rail solutions often used in other major exporting countries. This has not precluded rail from being developed in Indonesia. Moving coal by rail is more common in Sumatra, particularly in the South Sumatra and Lampung provinces. However, rail transportation suffered from poor reliability in the past and requires considerably more investment. Currently, PTBA transports coal via a 400 km rail link connecting its mine to the Tarahan port on the Sunda Strait, and smaller tonnages go through Kertapati. Other rail projects are being mooted for development in South Sumatra and Kalimantan. PTBA is to embark on a double track railway to double the rail capacity. PTBA is also considering the construction of a canal from its mine to the Bangka Channel. If these infrastructure developments are successfully realised, PTBA production could quadruple, but the 2010 deadline is considered optimistic. Completion is likely to be considerably later.
17.3 Offshore loaders and trans-shipment The limits to the vessel size at Indonesian ports have given rise to the use of offshore terminals, as discussed earlier, enabling Panamax (approximately 65–80,000 deadweight or dwt) and Capesize (approximately 80–175,000 dwt) vessels to be loaded easily. Consequently, export coals are loaded into barges at either river or coastal located loading facilities and transported to offshore transfer points for loading onto ocean-going vessels or barged to a deep water coal terminal. Indonesia has an unusually large capacity of shiploading terminals that are situated off the country’s coast in the form of offshore loaders. The two main designs of offshore loaders used in Indonesia are trans-shippers, which either utilise continuous bucket chains for transfer from the barge, or the continuous conveyor system and ship loading boom. The latest trans-shippers also combine storage facilities that improve the availability of spot shipments from Indonesia. For example, Adaro operates the Banjarmasin floating crane with a 15–20,000 t/d capacity and can accommodate vessels weighing more than 200,000 dwt. A typical Capesize vessel of 100–150,000 dwt could therefore take around 5–10 days to load fully. Kideco and KPC also operate floating cranes while Berau operates a semi submersible trans-shipment (SST) system. Offshore loading cranes are a fraction of the capital cost of fixed onshore port facilities, partly because they avoid the need for land for siting. These so-called floating trans-shippers cost around $10 million for a crane capable of throughputting 3.3 Mt/y of coal. A large 30 Mt/y onshore terminal, however, would cost $1000 million, and so recovering the fixed costs of capital would be inflated by an order of ten times that of a floating crane. On an economic basis, floating trans-shippers have their benefits, even though the throughput capacity of the trans-shipper is considerably lower than that of a fixed land system.
17.4 Port facilities Table 5 lists the major ports and export terminals that exist in Prospects for coal and clean coal technologies in Indonesia
Indonesia and is derived from MEMR data published by the IEA (2008) in the Energy Policy Review of Indonesia and industry sources. According to these sources Indonesia’s port capacity is 309 Mt/y. Not surprisingly, the bulk of the capacity is located in East and South Kalimantan, the respective capacities being 140–150 Mt/y and 120–130 Mt/y. A further 50 Mt/y is located in Sumatra. These capacities refer to maximum port capacities, and so actual capacities are probably less than these figures, but nevertheless indicate the potential for expansion in the future. Port costs are fairly standard by world standards, in the range 1–3 US$/t (Baruya, 2007). There are a number of companies which have either exclusive or overall control over a number of ports. Companies with dedicated port facilities include: Adaro Indonesia, Indominco, Kideco, Arutmin, Bukit Asam (PTBA), Berau Coal, and Kaltim Prima to name just the main producers (see Table 5). A few facilities are not strictly coastal ports, but are located on rivers. One such example is the Kerpati Jetty, which is a river terminal used by PTBA in Sumatra. The combined North and South Pulau Laut Coal Terminals have a maximum capacity of 126 Mt/y. The South Terminal is owned by PT Indonesian Bulk Terminal and is the largest in South Kalimantan (72 Mt/y). The Pulau Laut Coal Terminal is a common-user located on the South Western tip of the island of Pulau Laut opposite the south eastern coast of South Kalimantan Province in Indonesia. Kaltim Prima has the largest capacity in East Kalimantan, the Tanjung Bara Coal Terminal, with a maximum capacity of 77 Mt/y. Where the onshore coal terminal might have restrictions on vessel size, the ports operate in conjunction with offshore floating terminals that can accommodate larger ships. Balikpapan Coal Terminal is located in a sheltered area of Balikpapan Bay. The port readily accepts Panamax and Capesize vessels, the latter being loaded at the Kalimantan Floating Terminal (KFT) which is capable of manoeuvring to locations that suit demand and weather conditions. This particular facility has four unloading cranes and 65,000 t stockpiling capacity where blending can take place. In combination with the country’s offshore loaders, there does not appear to be any shortage in export terminal capacity, given that the maximum potential capacity is 350–360 Mt/y (port and anchorage capacity). Total export for 2007 and 2008 was about 200 Mt. Add to this the potential 30 Mt/y or so passing through coal discharge ports of Cigading (Indocement), Paiton PEC, Paiton PLC, Paiton Jawa Power, and Suralaya, the total amount of coal that could be passing through Indonesian export ports is at least 230 Mt. With a maximum capacity of 365 Mt, Indonesian ports in 2007 might only have run at a utilisation of 65%. Indonesia therefore has plenty of scope for expansion in the near term.
