Electricity Supply Business Plan

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3 Executive Summary Electricity Supply Business Plan PT PLN (Persero)

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5 CONTENTS PURPOSE AND SCOPE RUPTL 1 BUSINESS GROWTH AND CURRENT CONDITIONS OF ELECTRICITY SUPPLY 1 SHORT-TERM RESPONSE EFFORTS 2 AVAILABILITY OF PRIMARY ENERGY 2 POWER SYSTEM PLANNING POLICY AND DESIGN CRITERIA 2 POWER DEMAND FORECAST 3 PLANS FOR ADDITIONAL POWER GENERATION 4 CO 2 EMISSION PROJECTION 6 CARBON FINANCE PROJECT 7 DEVELOPMENT PLAN FOR TRANSMISSION AND SUBSTATION 7 INVESTMENT NEEDS 9 JAVA-BALI SYSTEM DEVELOPMENT PLAN 9 SUMATERA SYSTEM DEVELOPMENT PLAN 15 WEST KALIMANTAN SYSTEM DEVELOPMENT PLAN 19 SOUTH, CENTRAL AND EAST KALIMANTAN SYSTEM DEVELOPMENT PLAN 22 NORTH SULAWESI SYSTEM DEVELOPMENT PLAN 26 SOUTH SULAWESI SYSTEM DEVELOPMENT PLAN 27 DEVELOPMENT PLAN FOR NEW AND RENEWABLE ENERGY 31 DEVELOPMENT PLAN FOR ISOLATED POWER SYSTEMS 32 RISK ANALYSIS 32 CONCLUSION Executive Summary Electricity Supply Business Plan iii

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7 PURPOSE AND SCOPE RUPTL The Electricity Supply Business Plan (RUPTL) by PT PLN (Persero) for the period has been issued to fulfill the mandate of the Government Regulation No on Power Supply Operations and to serve as guidance for the development of power infrastructure to meet electricity demand within PLN business areas in an efficient and well-planned manner, in order to prevent inefficiencies from starting at the planning stage. RUPTL covers electricity demand load forecasts, generation capacity expansion plans and the development plans related to transmission, substations and distribution. Projected electricity demand has been prepared for each province and electricity system, including the electricity systems in remote islands across the region. Development plans for generating capacity, transmission and substation are also for their respective projects. Electricity demand forecasts are prepared to project the electricity needed to support economic growth targeted by the government and to take into consideration population growth. The development of generation capacity has been planned to meet the growing demand for electricity, reserve margin and to the extent possible, based on the principle of lowest cost. Utilization of local energy sources is also prioritized, especially renewable energy such as geothermal and hydropower. Several projects have been confirmed as undertaken as a PLN project or independent power producer (IPP) project, whilst some projects have not been designated as either a PLN or IPP project. This is intended for PLN to decide a later stage, with the approval of the Government, whether a project is implemented as a PLN or IPP project. The development of the transmission system is planned to strike a balance between generation capacity and power requirements efficiently to meet certain reliability and quality criteria. In electricity systems as large as Sumatera and Java, an extra high voltage transmission line has been planned for the transmission system, to form the backbone of the electrical system. BUSINESS GROWTH AND CURRENT CONDITIONS OFELECTRICITY SUPPLY In the last five years, between 2008 and 2012, PLN s business has continued to grow. Electricity sales increased from 128 TWh in 2008 to 172 TWh in 2012, the number of customers increased from 39 million in 2008 to 50 million in 2012 and the electrification ratio increased from 62.3% in 2008 to 75.9% in The electricity landscape by September 2013 can be described as follows: As of September 2013 the installed capacity of PLN power plants and IPPs in Indonesia was 40,533 MW, consisting of 31,815 MW in Java-Bali and 8,718 MW in Sumatera and East Indonesia, excluding 2,933 MW of rental generating units. Generating capacity in Sumatera and East Indonesia is barely sufficient to meet the electricity needs of the community, but there can be a shortfall when there is disruption to the power supply or a plant needs to undergo routine maintenance. For example, the electricity system of North Sumatera operates for almost the whole year without backup operation and often faces shortfalls in electricity supply, resulting in the operation of many liquid fuel generating plants. The South Sumatera system also experiences a similar issue, suffering from shortfalls in electricity supply for most of the year. This situation also occurs in several other areas, such as East Kalimantan, South Kalimantan, Southeast Sulawesi, Minahasa-Gorontalo, Palu, Lombok, Ambon, Ternate and Jayapura. Smaller deficits are also observed in other smaller electricity systems. In Java and Bali, there is enough generating capacity to meet the power requirements. However, certain operational issues were faced in 2012, such as insufficient gas supply for PLN s power plants, over-loading of many transformers, as well as the increasing transfer of power from Central JavaEast Java to West Java, which resulted in voltage in the system transmission during peak-load periods Executive Summary Electricity Supply Business Plan

8 SHORT-TERM RESPONSE EFFORTS The problems in electricity supply that need to be addressed are an urgent need to meet electricity demand in areas that lack electricity supply, replacing oil-fired plants with a non-petroleum fuels and to electrify regions where there is no supply of electricity. Certain actions that have been taken in West and East Indonesia, including rental of generation capacity, purchase of electricity from small-scale IPPs, partnershipco-operation with local governments, purchase of excess power, acceleration of the development of coal-fired power plants as stipulated in PR712006, building of transmission lines, securing continuity of primary energy supply and installation of solar power plants. Short-term measures in the Java - Bali system include acceleration of the procurement of kv transformer and kv interbus, adding generating capacity in Bali, accelerating the commissioning of submarine cables in Java-Bali 150 kv circuits 3 and 4 and installing shunt capacitors in the Jakarta system to improve voltage levels. AVAILABILITY OF PRIMARY ENERGY Coal resources of 120 billion tonnes and reserves of 28 billion tonnes in Indonesia are the basis for the planning of the development of coal power plants, both coastal power plants using coal at market prices, as well as mine-mouth power plants using low-rank coal at cost price plus a margin. For natural gas, although Indonesia has large reserves amounting to 165 TS, in reality there is insufficient gas available for power generation. In fact, the supply of gas to the existing power plants has been and will be declining such that a deficit in gas supply is expected if there is no new gas supply. In the year 2012, the LNG FSRU plant in Jakarta commenced supply of LNG to power plants in Jakarta during peak load periods. The price of gas in LNG form is relatively high and is only economically viable if used for generation at peak load. Faced with such a gas supply situation, the RUPTL only plans for 2 units of 800 MW Combined cycle gas-fired power plant classes, with the expectation that one unit will received gas supply from the Cepu block, while the gas supply for the other unit is to be determined. LNG for power generation will also be developed in Arun, which will supply peaking power plants in Arun and Pangkalan Brandan and existing power plants in Belawan. Continuing on the topic of gas, the RUPTL plans a smaller number of peaking power plants that will utilize LNG or CNG in East Indonesia. The base load requirements will be met by the planned development of coal fired power plants, while gas supplies will be used for peaking power plants wherever possible, to avoid the use of oil. A large number of plants utilizing renewable energy on large scale, such geothermal and hydro powers, have also been planned in the RUPTL. POWER SYSTEM PLANNING POLICY AND DESIGN CRITERIA Interconnection System RUPTL Power system planning is optimized from an economic perspective, with the objective of achieving a configuration of the development of plants which provide the lowest total NPV of the electricity supply cost, while still meeting certain reliability criteria. The cheapest configuration is obtained through an optimization process or objective function that includes capital costs, fuel costs, operation and maintenance costs and the cost of energy not served. Simulation and optimization is done by using a model called WASP (Wien Automatic System Planning). The reliability criteria used in the planning process is a Loss of Load Probability (LOLP) which is less than 1 day per year. This means the probability of peak loads exceeding available generating capacity is less than 2 Executive Summary Electricity Supply Business Plan