17.5 Common disruptions in coal supply Coal exporters are faced by the usual constraints set by the physical capacity of production, and transportation. There are 41
Inland transport infrastructure: river barge, road, and rail Table 5
Estimated export capacity in 2007/08 (Author’s estimates based on ICMA, 2007)
Port (P) terminal or anchorage (A) point
Main User
Estimated maximum capacity, Mt/y*
East Kalimantan Balikpapaan Coal Terminal
(P)
Common user
23
Bontang Coal Terminal
(P)
Indominco
21
Tanah Merah Coal Terminal
(P)
Kideco
22
Tanjung Bara Coal Terminal
(P)
Kaltim Prima Coal
76
Teluk Apar
(A)
Muara Berau/Muara Jawa
(A)
Various
3
Muara Pantai
(A)
Berau Coal
5
Tarakan
(A)
Mandiri Inti Perkasa
3
2
Subtotal for East Kalimantan
155
South Kalimantan North Pulau Laut Coal Terminal
(P)
Arutmin
54
South Pulau Laut Coal Terminal
(P)
Common user
72
Jorong
(A)
Joromg Barutama
3
Sebuku
(A)
Bahari Cakrawala
2
Muara Satui
(A)
Arutmin, various
3
Taboneo
(A)
Adaro, various
5
Tanjung Petang
(A)
Arutmin, various
3
Satui
(A)
2
Sembilang
(A)
3
Tanjung Permancingan
(A)
3
Subtotal for South Kalimantan
149
Sumatra Kertapati Jetty (river)
(A)
Bukit Asam
3
Muarasabak
(A)
Various
2
Sungaipakning
(A)
Riau Coal, Manunggal Inti Arta
4
Pulau Baai Port
(P)
Various
14
Tarahan Coal Terminal
(A)
Bukit Asam
14
Teluk Bayur Port
(P)
Bukit Asam, Karbindo
13
Subtotal for Sumatra
50
Total port capacity
309
Total anchorage capacity Trans-shipment fleet
44 Estimated Mt/y*
Adaro floating crane
7
Berau semi-submersible trans-shipment
7
Kideco floating crane
7
KPC Floating transfer station
7
Common user floating crane
5
*
annual tonnage based on maximum daily capacity times 360 days – actual tonnage will be below this
also occasional episodes of non capacity related bottlenecks that affect the smooth operation of supplying coal to international and domestic markets. The Indonesian coal industry is not renowned for regular 42
industrial disputes, although they still occur. Weather related incidents are more regular and frequently create what is termed force majeure. This is an unplanned event that can prevent the smooth operation of the coal supply chain or often halt the supply of coal altogether. Indonesia’s climate is IEA CLEAN COAL CENTRE
Inland transport infrastructure: river barge, road, and rail predominantly tropical. Some variations in the climate occur depending on the latitude but Kalimantan and Sumatra are both bisected by the equator. Hilly areas are cooler, but rain falls throughout the year, often as thunderstorms. There is a relatively dry season in July to September; December to March are typically the wettest periods. However even outside these months, rainfall is capable of causing problems, forcing coal suppliers to rely on stocks at the export terminals to ensure that supply contracts are honoured. Many of the access routes between the mine or preparation plant and the river barge terminal are by road. However, the country’s regular wet seasons cause disruption to these road links as well as the mine operations. In 2008, at least six major producers were affected by heavy rains, causing problems to mining operations, road haulage, and vessel queuing. In most cases, rainfall causes flooding at the production facilities and on roads, while tugs and barges can also be subject to damage. The companies worst hit were Adaro, Gunung Bayan, Kideco, Indominco, and ABK. Similarly, when river levels are low, barge access can halt, again putting stockpiles to the test for effective buffer supplies. These problems are not unsurmountable given that most producers operate coal stocks, thus ensuring delivery schedules can be met. However, beyond the stockpiles, the impact of adverse weather on the barge and port facilities just prior to shiploading means vessel loading is delayed, and demurrage charges are applicable. At times of high freight costs, the daily charter rate for a vessel caught in an unplanned queue can be high.
Prospects for coal and clean coal technologies in Indonesia
43
18 Electricity generation This chapter describes the various issues regarding the Indonesian electricity market and the development of generating capacity. There is also discussion on the characteristics of the various forms of generating stations in which coal plays an increasingly important role.
18.1 A brief history of the industry The electricity supply industry is dominated by the state company PT Perusaahan Listrik Negara, (PLN). PLN has 36 million customers and 113 TWh of sales. Some 29 TWh is purchased from independent power producers (IPP) and other non-PLN generating companies, while 102 TWh is produced by PLN itself. The history of PLN dates back to 1965, when two state energy companies were established. The first was PLN the power company, and the second was PT Perusahaan Gas Negara (PGN), a gas processing company. Therefore, 1965 was probably the first time the electricity industry was formed in its current semblance. At that time PLN only had 300 MW of electrical power generating capacity. After some changes in the company status, the market remained largely unchanged until the 1990s when the government granted an opportunity for the private sector to take part in the business of providing electricity to help alleviate the worsening shortage of generating capacity in the market and reduce dependence on oil-fired power. At this time, the Indonesian Government introduced an IPP programme inviting private domestic and foreign corporations to build, own and operate (BOO) generating plants. The IPP schemes were to be largely fuelled by coal or natural gas, although small geothermal projects would also be adopted (Turner, 1997). As of 1997, the programme included twelve plants amounting to 7500 MWe of coal-fired generation. A further 2000 MW of this programme was natural gas fired. Major incentives for an IPP to invest included generous offtake contracts that ensured a good rate of return for the station owner (more importantly, in US$). These contracts also had an element of long-term security for much of the life of the station. This latter incentive refers to purchase agreements agreed with PLN to allow IPP stations to operate for up to 80% capacity a maximum 30 years. PLN even switched off some of its own capacity to meet the guarantee. This relieved PLN of the burden of capital investment and the risks associated with building new and more efficient power stations. By June 1998, thirteen IPP projects had signed PPAs for periods of 20–30 years. The firms involved includes companies such as Mission Energy (USA), Powergen (UK), Siemens (Germany), Ansaldo Energia (Italy), Mitsubishi (Japan), National Power (UK), and former Enron (USA). Since Suharto’s departure, all the concessions for electricity deals and even the UK’s Thames Water contracts in East 44
Jakarta were placed under scrutiny by the succeeding government. In 1998, Power in Asia reported on some of the non-conventional business practices being carried out in the new Indonesian power market. The drive to promote foreign investment in Indonesian power gave the former Suharto Government departments the opportunity to promote allegedly irregular financial transactions in order for foreign projects to proceed (PiA, 1998). In the 1990s, virtually every joint venture by an IPP was partnered with a Suharto family member or Suharto appointee. PLN was almost driven to bankruptcy by deals with IPPs that were owned by the Suharto family members. IPPs, once heralded as the prime customers and key growth market for coal, were giving way to possible restructuring of the power business, postponement or even cancellation altogether. The risks of signing long-term PPAs proved to be high as the Asian currency crisis ensued. The 30-year tariff deal was for the equivalent of 7.5 ¢/kWh, but the depreciation of the rupiah forced PLN to push for a renegotiation. PLN unilaterally terminated a PPA to one geothermal project and formed a committee to review all others. Other projects included the Tanjung Jati B on the north coast of Java where construction was halted ($1.8 bn, 1329 MWe coal plant). The Paiton 1 and 2 projects in East Java experienced start-up delays due to the lack of power demand on the Bali-Java grid at the time. The Asian currency crisis became a subsequent reason for the IPP Paiton Energy Company to consider renegotiating the contractual terms of its PPA with PLN. The effect of the Asian economic crisis reduced demand for goods and services across the region. Daily reports of rioting, food shortages and unemployment weakened the economic outlook (Marston, 1998). IMF and World Bank funding exceeding $1.2 bn intended to help boost and stabilise the economy was postponed at a time when the economy was suffering the most, just after the Asian currency crisis. Somehow, throughout all the upheaval occurring in the domestic market for power generation, the coal export industry continued to expand and further its presence in the world market for steam coal. The low cost of Indonesian coals, and the continual productivity improvements meant that Indonesian exporters were better positioned than most to survive the period of great uncertainty in the 1990s, even when the price of coal was low. Confidence was eventually restored following a global economic upturn and successive rulers pledged to deal with corruption and reform of the markets. In 2004, the courts overruled plans to divest PLN and liberalise the electricity market, claiming it was unconstitutional. This consolidated PLN’s control over the power market although MEMR and local and regional government retains some influence in certain matters. Today the electricity market has moved on IEA CLEAN COAL CENTRE
Electricity generation slightly, and while PLN remains the dominant force in the power market, IPPs remain an increasingly important provider of capacity development. Yet, while the crisis in the power market continues, there seems a greater confidence in meeting the challenges.
and offices would be required to use their own power generators ten hours per week between 17:00 and 22:00 hours – the busiest hours for stores and hotels. Shopping centres were opposed to the plan, saying additional costs of up to Rp100 million (US$10,869) per month would be incurred.