9 0.274%. Calculation of generation capacity based on the LOLP produces a reserve margin, which depends on the generation unit size, availability factor of each unit, number of units and type of units. In the Java-Bali system, the LOLP of < 0.274% is equivalent to a reserve margin of 25-30% of net generation capacity. When expressed in terms of installed capacity, the reserve margin required is approximately 35%. For East Indonesia and West Indonesia, the reserve margin is set at about 40%, in view of a smaller number of generating units, a larger unit size relative to peak load, a higher level of de-rating and a higher growth rate compared to Java Bali. As part of the optimization process, renewable energy generation capacity, particularly geothermal and hydropower, is treated as a fixed system (permitted to enter the grid with no economic optimization required) at the time the project is put into commercial operation. Small Non-InterconnectedIsolated Systems Power generation planning for isolated small systems do not apply probabilistic methods and the economic optimization process, but use the deterministic method. In this method, the planning was based on a N-2 criteria, i.e. the minimum reserve must be greater than the two largest generation units. The reserve is defined as the difference between the total generation capacity of existing power plants and peak load. Transmission Planning Criteria The transmission planning is carried out using both a static and dynamic reliability criteria N-1. The static N-1 criteria requires that when there is an outage in a transmission circuit due to a disruption or maintenance, then the remaining transmission circuits must be able to distribute the overall load, so the continuity of electrical power supply is maintained. The dynamic N-1 criteria requires that in the event of a three-phase short-circuit, followed by the loss of a transmission circuit, then there should not be a loss of synchronization between that group of generators and other groups of generators. Generally, the criteria applied in the RUPTL is that there is a need for additional transformer capacity when the loading of the transformer reaches 70% - 80%. POWER DEMAND FORECAST Between 2013 and 2022, electricity consumption in Indonesia is expected to increase from 189 TWh to 386 TWh, with an average growth of 8.4% per year, as shown in Figure-1. The number of costumers is projected to increase from 54 million to 77 million by 2022, an increase of 2.7 million per annum. The additional customers will increase the electrification ratio from 79.6% to 97.7%. Regionally, the electricity demand in Java-Bali is expected to increase from 144 TWh to 275 TWh, growing at a rate of 7.6% per annum. Demand in East Indonesia is expected to grow more rapidly, increasing from 18 TWh to 46 TWh, a growth rate of 11.2% per annum, while demand in Sumatera is expected to grow from 26 TWh to 66 TWh, a growth rate of 10.6% per annum. Figure-2 shows that in the Java-Bali system, industrial customers account for the largest portion of total consumption, an average of 38.5% of total sales. In East Indonesia and Sumatera, the proportion of consumption by industrial customers is relatively smaller, at 11% and 15.8% respectively. By 2022, residential customers would dominate sales, accounting for 62% of sales in East Indonesia and 55 % in Sumatera Executive Summary Electricity Supply Business Plan

10 Figure-1. Map of Power Demand Growth in Indonesia through Year , , ,000 Indonesia 300, ,000 Jawa-Bali 300, , , , ,000 50,000 - Industrial Public Business Residen al Indonesia 70,000 Sumatera 60,000 50, , , ,000 50,000 - Industrial Public Business Residen al ,000 Eastern Indonesia 45,000 40,000 35,000 40,000 30,000 20,000 10,000 Industrial Public Business Residen al 30,000 25,000 20,000 15,000 10,000 5,000 Industrial Public Business Residen al Figure-2. Power Demand Growth Composition by Customer Group in Indonesia Regions (GWh) RUPTL PLANS FOR ADDITIONAL POWER GENERATION To meet the growing power demand, an additional generating capacity of 59.5 GW for the whole of Indonesia is required, an average growth rate of 6 GW per annum, as shown in Figure-3. The RUPTL plans for PLN and IPPs to develop 16.9 GW and 25.5 GW of capacity respectively, with the remaining 17.1 GW currently unallocated, i.e. projects where developers and funding sources have not been established. 4 Executive Summary Electricity Supply Business Plan

11 Unallocated IPP PLN Figure-3. Additional Generation Capacity Requirement (MW) Figure-4 shows the additional generation capacity required, by plant type. New coal-fired power plants will dominate the additional generation capacity to be developed, accounting for 37.9 GW, or 63.8% of the planned additional capacity. Planned combined cycle gas-fired power plants amount to 5 GW of capacity, or 8.4 %. For renewable energy, the largest planned additional capacity relates to hydropower at 6.5 GW, or 11.0% of the total additional capacity, followed by geothermal at 6.0 GW, or 10.2%. Of this planned additional capacity, around 16.6 GW will be in West Indonesia and around 11.5 GW in East Indonesia. In West Indonesia, there is a 510 MW hydroelectric project Batang Toru to be developed by the private sector, and in East Indonesia there is also a 450 MW hydropower project Karama which will be developed by the private sector. For the Java - Bali system, additional power is about 31.5 GW, or an average of 3.2 GW per year, including 353 MW of mini-hydro and 50 MW of wind turbine power plants. 12,000 10,627 10,000 9,154 8,000 7,473 6,000 4,000 2,000-2,831 3,786 2,838 5,948 5, PP HEPP GeoPP CCPP GTGEPP Others Figure-4. Additional Generation Capacity by Plant Type (MW) The energy mix for power generation in 2022 for Indonesia is projected to be 65.6% coal, 16.6% natural gas (including LNG), 11.0% geothermal, 5.1% hydroelectric and 1.7% oil and other fuels as shown in Figure-5. 5,348 6, Executive Summary Electricity Supply Business Plan

12 500, , , , ,000 GWh 250, , , ,000 50, Import Biomass SolarWindHybrid HSD MFO LNG Gas Coal Geothermal Hydro Figure-5. Projected Electricity Production by Fuel Type for Indonesia Table-1 shows the energy mix for Indonesia from 2013 to Table-1. Projected Primary Energy Requirement No, Fuel Type HSD ( x 10^3 kl ) 6,679 6,007 4,711 3,414 2,651 1,740 1,812 1,757 1,862 2,019 2 MFO ( x 10^3 kl ) 1,267 1,238 1,599 1,544 1, Gas (bcf) LNG (bcf) Batubara (10^6 ton) Biomass (10^3 ton) CO 2 EMISSION PROJECTION System planning process in RUPTL doesn t take into account the CO 2 emissions cost as one of variable costs. However, this doesn t mean that RUPTL ignoring the CO 2 emissions reduction. It can be seen from the number of geothermal and hydropower power plants candidate set into the electrical system even though they are not the lowest cost solution. The use of supercritical boiler technology and ultra supercritical in Java also prove that PLN concerned with the efforts to reduce CO 2 emissions from power generation. RUPTL The amount of emissions is calculated from the amount of fuel used and converted into CO 2 emissions (in tonnes of CO 2 ) by using a multiplier factor (emission factor) issued by the IPCC (Intergovernmental Panel on Climate Change ). Figure 6 shows the CO 2 emissions that would be generated with electricity production and fuel mix as shown in Figure 5. From Figure 6 it can be seen that CO 2 emissions in Indonesia will increase from 165 million tons in 2013 to 339 million tonnes by Of the 339 million tons of emissions, 294 million tons (87%) comes from burning coal. 6 Executive Summary Electricity Supply Business Plan

13 Million tco Biomass HSD MFO LNG Gas Coal Figure-6. CO2 Emission per Fuel Type (Indonesia) Average grid emission factor for Indonesia in 2013 was kgco 2 kwh, will increase to kgco 2 kwh in 2017 and will further decline due to the operation of geothermal and hydro projects so that the average grid emission factor in 2022 became kgco 2 kwh. CARBON FINANCE PROJECT PLN will utilize carbon finance opportunities through the UNFCCC or outside the UNFCCC framework. Carbon finance project implementation will be applied to all activities within the PLN, which has the potential to obtain carbon finance. Since the year 2002 PLN is aware of funding opportunities of carbon through the Clean Development Mechanism (CDM) and do some assessment of potential CDM projects, and results to date PLN has signed several ERPA (Emission Reduction Purchase Agreements). In addition PLN also develop projects through the VCM (Voluntary Carbon Mechanism). Since the expiration of the first commitment of the Kyoto Protocol by the end of 2012, the use of carbon finance will be adjusted to the new carbon financing mechanisms, both within and outside the UNFCCC framework of the UNFCCC. DEVELOPMENT PLAN FOR TRANSMISSION AND SUBSTATION The planned development of the transmission system for the period includes the development of the transmission system with a voltage of 500 kv and 150 kv in the Java-Bali system, and systems with voltage of 500 kv, 275 kv, 150 kv and 70 kv in East Indonesia and West Indonesia. Generally, the construction of the transmission system looks to achieve compatibility between the upstream generation capacity and the downstream portion of the power demand in an efficient manner. In addition, it also looks to overcome bottlenecks and improve service voltage. The development of 500 kv transmission lines in Java is generally intended to transmit power from new and expansion plants and to maintain the N-1 reliability criterion, whether static or dynamic. On the other hand, the development of 150 kv transmission lines is intended to maintain the N-1 reliability criterion and the associated transmission, in relation to the new 150 kv substations Executive Summary Electricity Supply Business Plan

14 kv 150 kv 250 kv DC 275 kv 500 kv DC 500 kv AC Figure-7. Requirement for Development of Transmission Lines by Voltage (kms) kv kv kv 250 kv DC kv 500 kv DC kv kv Figure-8. Requirement for Development of Substations and Transformers by Voltage (MVA) RUPTL The development of 500 kv transmission line in Sumatera is intended to form the backbone of the transmission system, bringing together the interconnections in the eastern corridor of Sumatera. Large-scale power plants and load centers in Sumatera will be connected to this 500 kv transmission system. This transmission system also will transmit power from regions with rich and inexpensive primary energy sources (e.g. Sumbagseland Riau) to regions which lack an affordable primary energy source (e.g. Sumbagut). In addition, a 500 kv transmission line will also be developed in South Sumatera as a feeder electricity supply from the mine mouth power plants to the converter station for the HVDC transmission line, which will connect Sumatera and Java. 8 Executive Summary Electricity Supply Business Plan

15 The development plan for the transmission system in Indonesia by 2022 involves a projected 57,132 kms and 134,435 MVA of substation and transformer as shown in Figure-7 and Figure-8. INVESTMENT NEEDS The development of generation, transmission and distribution infrastructure requires an investment of US$71.1billion for PLN projects alone and a total of US$125.2 billion when combined with the power projects expected to be implemented by the private sectoripps, with annual disbursements as shown in the Figure PLN power plant : US$ 37,2 billion IPP power plant : US$ 54,1 billion Transmission : US$ 19,4 billion Distribution : US$ 14,5 billion Total PLN Total PLN+IPP : US$ 71,1 billion : US$125,2 billion Total Investment PLN Total Investment PLN+IPP Power Plant PLN+IPP Transmission Distribu on Power Plant PLN Figure-9. Investment requirement for the development of electricity To date, many PLN projects have been financed through loans obtained from overseas (two-step loan). However, since 2006 the role of this kind of financing has begun to decline and financing by issuing bonds (both local and global) has been increasing. The 10,000 MW Fast Track project was fully financed by loans to PLN, backed by a guarantee from the Government. Lately, PLN has once again tried to obtain loans from multilateral and bilateral financial institutions to fund power projects, such as the Upper Cisokan pumped storage and the Sumatera-Java HVDC transmission line. JAVA - BALI SYSTEM DEVELOPMENT PLAN The additional generation capacity to be developed over the period of for the Java - Bali system is 31.5 GW, or an average increase in capacity of 3.2 GW per year, including small-scale mini-hydro power plants of 353 MW and wind power plants of 50 MW. The capacity of PLN will increase by as many as 8.3 GW, or 26% of the total planned additional capacity. Private sector participation represents a large proportion of the total planned additional capacity, i.e GW, or 50%, while unallocated projects amount to 7.5 GW, or 24%. Of the types of power generation, coal-fired power plants will represent the majority of additional capacity to be developed, at 22.6 GW, or 71.8%, followed by combined cycle gas-fired power plants with a total capacity of 3.2 GW, or 10.0% and gas-fired plants with total capacity of 0.2 GW, or 0.7 %. As for renewable energy, additional capacity consists of geothermal at 2.8 GW, or 8.9%, hydro electric at 2.6 GW, or 8.4%, and other plants of 0.05 GW, or 0.2%. The breakdown of power generation development in the Java-Bali system is shown in Table Executive Summary Electricity Supply Business Plan

16 Table-2. Power Generation Development Plan in the Java - Bali System PROJECTS Energy Sales GWh 144, , , , , , , , , ,850 Growth % Energy Production GWh 163, , , , , , , , , ,111 Load Factor % Gross Peak Load MW 23,801 25,880 27,982 30,106 32,346 34,605 36,957 39,458 42,112 44,919 GENERATION CAPACITY Net Capacity MW 29,053 29,028 29,028 29,028 29,028 29,028 27,997 27,997 27,997 27,997 Installed Capacity MW 30,285 30,261 30,261 30,261 30,261 30,261 29,229 29,229 29,229 29,229 PLN MW 24,625 24,601 24,601 24,601 24,601 24,601 23,569 23,569 23,569 23,569 RetiredMothballed IPP MW 5,660 5,660 5,660 5,660 5,660 5,660 5,660 5,660 5,660 5,660 RUPTL PLN On-going and Committed Pelabuhan Ratu PP Pacitan PP 630 Tj. Awar-awar PP Adipala PP 660 Indramayu #4 (FTP2) PP 1,000 Upper Cisokan PS HEPP (FTP2) 1,040 Sub Total PLN Ongoing & Committed MW 1,680 1, , ,000 IPP On-going and Committed Celukan Bawang PP Banten PP 625 Sumsel-8 MT PP 1,200 Sumsel-9 MT (PPP) PP Sumsel-10 MT (PPP) PP 600 Cilacap exp PP 614 Madura 2x200 MW PP (FTP2) 400 Jawa Tengah (PPP) PP Rajamandala (FTP2) HEPP 47 Patuha (FTP2) GeoPP Kamojang-5 (FTP2) GeoPP 30 Karaha Bodas (FTP2) GeoPP Tangkuban Perahu 1 GeoPP (FTP2) 110 Ijen (FTP2) GeoPP 110 Iyang Argopuro (FTP2) GeoPP 55 WilisNgebel (FTP2) GeoPP Cibuni (FTP2) GeoPP 10 Tangkuban Perahu 2 GeoPP (FTP2) 60 Cisolok - Cisukarame GeoPP (FTP2) 50 Ungaran (FTP2) GeoPP 55 Wayang Windu (FTP2) GeoPP 220 Dieng (FTP2) GeoPP 115 Tampomas (FTP2) GeoPP 45 Baturaden (FTP2) GeoPP 220 Guci (FTP2) GeoPP 55 Rawa Dano (FTP2) GeoPP 110 Umbul Telomoyo (FTP2) GeoPP 55 Gn. Ciremai (FTP2) GeoPP 110 Gn. Endut (FTP2) GeoPP 55 Sub Total IPP On-going MW & Committed , ,350 2, Executive Summary Electricity Supply Business Plan