18.2 Crisis in the power markets
In 2008, PLN imposed rotating power blackouts in Jakarta and surrounding suburbs due to a massive shortage of power (1000 MWe) resulting from a range of events that hit the region simultaneously. Flooding afflicted 60% of Jakarta for two days, while a disruption in coal and oil deliveries to power stations resulted from rough seas affecting offshore transport (Jakarta Post, 2008a).
The country has suffered from power shortages for many years and PLN has been forced to manage existing power demands despite shortages of power supply. In 2008, Indonesian industry was at risk of losing $4.5 million over a two-month period due to production interruptions resulting from power blackouts (Jakarta Post, 2008d). Industrial facilities avoided power outages by shifting their operation schedules to minimise financial losses. In July 2008, the government responded by issuing a regulation ordering manufacturing industry in Java and Bali to shift one or two working days every month to a weekend, but excluded those facilities that operated 24 h/d. This measure helped save an average of 180 MW/d, but remained well short of the 600 MW/d of savings that was actually required (Jakarta Post, 2008f).
The possibility of mandatory blackouts were also considered during the holy period of Ramadan and the New Year public holiday. Electricity consumption in Java and Bali was estimated to increase by 2.5% during this period and so PLN expected to save up to 200 MWe of electricity every day by forcing commercial properties such as shopping malls, hotels and offices to switch to on-site back-up generators. There is a danger that the Indonesian economy could suffer a repeat of the 1990s economic crisis, resulting in a considerable downturn in end-user demand. This demand ‘destruction’ can be brought about by high prices for energy as well as the impact of blackouts. Yet, a more predictable and possibly fundamental impact on the demand for electricity could be the gradual withdrawal of subsidies to the end-users of electricity.
Hospitals and the Indonesian Red Cross in Bandung reported power cuts disrupting operations with little warning, and back-up power systems could not be brought into service to avert the problem (Jakarta Post, 2008b). While fatalities were not reported, clinical operations remained at high risk of being subject to power cuts.
Figure 14 illustrates the degree to which the government funded Rp35 trillion towards households and industries. In 2008, an estimated state budget of Rp60 trillion was reported to be set aside for financing the subsidised power tariffs for
Further power saving measures were proposed forcing commercial properties in Java and Bali to undergo extreme efficiency measures. Under the PLN regulation, malls, hotels
PLN subsidy – Rp1.77 trillion government subsidy – Rp34.78 trillion consumer payment – Rp70.74 trillion
Rp/kWh
1000
R1 1300 VA
B2 >2200 s/d 200 kVA
R1 2200 VA
B3 >200 kVA 1.3 >200 kVA
R1 900 VA
500
1.4 >30,000 kVA R2-R3 R1 s/d 450 VA 1.1-1.2
B1
households
business groups
industries
social groups
public
S1-S3
P1-P3
0 2.6
43.8
17.3
43.6
4.2
Sales, TWh
Figure 14 Electric power state subsidy to end-users in 2006 (PLN, 2007) Prospects for coal and clean coal technologies in Indonesia
45
Electricity generation 2009 (ESDM, 2008). Given that the elasticity of the demand for electricity might be considered low in many industrialised countries, the proportion of income that is devoted to energy by a household in an emerging economy may be much higher. The demand elasticity may therefore be significantly higher in Indonesia than first thought. Therefore, demand destruction could be potentially high, easing the burden on the power system, reducing the need for new electricity capacity and lessening the financial investment required. The obvious downside is the impact on end-users, notably households, and the ensuing social disruption and probable increase in power theft and losses that might cost the PLN in different ways. However, the signals to suggest this are not yet apparent. Frequent reports of power shortages keep highlighting the threat to the country’s economy especially during periods of global economic crisis.
18.3 Power generating capacity in Indonesia Before 1990, Indonesia had less than 10 GWe of generating capacity; more than half was fuelled by oil products. After 1990, Indonesia witnessed a startling rise in power generating capacity during the initial IPP programme. Power capacity developments throughout most of the 1990s kept pace with the high growth in demand, especially in areas which had previously not been electrified. This growth continued for a short period after the 1997 currency crisis when committed investments were still being built, with a range of gas and coal-fired projects coming on line along with a number of hydro and geothermal developments.
too high and the systems require better maintenance and upgrading. Raising funds to finance such capital intensive projects is difficult as the tariffs remain subsidised. It also puts great pressure on PLN to meet the power station construction targets (IEA, 2008). Tariffs for industrial consumers are already set to rise, but whether this will release enough funds is yet to be seen. The PLN annual report published in 2007 reported the total capacity to be 25 GWe for the year 2006, while MEMR report power generating capacity in 2006 to be around 31 GWe (CDIEMR, 2006). It is likely that the latter refers to the power capacity to which PLN have access, which also includes IPP and industrial generators. This is confirmed by reports from GPR (2008) which estimate that additional capacity of non-PLN generation is around 6–7 GWe. When added to the 25 GWe of capacity stipulated in the PLN annual report, this means the total national capacity is close to 31–32 GWe. Historically, oil has been the main fuel for power generation. As Figure 15 shows, the country’s capacity still has a significant proportion that is oil- and diesel-fired (accounting for 20%). As part of the policy to promote greater energy security, some 8 GWe of diesel-fired capacity is earmarked to be converted to coal-fired capacity, in addition to the extra 10 GWe of new coal-fired power capacity by the year 2010. However, the likelihood of the full capacity conversion occurring by this time is questionable. There has been little reporting of the closure of power stations in Indonesia. In the light of the power supply crisis that has afflicted the Java and Bali grid, there is probably increasing pressure to keep older stations open.