17 Table-2. Power Generation Development Plan in the Java - Bali System continued PROYEK PLANNED ADDITIO- NAL CAPACITY Jawa-1 (Load Follower) CCPP 800 Jawa-2 (Load Follower) CCPP 800 Muara Tawar Add-on CCPP Blok 2,3,4 650 Muara Karang Peaker CCPP 450 Grati Peaker CCPP Pesanggaran Peaker GEPP Karangkates #4-5 HEPP 100 Kesamben HEPP 37 Kalikonto-2 HEPP 62 Jatigede (FTP2) HEPP 110 Matenggeng PS HEPP Indramayu #5 PP 1,000 Lontar Exp #4 PP 315 Jawa-1 (FTP2) PP 1,000 Jawa-3 (FTP2) PP Jawa-4 (FTP2) PP 1,000 1,000 Jawa-5 (FTP2) PP 1,000 1,000 Jawa-6 (FTP2) PP 2,000 Jawa-7 PP 1,000 1,000 Iyang Argopuro GeoPP 220 Cisolok - Cisukarame GeoPP 110 Ungaran GeoPP 140 Dieng GeoPP 110 Bedugul GeoPP 10 Gn. Lawu GeoPP 165 Arjuno Welirang GeoPP 110 Sub Total Planned Additional Capacity MW ,225 2,450 3,869 4,110 2,450 1,855 Total Additional Capacity MW 1,680 1, ,869 2,537 5,800 6,684 4,220 2,670 3,255 TOTAL INSTALLED CAPACITY MW 31,965 33,536 34,266 36,135 38,672 44,472 50,124 54,344 57,014 60,269 TOTAL NET CAPACITY MW 30,733 32,303 33,033 34,902 37,439 43,239 48,892 53,112 55,782 59,037 The breakdown of the planned development for Java - Bali power system above indicates that the net reserve margin varies between 16-36%, with the lowest reserve margin occurring in 2015 (18%), 2016 (16%) and 2017 (16%), due to delays some IPP projects such as Sumsel 8 coal-fired power plant (2x600MW), Central Java coal-fired power plant (2x950 MW), Madura coal-fired power plant (2x200 MW), Java-1 coal-fired power plant (1x1,000 MW), Java-3 coal-fired power plant (2x660 MW) as well as some geothermal power plants amounting to 400 MW. In anticipation of lower reserve margins in 2015 to 2017, steps have been taken to address the issue. The Muara Karang combined cycle gas-fired power plant (450 MW), Grati combined cycle gas-fired power plant (450 MW), Pesanggaran gas engine power plant (200 MW) and Java-1combined cycle gas-fired power plant (800 MW) and coal-fired IPPs such as Celukan Bawang power plant (380 MW), Banten power plant (625 MW) and Cilacap expansion (600 MW) should be operational over the period , to ensure that the reserve margin is maintained and does not decline. Plants that undergo changes are as follows: (i) Changes in plant type and unit size: Muara Karang open cycle gas-fired power plant (400 MW) to Muara Karang combined cycle gas-fired power plant (450 MW) and the Grati open cycle gas-fired power plant (300 MW) to Grati combined cycle gas-fired power plant (450 MW), as combined cycle gas-fired power plants are more efficient and are able to operate on a daily start-stop basis as a peaker plant, (ii) Capacity of Java-1 and Java-2 combined cycle gas-fired power plants to increase from 750 MW to 800 MW, to keep abreast of the latest technology that is more efficient, (iii) Changes in location: Executive Summary Electricity Supply Business Plan

18 Location of Java-6 coal-fired power plant from Bojonegara to Karawang, (iv) Addition of new planned generating capa city: Java-7 coal-fired power plant (2x1,000 MW), (v) plants removed from the RUPTL: Semarang open cycle gas-fired power plant (150 MW) as the period of validity of the loan had expired and was not renewed, and Kamojang 6 geothermal plant (60 MW) in view of the results of the study of the PGE reservoir show that it is not possible to develop the Kamojang 6 geothermal power plant, but only to develop the Kamojang 5 geothermal power plant (30 MW). The locations of coal-fired power plants and combined cycle gas-fired power plants are subject to change in accordance with developments in project preparation, including the availability of gas supply. SRLYA BANTEN MTWAR ~ ~ PLTU PLTU 4x1.000 MW ~ 2x1.000 MW PRIOK MKRNG CLGON DKSBI IDRMYU KMBNG BKASI CBTUBRU BRAJA CWANG CBATU TMBUN GNDUL CIBNG DEPOK XBOGOR CRATA CSKAN PS SGLNG MDCAN PLTU 1x1.000 MW PLTU 2x660 MW JATENG IPP PLTU 2x1.000 MW TJATI B GRSIK BDSLN CGRLNG UJBRG TASIK PMLNG RWALO CLCAP IPP ADIPALA UNGAR SOLO PEDAN TANDES NGBNG SBSLN SBBRT GRATI KDIRI BANGIL PITON NEW ANTOSARI Legend: Existing Power Plant in 500 kv ~ Planned Power Plant in 500 kv Existing 500 kv SS Planned 500 kv SS Existing 500 kv EHV Planned 500 kv EHV Figure-10. Plans for Strengthening 500 kv Transmission in Java Bali The development of the 500 kv transmission in Java is generally intended to evacuate power from new and expansion power plants, to maintain both the static and dynamic N-1 security criterion,while the development of the 150 kv transmission is intended to maintain the N-1 security criterion and the transmission associated with the new 150 kv substation. The plans for development of the 500 kv transmissions in Java-Bali are shown in Figure-10. Considering the development of EHV transmission lines and HV transmission lines are often delayed due to licensing, ROW and social issues, as well as the urgent need for additional power, there is a need for PLN to take steps to increase transmission capacity soon. The development of EHV transmission line using the new route would take a long time, while the reconductoring of several sections of the 500 kv and 150 kv transmissions would take a shorter time. RUPTL Construction of the 500 kv transmission is intended to evacuate power from large-scale coal-fired power plants such as Adipala, Indramayu 4 and 5, Central Java, Java-1, Java-3, Java-4, Java-5, Java-6, Java-7, Java- Bali Crossing to transfer from Paiton to the load center in Bali, pumped storage hydropower Upper Cisokan and Matenggeng, as well as several other new plants. The 500 kv EHV transmission lines to undergo reconductoring are New Suralaya-Bojonegara-Balaraja (2018) and Old Suralaya-Balaraja-Gandul (2019). The new 500 kv transmission development plan for EHV transmission lines includes Tanjung Jati B-Pemalang- Indramayu - Cibatu, Balaraja - Kembangan - Duri Kosambi and Duri Kosambi - Muara Karang - Muara Tawar forming looping EHV transmission lines in North Jakarta, to strengthen and improve the reliability and flexibility of the system operation in Jakarta. A 500 kv HVDC transmission interconnection between Sumatera-Java will also be built, to distribute power from the mine mouth power plants in South Sumatera to the load centers in Java. 12 Executive Summary Electricity Supply Business Plan

19 PLTU LONTAR 3 x 300 MW TNAGA T E L U K J A K A R T A MKRNG TNAGA II KAPUK SPTAN PRIOK PLTU 4x1.000 MW PLNDOB MTWAR PLNDOA SPTAN III MKRNG ANCOL MKRNG III SPTAN II TGBRU II GNSRI SOETA ANGKE MGBSR II KMYRN KDSPI II PLPNG PSKMS JGC MRNDA TGBRU DMGOT HRPDH GRGOL KTPNG MGBSR TGRNG III KMYRN II CKRNG KLPGD RWBUAYA GBLMA TTNGI KDSPI MAXIM DRKSB GMBRU PGLNG II CBTUBR New KBSRH PKRNG GPOLA JTAKE Old BKASIUTRA CKNDE CKUPA TGRNG GRGOL II BDKMY DKTAS PGSAN SMBRT II PGLNG CLDK DKTASII GBLMA-2 BKASI II SPINML PLMAS PGDNG SKTNI KBJRK KARET MGRAICIPNG II BKASI BLRJA LIPP NewOld STBDI CIPNG KESA KSBRU O BNTEN NSYAN II SMBRT PGDGSTEEL LIPP ALMSTRA AGP II O II KMBNG LAUTS SNYAN AGP PCRAN2 PNCOL II FAJAR MLNIUM NSYAN TMRSD PDKLP DNYSA II Old CITRA PNCOL PWRSTEL MPANG DNYSA TGRSA CIKRNG BKSPWR HVDC CSW CSW II CWANG JTWRG TMBUN II LEGOK LKONG DRTGA JBEKA MRT TMBUN TMBUN PTKNG CWANGBR RJPKSI TGRSA II PDNDH II CSW III MNTUR LKONG II BNTRO II Psmede GDMKR CBATU CSENG KMANG LKONG PDNDH LKONG IIIBSD RGNAN BNTRO SRPNG BNTRO III GDRIA JTNGN GNDUL DPBRU JTNGNII CBBUR LEGEND : EXISTING 500 KV SS NEW 500 KV SS EXISTING 150 KV SS NEW 150 KV EXISTING NEW 150 KV SS FOR HV CUSTOMER EXISTING 70 KV SS CLGON DEPOK III BGORX CMGIS II CMGIS ASPEK CIBNG CIBNG II SCBNG SNTUL ITP CLGSI II JONGGOL CLGSI SGLNG CBATU TSMYA KDBDK BGBRU Figure-11. Plans for Strengthening of 500 kv Transmission in Jakarta To strengthen the system supply in Jakarta, construction has been planned for a EHV transmission line for the Duri Kosambi - Muara Karang - Priok - Muara Tawar section (looping EHV transmission line for north Jakarta route) as shown in Figure-11. The new EHV transmission line will also improve the reliability and flexibility of operation of the power systems in Jakarta and Bekasi. Figure-12. Projected composition of Electricity Production by fuel type in Java - Bali Executive Summary Electricity Supply Business Plan

20 Figure-12 shows that coal will be the main primary energy used, representing 70% of all production in 2022, followed by natural gas (including LNG) 17%, geothermal 9%, hydro 3% and fuel oil in very small proportions (1%). The proportion of fuel oil utilized in 2013 was about 3.5% but will decrease to very low levels by This decrease can be achieved if alternative fuels are available at levels as planned and fullest efforts are made to reduce electricity production costs. Contribution of natural gas will decline from 21% in 2013 to 10% in 2022 due to no certain additional gas supply expected to materialize. The contribution of LNG is relatively stable at around 6-7% until the year 2022, to operate peaking power plants and must run plants. Contribution by geothermal energy was only 5% in 2013 and will rise to 9% by Table-3 shows the gas supply based on current contracts. From Table-3 it shows that the supply of gas for the next 10 years is likely to decline, especially for Priok, Muara Karang, Muara Tawar, Gresik and Grati. Tambak Lorok and Pesanggaran (Bali) have been using fuel oil to-date and they are expected to obtain gas supplies from new sources. Demand for gas for power generation in Java-Bali is shown in Table-4. In the coming years, there will be additional planned gas-fired generating capacity as follows: Pesanggaran gas engine power plant 200 MW (2015), Grati combined cycle gas-fired peaker plant 450 MW (201516), Muara Karang combined cycle gas-fired peaker plant 450 MW (2016), Java-1 combined cycle gas-fired power plant (in Gresik) 800 MW (2017), which is expected to receive gas supply from the Cepu block; as well as Java-2 combined cycle gasfired power plant (alternative in Grati) 800 MW (2018), which has yet to establish its gas supply. Table-3. Gas Supply Situation for Java - Bali Power Generation No Power Plant Supplier bbtud RUPTL 1 Muara Karang and PHE ONWJ (GSA) Priok PGN - Priok (GSA-IP) FSRU PT NR (GSA) Total Muara Tawar PERTAMINA - P Tengah (GSA) PGN (GSA) MEDCO Ex-KeramasanSCS Field MEDCO LematangSinga Field 35 SWAP JOB Jambi Merang Additional from PHE (Potential) Swap Program FSRU West Java (Potential) Swap Premier (Potential) 5 3 Total Cilegon CNOOC (GSA) PGN (GSA) Total Tambaklorok PCML SPP (GSA-IP) Total Gresik PHE WMO ex-kodeco Hess (GSA) Kangean Energy Indonesia Media Karya Sentosa 11 Wali Nusa Energi Petronas-Bukit Tua (Potential) Santos Peluang Field (Contract Process) ExxonPertamina Cepu Block (Potential) Total Grati Santos Oyong (GSA-IP) Santos Wortel (GSA-IP) Sampang Mandiri Perkasa (GSA-IP) Pasuruan Migas (GSA-IP) Total Pesanggaran Sengkang LNG (Potential) Total Total Gas Supply for Power Plants in Jawa - Bali 1,071 1,118 1,101 1,019 1, Executive Summary Electricity Supply Business Plan

21 From Table-4, there could be a shortage of gas supply to some power plants due to the decline in the supply of gas for the next 10 years. To prevent this, there must be a follow-up to extend existing gas contracts and to seek new sources of gas. Table-4. Gas Balance for Power Plants in Java - Bali bbtud No. Power Plant MW Muara Karang 1 ) 2,077 Gas Demand Tanjung Priok 1,923 Gas Demand Gas Supply LNG Supply Surplus-Deficit Muara Tawar 2 ) 2,662 Gas Demand Gas Supply Surplus-Deficit Gresik 3 ) 2,979 Gas Demand Gas Supply Surplus-Deficit Tambak Lorok 1,234 Gas Demand Gas Supply Surplus-Deficit Grati 4 ) 2,014 Gas Demand Gas Supply Surplus-Deficit Cilegon 740 Gas Demand Gas Supply Surplus-Deficit 8 Pesanggaran 250 Gas Demand Gas Supply Surplus-Deficit Total Jawa-Bali Gas Demand 1,012 1,069 1,108 1,168 1,116 1,176 1,133 1,107 1,123 1,156 Gas Supply - 1,012 1,069 1, SurplusDeficit Note: 1) Includes Muara Karang combined cycle gas-fired power plant 450 MW 2) Includes Muara Tawar Add-on Blocks 2,3,4 combined cycle gas-fired power plant 650 MW 3) Includes Java-1 combined cycle gas-fired power plant 800 MW 4) Includes Java-2 combined cycle gas-fired power plant 800 MW SUMATERA SYSTEM DEVELOPMENT PLAN Table-5 shows the power supply and demand balance of the Sumatera power system. The power system in Sumatera is planned to achieve a reserve margin of 65% by 2022, which is lower than the reserve margin in the RUPTL , which had planned to achieve a reserve margin of 70% in Potential burden on Sumatera could be higher than planned. With reserve margins that are high enough, it is possible to accommodate such potential high loads. However, if the reserve margin is lower than 40 %, it would be necessary to control the load Executive Summary Electricity Supply Business Plan