The period 1997 to 2005 saw a rise in consumption averaging 7%/y, yet generating capacity (mainly thermal) did not follow the same trend, but instead grew by just 3–4%/y. The aftermath of the economic crisis led to capacity building slowing down significantly between 2000 and 2003. The period of near zero growth in new capacity construction in the early 2000s had major repercussions leading to a subsequent shortage of capacity in the late 2000s which the government is now keen to rectify. Since 2003, fortunes have changed somewhat for coal-fired power through the ‘crash’ programme (see Chapter 19). The fragmented nature of the country’s islands makes it impossible to establish a unified grid system that covers the entire country. For this reason, power stations were built on the island of Java where there is the most demand for power, although not necessarily endowed with energy resources. The key major power grid is located in Java, which also links Bali and Madura. The major coal reserves are where the smaller power grids exist in Sumatra, Kalimantan, and Sulawesi. According to the official figures published by MEMR (IEA, 2008), the losses incurred by the transmission and distribution network amounted to a substantial 11% in 2007, an improvement on the 16–17% reported in 2002-03. Grid reinforcements and transmission upgrades are seen as an effective way forward to help meet the country’s power needs. Transmission and distribution losses exceeding 10% are still 46
hydroelectricity 11% geothermal 3% coal 34% oil 8% gas GT 9% CCGT 26% diesel 10%
Figure 15 Estimated installed power generating capacity in Indonesia, 2006 (IEA CCC estimates based on MEMR, 2007) IEA CLEAN COAL CENTRE
Electricity generation Today, the bulk of generated power comes from the country’s gas- and coal-fired stations, each of which contributes 34% of the capacity. All the coal capacity is based on conventional boiler and steam turbine technology. Two-thirds of the gas-fired capacity is higher efficiency CCGT; the rest is lower efficiency, but more flexible, single-cycle gas systems (turbines, boilers and internal combustion engines).
to start operation in 2016 and could provide 4000–6000 MWe to the Java-Bali grid although the more detailed progress seems to have been achieved with the Korean 2x1000 MWe project (Jakarta Post, 2008e). According to the MEMR working group, Indonesia needs 10,000 MWe of nuclear capacity on at least three sites in coming years.
Figure 15 shows that hydro accounts for just 11% of the country’s 31 GWe generating capacity.
18.5 Utilisation and efficiency of the power station fleet
Indonesia has a substantial potential for hydroelectricity. According to MEMR (2007), Indonesia has the potential for 75 GWe, with a micro/mini hydro potential of 0.5 GWe. The World Energy Council estimates a gross theoretical capability of 2200 TWh/y, although just 40 TWh is economically exploitable. Reconciling the two figures is dependent on the assumptions of potential hydro operation throughout the year, but assuming a good annual utilisation of 40%, then the economically exploitable capability published by the WEC translates to an installed gross capacity closer to 11 GWe. Other potential, but less significant resources include wind energy potential of 9 GWe, solar potential of 4.8 kWh/m2/d, and a biomass potential of 49 GWe.
Indonesia has a range of both large and very small coal-fired power stations, some as small as a few MW for industrial sites. This is also the case for gas- and oil-fired stations. For this reason, different plants can operate very differently across the energy industry. Official figures published by the MEMR indicate that the capacity factor or utilisation of the thermal fleet averaged 48% in 2006 (IEA, 2008).
Coal-fired generation is discussed in considerably more detail in Chapter 19. However, as a brief introduction, coal-fired generation increased from 0.2 GWe in 1996 to 10 GWe in 2005 driving the total consumption of steam coal in the country from 6 Mt to 27 Mt (Coaltrans, 2006). In early 2006, the government announced that oil-fired power (8 GWe) would be replaced by coal-fired stations. While there are ambitious plans to build new capacity, the supporting infrastructure has been inadequate. According to the IEA (2008), reliability and quality throughout the system has been compromised as repair and maintenance has been less than adequate. Along with the occasional fuel supply disruption, the rising cost of fuel consumption (and emissions) from less efficient plants, has meant that some power stations have been unable to be fully utilised, although improvements are being made in the newer plants.
18.4 Nuclear power Korea has been heavily involved in Indonesia’s efforts to develop nuclear power. The Korea Electric Power Corp and Korea Hydro & Nuclear Power Co (KHNP) signed a memorandum of understanding in 2007 with Indonesia’s PT Medco Energi Internasional to make progress on a feasibility study to build two 1000 MWe OPR-1000 units from KHNP at a cost of US$3 billion. Also in 2007, the Japanese and Indonesian Governments signed an agreement to assist in the preparation, planning, and promotion of Indonesia’s nuclear power development. The IAEA is reviewing the safety aspects of two proposals with Indonesia’s Nuclear Technology Supervisory Agency. While a working group of the Ministry (MEMR) is still considering nuclear power as a concept, local opposition is a problem. One of the proposals, the Muria plant, is earmarked Prospects for coal and clean coal technologies in Indonesia
Official figures of station performance published by MEMR do not provide readily the utilisation or generating efficiency for any particular type of plant, namely coal, gas or oil. Instead, utilisation and generating efficiency trends are published for all ‘thermal’ plants only. Utilisation detail is given, however, for hydroelectricity and geothermal power. Using the best available data, a breakdown of the thermal fleet is still possible. Based on the author’s analysis, the fleet utilisation and efficiency can be derived for a simple list of generating technology types including: ● coal; ● natural gas in combined cycle; ● natural gas in single cycle, boiler, or internal combustion; ● hydroelectricity; ● geothermal; ● other renewables (excluding geothermal and hydro). Despatch curves are an effective method of illustrating the way power stations have operated over a period of a year. Figure 16 provides a representative despatch curve based on the groupings listed above. This despatch ‘curve’ includes the whole Indonesian power generating fleet as of 2006, inclusive of both PLN and non-PLN generators. In reality, the despatch of power stations is not carried out in such discrete blocks. On a day-to-day basis, the despatch curve is smooth and generation for individual station units is spread across the curve. Station despatch changes hourly as well as annually depending on the availability of the plant and the cost of generation. Nevertheless, the illustration provides a useful simplified picture of the way a fleet of stations operate over a typical year. Figure 16 shows how the country’s 30 GWe of generating capacity comprises mainly coal-fired and gas-fired CCGT capacity. The vertical axis indicates the amount of generating capacity the country had operating in 2006-07, and the horizontal axis shows the percentage of the year that these fleets of power stations operated, otherwise referred to as utilisation (100% being 365 days, or 8760 hours). The area of each block indicates the amount of power generated in GWh (convert % utilisation to hours by multiplying by 87.6). 47
Electricity generation 35 oil (boiler/IC/turbine)
Gross generating capacity, GWe
30
gas turbine/boiler/CHP hydroelectricity
25 gas CCGT existing coal 20 geothermal and others 15
10
5
0 0
5
10
10
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
95
100
Utilisation, %
Figure 16 Representative power despatch curve for Indonesia. Based on utilisations averaged over seven years, and capacity levels for 2006 One of the outcomes of the IEA CCC analysis is the modest utilisation of the coal and CCGT plants, which average 60% or less, somewhat higher than the official 48% for all thermal plants. Given that the country has been heading towards a state of power shortage, one would expect thermal plants to have been pushed harder to produce more power. That they haven’t could be due to a range of factors such as fuel availability; the rise in fuel input prices making operation of inefficient plant prohibitively expensive; and inadequate infrastructure development to carry more electricity across the grid from the power stations. Nevertheless, the figure of 60% utilisation still seems low when compared to the utilisation of some of the more recently built coal-fired stations. Some newer coal-fired stations have been available for operation for well over 80% of the year, such as those at the Paiton II complex (Elsworth, 2008) . This potential for high utilisation would infer that other, older coal stations must be operating well below the fleet average for coal of 60–65%. Gas-fired (non-CCGT) and oil-fired generators act as either back-up or peaking plant during periods of high demand, and so are located further up the despatch curve. The rising cost of oil products in recent years means that operating oil plants have become prohibitively expensive, given the low generating efficiencies achieved by some of these ageing plants. However, a massive drop in the world price of crude oil in late-2008 and early-2009 may make oil generation more attractive, but not by much if the prices of gas and coal drop as well. Coal-fired power is discussed in more detail in Chapters 19–21. Hydroelectricity is considered a ‘must-run’ source of power, and hence during periods of low reservoir or run-of-river 48
levels, shortfalls in availability and output must be met by fossil-fuelled sources. Yet, since 2000 utilisation has averaged little more than 30%. Opponents of fossil fuels might push for a greater role for renewable energy; however in times of need, renewables cannot always deliver. For example, the Cirata and Saguling hydroelectric stations in West Java operated below capacity due to the poor availability of water. Low hydro availability seems an unusual problem given that flooding affected Jakarta, but nevertheless illustrates the limited conditions under which hydro can operate. Hydro requires weeks and months of steady water supply in preceding months before it can adequately supply electricity to any market. Promoting more wind energy is always possible, but current technology is insufficient to meet the needs of a rapidly growing economy in a cost-effective way. Given the geographical nature of Indonesia, the amount of wind capacity to service a 30% reserve margin above peak demand would require a phenomenal investment in a form of power generation that can be highly (and regularly) unpredictable, again underestimating the complex nature of renewable investments in many parts of the world. In the right location, geothermal energy provides a much more secure form of electricity production than both wind and hydro, and has been actively pursued in Indonesia. Geothermal power is a more stable and available source of renewable power, albeit limited by extremely high capital costs per kWe and suitable locations. Geothermal power is available for around 90% of the year in Indonesia, which is probably better than any other form of renewable energy. Its high utilisation makes it superior in many ways to wind power and hydroelectricity. Indonesia lies on the cusp of three tectonic plates, the edge of IEA CLEAN COAL CENTRE
Electricity generation the Euro-Asian plate, the northward moving Indo-Australian plate, and the westward-moving Pacific plate. The Indonesian region is therefore one of the most seismically active zones on earth and has many active and potentially active volcanoes. Out of the 400 or so volcanoes in Indonesia, 100 are active. Volcanoes are located along the entire western coasts of Sumatra and through Java. Much of the volcanic activity involves eruptions of ash, but seldom lava. Indonesia is the fourth largest generator of geothermal electricity in the world, producing 6770 GWh of electricity in 2006 (CDIEMR, 2007). The top three producers of geothermal power are the USA, Philippines and Mexico. The government has identified as many as 255 prospects, of which 70 are specified as high-temperature reservoirs, with an estimated total resource potential of nearly 20,000 MWe (WEC, 2007). Of this potential, about 48% is in Sumatra, 30% in Java-Bali, 7% in Sulawesi and 15% in other islands. Taken together, the low and high-enthalpy potential totals some 27,000 MW. The effects of Indonesia’s financial crisis in 1997 are still being felt. Prior to this time the Government had planned to install some 3000 MW geothermal power by 2006, but by end-2004 the country had increased its installed geothermal electric power generation capacity to just 797 MWe (operationally capable of at least 807 MWe). This latter figure includes existing facilities at Gunung Salak (330 MWe), Kamojang (140 MWe), Darajat (145 MWe), Wayang Windu (110 MWe), Sibayak (2 MWe), Lahendang (20 MWe), and Dieng (60 MWe). It remains the Government’s policy to significantly alter the fuel mix of electricity generation by increasing the use of coal, geothermal energy and hydro power and thus reducing the use of oil and gas. To this end, it plans to have 6000 MWe of geothermal generating plant installed by 2020.
18.6 Generating efficiencies of the thermal fleet Rising fuel input costs hamper PLN’s ability to operate the system effectively, whilst still running quite inefficient plant capacity, especially amongst the older plants. Like utilisation, MEMR publishes trends in station efficiency, but for the total thermal generating fleet. As of 2006, the average efficiency of all thermal plants stood at 34%. This efficiency level is not low by the standards of many emerging economies. However, considering a large proportion of the power output comes from higher efficiency CCGT, it could suggest that much of the existing non-CCGT capacity, namely older gas, coal, and oilfired plants, are all operating at or below the average of 34%. Based on the author’s analysis, a breakdown of station efficiencies can be calculated for all the main groups listed in Section 18.5. The average net efficiency of the coal-fired fleet was estimated to be around 30%, which is typical of older subcritical stations, but seems low when compared to the list of newer build stations shown in Table 6. The list in Table 6 was published by Marpaung and Miyatake (2003) and provides plant-by-plant heat rates that have been converted to percentage efficiencies and show that the newer coal-fired stations are achieving efficiencies of 34–37%. This efficiency rate is more plausible as the major complexes located at Paiton, Suralaya, and Tanjung Jati account for more than 8 GWe of coal-fired generating capacity, and therefore at least 80% of the coal fired capacity in the country. It seems unlikely the calculated fleet efficiency of 30% is due to the numerous smaller stations, which account for just the remaining fifth of the coal generating stations. The discrepancy may arise from overestimates of coal consumption by the IEA, or under-reporting of the power output from coal stations as published by PLN. Either way,
60
50
Net efficiency, %
40
30
20
10
0 gas CCGT
gas turbine/ boiler/CHP
existing coal
oil (boiler/IC/ turbine)
officially reported thermal average
Figure 17 Percentage efficiency of Indonesian power fleet in 2006 (MEMR, 2008) Prospects for coal and clean coal technologies in Indonesia