22 The new power plant development plan on Sumatera system includes the following: Sumut-1 coal-fired power plant 300 MW (COD 2017); Sumut-2 coal-fired power plant 2x300 MW ( ); Sumbagsel-1mine mouth coalfired power plant 2x150 MW ( ); Bengkulu coal-fired power plant 2x100 MW (2019); Sumbagut-2 gas turbineengine power plant 250 MW peaker (2018) Sumbagut-3 gas turbineengine power plant 250 MW (2018); Sumbagut-4 gas turbineengine power plant 250 MW (2018); and Meurebo-2 hydropower 59 MW (2020). Table-5. Power Generation Development Plan in Sumatera Projects Unit Demand Energy Production GWh 28,935 31,603 34,918 38,562 42,599 47,047 52,981 57,456 63,539 70,312 Load Factor % Gross Peak Load MW 4,742 5,227 5,770 6,316 6,912 7,561 8,288 9,288 9,916 10,961 Supply Installed Capacity MW 5,722 5,607 5,492 4,832 4,542 4,384 4,384 4,384 4,384 4,384 Net Capacity MW 4,711 4,672 4,542 4,019 3,849 3,742 3,742 3,742 3,742 3,742 PLN MW 3,126 3,093 3,093 2,960 2,795 2,773 2,773 2,773 2,773 2,773 Rental MW IPP MW Retired & Mothballed (PLN) MW Additional Capacity PLN ON-GOING & COMMITTED Tarahan (FTP1) PP 200 Meulaboh (Nagan Raya) #1,2 (FTP1) PP Teluk Sirih #1,2 (FTP1) PP Pangkalan Susu #1,2 (FTP1) PP Riau (FTP1 Amandment) PP 220 Pangkalan Susu #3,4 (FTP2) PP Sungai Gelam (CNGPeaker) GEPP 92 Duri GEPP 112 Arun (Peaker) GTGEPP 200 Batanghari CCPP 30 Keramasan CCPP 80 Hululais (FTP2) GeoPP Sungai Penuh (FTP2) GeoPP Peusangan 1-2 HEPP 88 Asahan III (FTP2) HEPP 174 Masang-2 (FTP2) HEPP 55 RENTAL Dumai PP 240 Lampung (Sribawono + Sutami) GTGEPP Payo Selincah GTGEPP Tanjung Jabung Timur GTGEPP ADDITIONAL RENTAL (DieselGTGEPP) Sumbagut MW Sumbagselteng MW RUPTL IPP ON-GOING & COMMITTED Banjarsari PP 230 Keban Agung PP 225 Sumsel - 5 PP Sumsel - 7 PP Riau Kemitraan (PLN-TNB-PTBA) PP 1,200 Jambi PP Gunung Megang, ST Cycle CCPP 30 Lumut Balai (FTP2) GeoPP Ulubelu #3,4 (FTP2) GeoPP Sarulla I (FTP2) GeoPP Muara Laboh (FTP2) GeoPP Rantau Dadap (FTP2) GeoPP Sorik Marapi (FTP2) GeoPP Seulawah Agam (FTP2) GeoPP Rajabasa (FTP2) GeoPP Suoh Sekincau (FTP2) GeoPP Sipoholon Ria-Ria (FTP2) GeoPP Executive Summary Electricity Supply Business Plan

23 Table-5. Power Generation Development Plan in Sumatera continued Projects Unit Wai Ratai (FTP2) GeoPP 55 Sarulla II (FTP2) GeoPP 110 Simbolon Samosir (FTP2) GeoPP 110 Danau Ranau (FTP2) GeoPP 110 Bonjol (FTP2) GeoPP 165 Scattered Sumut MHPP MHPP Wampu (FTP2) HEPP 45 Semangka (FTP2) HEPP 56 Hasang (FTP2) HEPP 40 Merangin HEPP 350 Peusangan-4 (FTP2) HEPP 83 Batang Toru (Tapsel) HEPP 510 PLANNED ADDITIONAL CAPACITY Meulaboh (Nagan Raya) #3,4 PP Sumut-1 PP 300 Sumut-2 PP Sumsel-1 MT PP Sumsel-6 MT PP Sumbagsel-1 MT PP Bengkulu PP 200 Banyuasin PP 230 Aceh GTPP 25 Riau CCPP 50 Lampung Peaker GTGEPP 200 Jambi Peaker GTGEPP 100 Riau Peaker GTGEPP 200 Sumbagut-1 Peaker CCPPMGU 250 Sumbagut-2 Peaker (Arun) CCPPMGU 250 Sumbagut-3 Peaker (Medan) CCPPMGU 250 Sumbagut-4 Peaker (Medan) CCPPMGU 250 G, Talang GeoPP 20 Kepahiyang GeoPP 220 Simonggo-2 HEPP 90 Meureubo-2 HEPP 59 Ketahun-3 HEPP 61 Kumbih-3 HEPP 42 Sibundong-4 HEPP 32 Total Additional Capacity HEPP 667 1, ,699 1,275 1,887 1,330 1,840 Total Installed Capacity MW 6,389 8,075 8,950 9,956 10,485 12,471 13,701 15,588 16,918 18,758 Total Net Capacity MW 5,378 7,140 8,000 9,143 9,732 11,829 13,059 14,946 16,276 18,116 MW The development of transmission lines in Sumatera will form the transmission backbone 500 kv interconnection system that unites the corridors of Sumatera in the east. The centers of large-scale generation and load centers in Sumatera will be connected to this 500 kv transmission system. This transmission also will transfer electricity from power plants in the areas with adequate cheap primary energy source (Sumbagsel and Riau) to areas which lack a primary energy source (Sumbagut). The addition of 500 kv transmission is also developed in South Sumatera as a feeder supplier of electricity from the mine mouth coal fired power plant to the HVDC transmission converter station which will connect the islands of Sumatera and Java. The development plan in RUPTL for the transmission system will see significant change to the network topology with the establishment of the 275 kv and 500 kv interconnection system in Sumatera. The development is also done to meet the growing demand in the form of additional transformer capacity. Development to improve the reliability and debottlenecking which is also planned in some systems, such as the plan to build a second circuit and reconductoring several sections in the Sumbagsel and Sumbagut transmission systems.the plan for a 275 kv interconnection in Sumatera is programmed to be implemented entirely in In addition some substations and 150 kv transmission are being constructed to take over the load of diesel generators to interconnected systems Executive Summary Electricity Supply Business Plan

24 The development plan of the power system in Sumatera is shown in Figure No GI 275 kv COD 1 Sigli Meulaboh Lhokseumawe Sarulla Payakumbuh Kiliranjao Muara Bungo Bangko Lubuk Linggau Lahat Gumawang Muara Enim Betung New Aur Duri New G. Sak P. Sidempuan Simangkok Galang Binjai Pangkalan Susu Ulee Kareeng Rantau Prapat Lumut Balai Sungai Lilin Lampung No GI 500 kv COD 12 Muara Enim New Aur Duri Rengat New G. Sak Rantau Prapat Medan (S.Rotan) Kuala Tanjung Figure-13. Development Plan of Transmission System in Sumatera The projected fuel mix for electricity production in Sumatera in 2022 would be 49% coal, 17% natural gas, 11% hydro, 1% oil and 22% geothermal as shown in Figure ,000 70,000 60,000 50,000 GWh 40,000 30,000 RUPTL 20,000 10, Import Biomass HSD MFO LNG Gas Coal Geothermal Hydro Figure-14. Projected Composition of Electricity Production by Fuel Type in Sumatera 18 Executive Summary Electricity Supply Business Plan