49
Electricity generation Table 6
Heat rates and efficiencies of selected Indonesian power stations (Marpaung and Miyatake, 2003)
Plant
Technology
Fuel
kcal/kWh heat rate
kWh input
% efficiency
Suralaya
Steam boiler
Coal
2532
2.943
34
Suralaya
Steam boiler
Coal
2433
2.828
35
Paiton
Steam boiler
Coal
2380
2.766
36
Paiton I
Steam Boiler
Coal
2324
2.701
37
Paiton II
Steam Boiler
Coal
2324
2.701
37
Tanjung Jati B
Steam Boiler
Coal
2324
2.701
37
M Karang
CC
Diesel
1880
2.185
46
M Tawar
CC
Diesel
2067
2.402
42
T Lorok
CC
Diesel
2034
2.364
42
Grati
CC
Diesel
1866
2.169
46
M Tawar
GT
Diesel
3147
3.658
27
Grati
GT
Diesel
2799
3.253
31
Gresik
GT
Diesel
4230
4.916
20
Bali
GT
Diesel
4683
5.443
18
Bali
GT
Diesel
3423
3.978
25
Bali
GT
Diesel
3448
4.007
25
Gilimanuk
GT
Diesel
2996
3.482
29
Priok
Steam boiler
Diesel
2857
3.320
30
Bali
Steam boiler
Diesel
2268
2.636
38
Priok
CC
Natural gas
1997
2.321
43
Gresik
CC
Natural gas
2047
2.379
42
M Karang
Steam boiler
Natural gas
2999
3.486
29
M Karang
Steam boiler
Natural gas
2699
3.137
32
Cikarang
GT
Natural gas
2047
2.379
42
T Lorok
Steam boiler
Oil
2955
3.434
29
Gresik
Steam boiler
Oil
2661
3.093
32
Gresik
Steam boiler
Oil
2529
2.939
34
the data that is provided publicly does not provide a clear enough picture. According to author calculations, the average efficiency of the CCGT fleet is just below 50%, a figure typical of plants built in the 1990s, but low compared to the efficiencies of 50–60% typical for this type of technology built today (see Figure 17). The efficiencies for the remaining thermal stations, namely gas and oil (in both combined cycle and non-combined cycle) suggest that listed CCGTs operate at around 42–43%, and non-CCGT and oil stations operate at around 31%, although some operate at an efficiency as low as 18%. This shows that, apart from coal, the average estimates calculated for the fleet shown in Figure 17 are in broad agreement with the list of stations in Table 6. 50
Author’s analysis suggests that existing oil boilers operate at a notably poorer generating efficiency of around 25%. A large proportion of the oil-fired units are internal combustion generators using diesel, and anecdotally, it is suggested that many power blackouts were avoided in the past by commercial and wealthy domestic users switching to diesel back-up generators in times of need. The low efficiencies of all the older thermal generators makes fossil fuel generation relatively expensive. Electricity tariffs paid by end-users in industry, commerce and households are subsidised and so therefore do not reflect properly the cost of power generation in Indonesia today. Large subsidies place great pressure on government funding, as well as placing pressure on PLN to deliver on investment targets while unable IEA CLEAN COAL CENTRE
Electricity generation to pass on the cost increases to customers in full. This will continue to be a burden unless subsidies are revised significantly. However, recommending a withdrawal of subsidies is straightforward, but the political and social sensitivity of removing subsidies and raising tariffs to end-users is a critical consideration.
Prospects for coal and clean coal technologies in Indonesia
51
19 Coal-fired technology in Indonesia In 2006, coal-fired capacity amounted to just over 10 GWe. All the units were subcritical and almost 80% of the capacity was built after 2000; therefore the fleet is comparatively new. The IEA CoalPower database has a complete list of coal-fired stations and their respective unit sizes and design parameters, and from this the author’s analysis shows the average size of a coal-fired unit in Indonesia to be 150–200 MWe. However, there is a gradual trend to slightly larger units when comparing the average unit size built in the 1990s (150 MWe) to those built in the 2000s (200 MWe). Some of the largest stations comprise up to 660 MWe units, such as those built at the Paiton I and II, Tanjung Jati B, and Suralaya 1–6 power complexes. These stations are equipped to modern standards with particulate control and flue gas desulphurisation (FGD), and some are fitted with low NOx burners. In total, Indonesia has 8 GWe of capacity fitted with some form of SO2 control, either through scrubbing or boiler sorbent design. This accounts for 80% of the coal-fired capacity. Paitons I and II use seawater for cooling and FGD, making up 2.6 GWe of the FGD capacity in the country. A further 1.3 GWe of the country’s coal-fired capacity is fitted with standard FGD technology such as wet limestone scrubbers at the Tanjung Jati B power plant (units 1 and 2), with a further two units fitted with similar equipment and due online by 2010. More than 8 GWe of coal-fired capacity is also fitted with particulate filters, while 4 GWe have low NOx facilities mainly from low NOx boiler design. These stations set the standards for efficiency for future projects in Indonesia, but are not major advances in technology by global standards as they operate under subcritical steam conditions. While supercritical plants are likely to achieve 40–44% net efficiency, the current fleet of old and newer plants is well below 40% (net). While the current average generating efficiency is calculated to be around 30% for the coal-fired fleet, plants such as Paiton are operating at closer to 37–39%. However, in August 2008, International Power announced a new project that could be completed by 2012, the Paiton III. The new Paiton III project could steer Indonesia towards developing more supercritical stations if it is built and commissioned successfully. This project consists of an 815 MWe plant located on the Paiton complex in the east of Java, and is designed with supercritical steam conditions, to boost its efficiency above those stations operating in the country today. However, financial closure of the project was due in 2009 and comprises of a combination of debt and equity. Whether the debt will still be financially sound during the global credit crisis in 2008-09 means that the project, like many others, could face difficulties. Nevertheless, the project is heavily supported by a PPA lasting 30 years with PLN. The project should cost 1780 $/kWe, to be financed by a mix of project finance and equity. The sales tariff was set at 52
42 $/MWh, comparable with 43.6 $/MWh set for the 660 MWe Cirebon plant in West Java. Paiton III is part of the Paiton complex (plants 1 and 2 are owned and operated by separate companies) which comprises a number of large power stations. Another being constructed by PLN is the 1320 MWe Paiton Baru which is due online in 2010, and will be supplied by PT Arutmin. Other projects include PT Makmur Sejahtera Wisesa (PT Adaro) which is a 60 MWe plant based on twin 30 MWe circulating fluidised bed (CFBC) units. The project also has the security of a 13-year power purchase agreement with Adaro Indonesia. Tanjung Jati is another potential site for a supercritical station in West Java, also being developed by International Power. According to Elsworth and Mackey (2008), the project is to be located at Cirebon West Java. The nominal capacity is expected to be 1320 MWe, but since this plant is planned for sometime after 2015, the capacity of the station may well change if it is built. PLN also plan to include potential supercritical stations over the long term: Indramayu (2 x 1000 MW) and Cilacap (2 x 1000 MW). Both locations are in West Java and are currently only being considered. Fluidised bed technologies are also utilised for effective sulphur and ash control at two stations, the 200 MWe Tarahan Baru and a small 22 MW at Jatiluhur Factory with boilers built by Indian boiler manufacturer, BHEL. The ACFB boiler used in Tarahan Baru was supplied by the Japanese firm Fuji. More information regarding fluidised bed technology can be obtained from www.iea-coal.org.