25 Fuel requirements in Sumatera from 2013 to 2022 are presented in Table-6, and plans for the supply to gas power plant in Sumatera are presented in Table-7. Table-6. Fuel Requirement in Sumatera No. Fuel Type HSD ( x 10^3 kl ) 2, , , MFO ( x 10^3 kl ) Gas (bcf) LNG (bcf) Coal (10^6 ton) Biomass (10^3 ton) Table-7. Gas Supply for Power Plants in Sumatera No Power Plant Supplier Aceh Timur Medco Blok A Belawan, P. Pasir, Kambuna Sumbagut-1 dan FSRU LNG Tangguh Arun PEP Benggala Teluk Lembu Kalila Bentu PLTMG Rawa Minyak Bengkalis (Potensi)* Petroselat Rawa Minyak PLTG sewa Jabung Petro China (Potensi) Sungai Gelam PEP - TAC (Own Operation) Payo Selincah, PEP - TAC Sungai Gelam Simpang Tuan Perusda Jambi Payo Selincah, Energasindo Batanghari Jambi Merang Jakabaring (CNG) PDPDE Sumsel Indralaya Medco E&P Indonesia Talang Duku PGN Borang Medco E&P Indonesia Keramasan Medco E&P Indonesia Gunung Megang Pertamina EP Medco E & P Indonesia Borang Pertamina EP (Asri Gita) PLTMG Duri, Duri Relokasi, Riau Jambi Merang Peaker 16 PLTGU Duri Jambi Merang Rengat Jambi Merang Lampung Peaker FSRU Lampung (Potensi) Lampung Sewa PGN (Potensi) Total WEST KALIMANTAN SYSTEM DEVELOPMENT PLAN The current installed capacity in West Kalimantan is 335 MW (including rental capacity) which all plants are using fuel oil, so operating costs are very high. Additional generation capacity in West Kalimantan is still in the planning stage, with the exception of Fast Track Phase 1 Parit Baru (2x50 MW) and Kura-kura (2x25 MW) coal-fired power plants are under construction and expected to be operational by PLN and Sarawak Electricity Company (SESCO) have signed a Power Exchange agreement (PEA) which sets out plans for PLN to purchase electricity to supply West Kalimantan from Sarawak for 50 MW flat (as baseload) and at peak load PLN can purchase up to 230 MW, starting from early 2015 until In the long term Executive Summary Electricity Supply Business Plan

26 it is possible that such purchase of electricity from Sarawak will only be during peak loads. This will enable PLN to defer the need for peaking plants which run on expensive fuel. However, to avoid excessive dependence on electricity supply from Sarawak, the construction of a gas turbineengine power plant of 100 MW in 2017 has been planned. The power supply and demand balance of the West Kalimantan system (Table-8) indicates that the reserve margin will reach 51% by This situation is still acceptable considering that coal-fired power plant projects in West Kalimantan are at a risk of delays for various reasons andthere is no take-or-pay clause at peak periods in the Sarawak interconnection. Table-8. Power Generation Development Plan in West Kalimantan Projects Demand Energy Production GWh 1,371 1,632 1,855 2,373 2,907 3,302 3,675 4,088 4,544 5,040 Load Factor % Peak Load MW Supply Installed Capacity MW Net Capacity MW PLN MW GTPP-HSD PLN (Siantan) MW Diesel-MFO PLN (Sei Raya & Siantan) Diesel-MFO PLN (Sei Wie & Sudirman) MW MW Interconnected isolated system MW Rental MW Retired & Mothballed (PLN) MW Additional Capacity PLN ON-GOING AND COMMITTED Pantai Kura-Kura (FTP1) PP 55 Parit Baru (FTP1) PP 100 Parit Baru (FTP2) PP 100 IPP ON-GOING AND COMMITTED PLANNED ADDITIONAL CAPACITY Kalbar - 1 PP Kalbar - 2 (new proposal) PP Peaker GTGEPP 100 Nanga Pinoh*) HEPP 98 Pade Kembayung HEPP 30 Power Purchase dgn SESCo 275 KV 180 (Peaking) Power Purchase dgn SESCo 275 KV (Baseload) RUPTL Total Additional Capacity MW Total Installed Capacity MW ,074 1,274 1,402 Total Net Capacity MW ,061 1,261 1,389 Interconnection with Sesco can be extended, but only for peaking, after Kalbar-2 coal fired power plant in operation 20 Executive Summary Electricity Supply Business Plan

27 Development plans for the transmission network in West Kalimantan up to the year 2022 amount to 2,812 km, which include: construction of a new 150 kv transmission line associated with the Fast Track coal-fired plants, coal-fired IPP and hydro projects. Development of the existing 150 kv transmission line to scattered locations in West Kalimantan systems is also planned in order to meet the reliability criteria (N-1) and to overcome bottlenecks in delivery, improve voltage and operational flexibility. Construction of 275 kv West Kalimantan - Sarawak transmission interconnection will reap economic benefits of the energy exchange when there is a marginal cost difference between the two systems. The development of the interconnection is also useful as a contingency in the event that the construction of new plants is delayed. West Kalimantan system development plan is shown in Figure-15. ARUK BIAWAK SARAWAK (MALAYSIA) SAMBAS 2013 SERIKIN KUCHING PLTU P. Baru (FTP2) 2x50 MW 2016 PLTU P. Kura-Kura (FTP1) 2x27,5 MW 2015 SINGKAWANG U U JAGOI BABANG BENGKAYANG 2014 Ke GITET Matang TEBEDU ENTIKONG PLTA Pade Kembayung 3x10 MW 2022 PLTU Sintang 3x7 MW 2015 BATU KAYA BADAU PUTUSSIBAU 2020 KALIMANTAN TIMUR PLTU P. Baru (FTP1) 2x50 MW 2015 PLTG MG Peaker 100 MW 2017 MEMPAWAH PARIT BARU U G KOTA BARU 2015 SIANTAN NGABANG km SEI RAYA U A TAYAN 2013 GB U SANGGAU 2016 SEKADAU 2016 PLTU Sanggau 2x7 MW U SINTANG 2016 A NANGA PINOH 2018 PLTA Nanga Pinoh 2x49 MW 2022 KALIMANTAN TENGAH PLTU Kalbar -1 2x100 MW PLTU Kalbar -2 2x200 MW GI. K0TA BARU 2019 PLTGB Sewa Tayan 6 MW 2013 SUKADANA 2017 SANDAI 2017 ke Kalteng PLTU Ketapang 2x10 MW 2016 U KETAPANG 2017 PT PLN (Persero ) PERENCANAAN SISTEM PETA JARINGAN PROPINSI KALIMANTAN BARAT PLTU IPP Ketapang 2x6 MW km KENDAWANGAN 2020 GI 500 kv Existing Rencana GI 275 kv Existing Rencana GI 150 kv Existing Rencana GI 70 kv Existing Rencana GI kv Existing Rencana GI kv Existing Rencana GI kv Existing Rencana GI kv Existing Rencana TL 70 kv Existing Rencana TL 150 kv Existing Rencana TL 275 kv Existing Rencana TL 500 kv Existing Rencana U U PLTU Existing Rencana G G PLTG Existing Rencana P P PLTP Existing Rencana A A PLTA Existing Rencana GU GU PLT GU Existing Rencana MG MG PLTMG Existing Rencana M M PLT M Existing Rencana D D PLT D Existing Rencana Kit Existing Kit Rencana Edit Desember KALIMANTAN SELATAN Figure-15. Transmission System Development Plan in West Kalimantan The fuel mix for electricity production in West Kalimantan is presented in Figure-16. The role of each primary energy can be explained as follows: (i) in 2013, because of the lack of new power generation capacity besides fuel oil, electricity production using fuel oil reached 1,498 GWh. In line with the operation of coal-fired power plant and imports of electricity from Sarawak, the use of fuel oil as the primary fuel in the West Kalimantan power system can be further reduced; (ii) Hydro power resources are found in the Nanga Pinoh area, so a 98 MW Nanga Pinoh hydropower plant has been planned, to be operational by 2022; (iii) There are also plans to ship LNG from Batam to West Kalimantan, which will be used to supply peaker plants 100 MW with gas demands of 5 bbtud Executive Summary Electricity Supply Business Plan