19.1 The ‘crash programme’ – Phase I (2006-10) and Phase II (2009-13) The importance of the ‘crash programme’ goes well beyond just meeting the shortage of supply of electricity. The move away from fuels such as oil and less emphasis on gas -fired power relieves the demand on the tightening supplies of pipeline natural gas from domestic sources, and the rising cost of fuel oil, at least for the next few years. In response to the widespread and frequent blackouts experienced across Java, the government ‘crash programme’ aims to commission 20,000 MWe of new generating capacity, 10,000 MWe of which was scheduled to come online by 2010, and the remaining 10,000 MWe some time after as finances permitted. The initial 10,000 MWe due by the end of 2010 is fuelled entirely by coal, including 3000 MWe located in western Java that will utilise low rank coal reserves. The remaining 7000 MWe of coal-fired plants are located within the Java-Bali grid system. Table 7 lists the key coal-fired power projects that were planned to form a major part of the first phase of the ‘crash IEA CLEAN COAL CENTRE
Coal-fired technology is Indonesia Table 7
Coal-based power plant construction by PLN (PLN, 2007)
Project
Capacity, MW
Operating year
Location
PLTU Southern West Java
3 x 300–400
2010
Sukabumi, West Java
PLTU 1 East Java, Pacitan
2 x 300
2010
Pacitan, East Java
PLTU Labuan
2 x 300–400
–
Pandeglang, West Java
PLTU Tanjung Jati Baru
1 x 600–700
2010
Jepara, Central Java
PLTU Rembang
2 x 300–400
2009
Rembang, Central Java
PLTU 1 Banten, Suralaya
1 x 600–700
2010
Suralaya, Cilegon
PLTU 3 Banten Project
3 x 300–400
2009
Kemiri, Tangerang
PLTU West North Java
3 x 300
2010
Indramayu, West Java
PLTU Tanjung Awar-Awar
3 x 300–400
2009
Tuban, East Java
PLTU Paiton Baru
3 x 600
2010
Probolinggo, East Java
PLTU Madura
2 x 100
–
Pamekasan, Madura
PLTGU Bojonegara
3 x 740
–
Cilegon, Banten
PLTU Indramayu
2 x 300
–
Indramayu Betung, South Sumatra
PLTU Nusa Penida
2 x 100
–
Nusa Penida Island
PLTU Anyer
1 x 330
–
Anyer, Banten
PLTU Kuala Tanjung
2 x 112
–
South Sumatra
PLTU Banjarsari
2 x 100
–
South Sumatra
PLTU Banyuasin
2 x 100
–
Betung, South Sumatra
PLTU Baturaja
2 x 100
–
South Sumatra
PLTU Tanjung
2 x 55
–
South Kalimantan
PLTA Poso
255
–
Central Sulawest
PLTU Arahan
4 x 600
2012
Muara Enim, South Sumatra
PLTU Central Bangko
4 x 600
2010/2011
Muara Enim, South Sumatra
programme’. Not all of these projects would be completed within the proposed timescale, and some may not be built. Nevertheless, the programme remains a firm commitment to alleviate the power crisis that already faces much of the economy. Based on the list, seven of the eleven projects will be located in Java and two in Sumatra. The entire list represents 18,000 MWe, although 12,600 MWe had commissioning dates as of 2006 when the list was originally compiled. The construction and financial status of each project changes and it is quite likely that the names, capacities, and final commissioning dates will have altered by 2010. The Phase I of the programme cost $8 bn. Of the $8 bn total funding, the programme required $4.4 bn in foreign currency loans. As of August 2008, just $2.4 bn had been raised (PiA, 2008). A further $1.4 bn was raised from local currency loans, out of a total $1.9 bn required for the programme. As the target date of 2010 for the first phase of the ‘crash programme’ was drawing closer, refinancing during the 2008-09 global economic problems led to higher loan interest rates being sought by some funding bodies, such as the Prospects for coal and clean coal technologies in Indonesia
foreign lender the Chinese Export-Import Bank and other Chinese investors (PiA, 2009). PLN investments were therefore subject to the risks faced by global financial markets, especially from that of foreign lenders. By April 2009, Chinese lenders accounted for $1.7 bn of the $5.5 bn funds PLN had secured (Ismar, 2009). Phase II of the ‘crash programme’ consists of plants to come on line between 2009 and 2013, but given the delays experienced by the first phase, many Phase I stations are unlikely to come online until at least 2011, and so the first and second phases will overlap, with Phase II projects likely to be completed thereafter. Financing Phase II of the ‘crash programme’ will require $17.25 bn, more than double the unit cost of the coal-fired projects in Phase I (PiA, 2009). The reason for the hike in cost is the increased role of independent power producers (IPP) who will require higher returns on investment. Furthermore, Phase II has less emphasis on coal-fired power, and instead includes 4.7 GWe of geothermal capacity which incurs a higher capital investment than coal projects.
53
Coal-fired technology is Indonesia Only 2.6 GWe is expected to be coal fired, 1.4 GWe will be gas fired, and 1.2 GWe hydroelectric plant. While the operation of all the plant is expected to start in 2014, if finance problems arise as it did for Phase I, it is possible that the completion of the ‘crash programme’ may be sometime around 2016, but this has not been confirmed by any official source.
the ‘crash programme’ which expects geothermal and gasfired projects to feature in the investment programme. One of the notable features of the second phase of the ‘crash programme is the heavier reliance on private sector involvement, much of which could come from foreign interests.
While there appears to be some expectation that the government target could fall short, it does demonstrate a pro-active attitude of the government towards the electricity crisis, and soon after the aftermath of the currency crisis of the 1990s. Indonesia is also studying the possibility of building a high voltage cable across the Sunda straits which separates the southern tip of Sumatra and the western part of Java. The 800 km link would be capable of transmitting 3000 MWe between South Sumatra and Java. Provided funding of $1.8 bn is raised, the project could be completed by 2012 (Energy Times, 2008).
Figure 18 factors in a 2–3 year delay in the commissioning of some of the plants, omitting those stations where the commissioning date is not yet known.
The economic crisis of the 1990s left the private sector reluctant to reinvest in Indonesia for some years, but there has been a turnaround in sentiment more recently. The PLN capacity construction plans and IPP stations that are under construction will result in the trend seen in Figure 18 – assuming no further decommissioning occurs. Between 2000 and 2005, Indonesia saw no new coal-fired stations coming online, but 2006 brought in the 300 MWe Calicap power station and Tanjung Jati B (2 x 660 MWe) stations. The initial operation of Tanjung Jati B was not straightforward as problems with weather affected logistics which subsequently hit coal supply. Between 2006 and 2012, Indonesia could see a doubling of its coal-fired power station capacity (see Figure 18). This doubling assumes the construction of only those stations shown in Table 7 that have firm commissioning dates, namely the 12.6 GWe of stations earmarked to come online between 2009 and 2012, which overlaps with the Phase II of
Whether this building trend is enough to meet the demand remains to be seen, but with improvements in operating utilisation and efficiencies of the coal-fired fleet, plus improvements in transmission, coal is clearly helping to alleviate the power crisis, although there is some way to go. Environmentally, the use of control systems can minimise air pollution, but CO2 emissions from the power sector are set to rise. Over the long term this will be deemed unacceptable if Indonesia signs up to CO2 emission cuts under a global agreement. In the meantime, CO2 reduction measures have been at the periphery of Indonesian energy policy, but are quickly growing in importance.
19.2 Clean coal technology and tackling climate change According to the IEA (2008), Indonesia ranked 19th amongst the highest emitters of fossil fuel greenhouse gases, with some 24% attributed to coal burning. Considering the major push to promote energy and economic security through adoption of coal-fired generation, any increase in CO2 emissions is likely to be substantial. According to reports in 2008, emissions from the energy sector could rise from 1 GtCO2 to 2.9 Gt in 2050 (Simamora, 2008). As road transport and industry are also consumers of primary energy, this level will be much higher.
60
Power generating capacity, GWe
50
additional coal (PLN with delayed schedule) additional coal existing coal gas CCGT
oil (boiler/IC/turbine) gas turbine/boiler/CHP wind/solar/geothermal/tidal hydroelectricity
40
30
20
10
0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Figure 18 Power capacity trends 2000-15, GWe 54
IEA CLEAN COAL CENTRE
Coal-fired technology is Indonesia Tackling air pollution such as SOx, NOx and particulate matter is relatively straightforward, while the only promising development to limit the rise in CO2 would be the adoption of supercritical technology for coal-fired plant. Since the fleet of coal stations was built within the last 10–20 years, it is premature to replace the existing plant, but over the long term, a replacement or upgrade regime of subcritical stations to supercritical or ultra-supercritical stations will need to be considered. While gas-fired power and renewables are likely alternatives, the depletion of gas reserves rules out any major policy shift to reliance on power generated from domestically produced gas (although it does not rule out imported LNG). In 2006, President Susilo Bambang Yudhoyono issued a presidential decree to increase the percentage of renewable energy usage to 17% by 2025. Predictable renewable energies are limited to geothermal and hydroelectricity which are location dependent but will continue to be explored. Unpredictable and more intermittent wind power could add considerable strain to a transmission system that is already under intense pressure and at risk of failure in many parts of the country. Nevertheless, renewable energy should still be pursued wherever it is practicable to do so. Efforts are being made worldwide on clean coal technology R&D, but commercial deployment is still a long way off, and it is not a viable solution for Indonesia in the short to medium term. However, carbon capture and storage (CCS) is being pushed politically as a potential lifeline for the dwindling oil industry. It could benefit greatly from CCS and CO2 injection into oil reservoirs to boost recovery of oil reserves. In 2008, Indonesia held a workshop on the role of CCS in Indonesia where the Energy and Mineral Resources Minister, Purnomo Yusgiantoro, and the State Minister for the Environment, Rachmat Witoelar, declared that CCS technology was the most practical method of containing large quantities of CO2. Not only would the energy sector cut emissions, but the country’s oil production could increase by 60%. A study by Lemigas suggested that East Kalimantan and South Sumatra could be selected as potential candidates for CCS projects since many depleted oil and gas reservoirs are located conveniently near emission sources such as coal-fired power station and LNG plants. However, Indonesia’s hope of implementing CCS at even the demonstration stage is dependent on international co-operation and funding. If the CDM mechanism under the Kyoto Protocol (or succeeding agreement) recognises CCS as a viable technology, richer countries could provide funding for CCS developers to build and operate in Indonesia. In exchange, every tonne of CO2 that is stored (permanently) helps to offset CO2 reduction targets in those participating richer countries – but at a price. Unless the price of internationally tradeable CO2 is both predictable and high enough, there will be little incentive to invest. The potential to host emission cutting projects is therefore large in Indonesia, but highly unlikely to be developed by Indonesian firms or state-run bodies alone.
Prospects for coal and clean coal technologies in Indonesia
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20 Coal demand boom in the power sector Coal consumption in Indonesia has been boosted by the Indonesian Government’s pledge to reduce the role of oil and wood fuels in most sections of the economy. The increasing demand for coal in recent years for industry and power utilities has been driven by continuing economic growth. Given the relatively low GDP per capita at just US$1640 (2006), increased economic activity has brought about a natural rise in the demand for energy and particularly for coal-fired electricity. Since 2000, domestic coal sales have increased by 14%/y, reaching almost 50 Mt in 2006 (Figure 19). Considerable growth in coal consumption is expected, underpinned by government plans to increase coal-fired power station capacity by at least 10,000 MWe by 2010, and a further 2600 MWe by 2014 (see Section 19.1). This development in coal-fired power sits alongside other developments in geothermal, gas and hydro power, but coal-fired power spearheads the overall programme of development. The power market is controlled by the state company PLN, and has seen demand for coal rise by 12.5%/y, doubling consumption from 12 Mtce in 2000 to 24 Mtce in 2006, and is set to continue growing. In 2005, the country had ten coal-fired power stations, six owned and operated by PLN. The largest of the ten is the Suralaya power station which has a capacity of 3400 MWe and consumes around 9–12 Mt of coal per year making it a significant consumer and emitter of CO2.
20.1 The role of low rank coal in the power sector According to MEMR (2008a), the total demand for ‘low rank’ 50
Low rank coals such as lignite are limited in their tradeability due to the high cost of transporting a low heating value coal which carries much moisture. The coal qualities of lignite overlap with poorer quality subbituminous coals and so the definition of lignite might be confusing when determining which company produces which specific type of coal. For instance, exportable products such as Arutmin’s Ecocoal and Kideco’s Samarangau both contain 35% moisture and heating values of roughly 21 MJ/kg (5000 kcal/kg). Typically, a lignite might therefore be around 15 MJ/kg (3600 kcal/kg), with moisture content possibly exceeding 40%. Indonesia is rich in lignite and high moisture subbituminous coals. The main producer of lignite is the state-owned PT Bukit Asam (PTBA) although smaller tonnages are also produced by the private company Gunung Bayan and other, smaller producers in West and South Sumatra. Power stations that burn purely lignite are not always straightforward to identify as many burn subbituminous coals with high moisture contents. According to the IEA
other industry pulp and paper industry cement electricity generation iron and steel
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Sales, Mtce
coal in the power sector could grow to 72 Mt by 2010 fuelling 18 GWe of generating capacity. The term ‘low rank’ typically refers to high moisture coals, namely lignite, but also encompasses some subbituminous coals so the definition of ‘low rank’ must be treated with care. In 2006, the total sales of all coals to the power sector stood at 28 Mt (ICMA, 2006). The ‘crash programme’ could increase total demand for coal in the electricity sector in 2015 to 96 Mt/y, and 118 Mt/y by 2025. While this shift to coal-fired power is occurring, the government is hoping to wean the economy away from oil. Oil is the key commodity to which Indonesia is most exposed in terms of price risk, due to the shift to imports and loss of domestic production.
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Figure 19 Domestic coal sales within Indonesia 2000-06, Mtce (CDIEMR, 2007) 56
IEA CLEAN COAL CENTRE
Coal demand boom in the power sector CCC power station database, CoalPower, the Banjarmasin power station operated by PLN is one such example of a station that burns lignite. At just 130 MWe Banjarmasin is not a significant producer of electricity. However, Indonesia has around 5–6 GWe of generating capacity fuelled by subbituminous coals whose qualities border on lignite in terms of moisture content, but have a higher calorific value (as defined by MEMR as having a heating value