28 GWh Import HSD MFO LNG Gas Coal Geothermal Hydro Figure-16. Projected composition of Power Generationby Fuel Type in West Kalimantan SOUTH, CENTRAL, NORTH AND EAST KALIMANTAN SYSTEM DEVELOPMENT PLAN The South-Central Kalimantan (Kalselteng) system and North - East Kalimantan (Kaltimra) system have suffered power supply shortages for many years. To improve the power shortage situation, PLN has introduced both short-term and long-term solutions. Short-term solutions involve rental of diesel engine generating units, while long-term solutions involve the planning and development of a number of coal fired power plants, gas fired power plants and hydroelectric power plants. In reality, however, many of these power generating projects have faced problems and as such, project completions have been delayed from the initial schedule. As a result, the additional power generated from the short-term solution (rental of diesel engine units) has not been able to sufficiently improve the power shortage situation, due to the rapid growth of demand for power. In addition, maintenance of existing power plant machinery could not be carried out as planned because these plants have to be operated continuously. Also, some potential customers with high power demand could not be served. Currently, the power generation capacity of PLN and IPP power plants, including rental diesel engine units and excess power, in the South, Central, North and East regions of Kalimantan (Kalseltengtimra) is 815 MW, with peak load at 847 MW, excluding the Asam-asam coal fired power plant units 3 and 4, which are expected to be operational in In addition, the portion of power generation plants operating on oil fuel in Kalseltengtimra is still high, hence the power generation cost remains high. RUPTL A large number of additional power plants have been planned in anticipation of project delays. This is reflected in the power balance of the Kalseltengtimra system, where the annual reserve margin is 33% to 53%, other than in 2015, when the reserve margin is only 22% of the net available capacity. Reserve margins are estimated to be highest in 2019 if all projects are completed on time. However, based on PLN s experience to date, the success rate of power generation projects is relatively low, particularly in Kalimantan. The steam turbine IPP project, which had been planned to be operational by , has been delayed by one year. PLN Muara JawaTeluk Balikpapan coal fired power plant (FTP1) is estimated to be delayed by one year, while Pulang Pisau coal fired power plant is estimated to be delayed by two years. From the above, it can be seen that the reserve margin is relatively high (up to 53%). This is intended to provide greater certainty to the people South Kalimantan, Central Kalimantan, East Kalimantan and North Kalimantan that the electricity supply in these regions will be adequate. 22 Executive Summary Electricity Supply Business Plan

29 During the period , additional 2,957 MW of new generation capacity from both PLN and IPP has been planned, including those already in the procurement process and under construction. The additional new generation capacity comprises of coal fired power plants (1,925 MW), gas turbineengine peaker plants (795 MW), hydroelectric plants (120 MW) and combined cycle gas turbine power plants (117 MW). Power gene ration development plan in Kalseltengtimra is shown in Table-9. Table-9. Power Generation Development Plan in Kalseltengtimra PROJECTS Kalselteng - Kaltim Interconnection 2016 Kalselteng-Kaltim-Kaltara Interconnection (2018) Demand Energy Production GWh 5,154 6,304 7,744 8,495 9,376 10,545 11,390 12,277 13,178 14,190 Load Factor % Peak Load MW 847 1,036 1,266 1,391 1,511 1,690 1,819 1,956 2,095 2,252 Supply Installed Capacity MW Net Capacity MW PLN IPP Retired & Mothballed Additional Capacity PLN On Going & Committed Pulang Pisau (FTP1) PP Asam Asam (FTP1) PP Bangkanai (FTP2) GTGECCPP Kaltim Peaking (APBN) GTPP Muara JawaTeluk Balikpapan (FTP1) PP Sampit PP IPP On Going & Committed Senipah GTPP Embalut (Expansion) PP Senipah (ST) CCPP Planned Additional Capacity Kalsel Peaker 1 GTGECCPP Kalsel Peaker 2 GTGECCPP Kaltim Peaker 2 GTGECCPP Kaltim Peaker 3 GTGECCPP Kelai HEPP Kusan HEPP Kalsel (FTP2) PP Kalselteng 1 PP Kalselteng 2 PP Kalselteng 3 PP Kaltim (FTP2) PP Kaltim (Mine Mouth) PP Kaltim 3 PP Kaltim 4 PP Total Additional Capacity MW TOTAL INSTALLED CAPACITY MW 1,282 1,551 1,719 1,959 2,167 2,727 2,827 2,977 3,227 3,347 TOTAL NET CAPACITY MW 1,127 1,396 1,565 1,804 2,131 2,691 2,791 2,941 3,191 3,311 The development plan of the Kalseltengtimra 150 kv and 70 kv transmission system is intended to meet electricity demand growth and to connect isolated systems to the grid. The transmission system is also intended to support regional development to ensure availability of power supply, given the establishment of the North Kalimantan province, which will result in increasing electricity demand Executive Summary Electricity Supply Business Plan

30 The transmission development plan in Kalseltengtimra in Figure-17 and Figure-18 include: Construction of a new 150 kv transmission line related to accelerated coal fired power plants under the Fast Track 1 projects, as well as accelerated coal and gas fired power plants under the Fast Track 2 projects, coal-fired and open cycle gas-fired IPP projects, gas turbineengine peaker plants, and hydroelectric plants; Development of 150 kv transmission in dispersed locations to connect isolated electrical systems, to overcome bottlenecks in the electrical power distribution to meet reliability criteria (N-1), improve service voltage and increase operational flexibility; Construction of 150 kv transmission systems associated with development of industrial estates as directed in the MP3EI (Master Plan for Development of Economy and Industry) in East Kalimantan, i.e. from Sangatta to the Maloi industrial zone; 150 kv transmission projects which are required and expected to be operational in due course include: the section connecting Tanjung (South Kalimantan) Kuaro Petung Karangjoang (Kaltim) in 2016, to connect the Kalselteng and Kaltim systems; and the section connecting Bangkanai gas turbineengine plants MuaraTeweh Buntok Tanjung in 2014,to connect the Bangkanai gas turbine engine plants to the Kalselteng system. With the establishment of the North Kalimantan province, it is expected that the electricity demand in the next few years will grow higher, especially in big cities: Tanjung Selor (the province s capital) and Tana Tidung and Malinau (regency capital cities). The North Kalimantan Interconnection System in Kalseltengtim is a 150 kv transmission network connecting Muara Wahau Tanjung Redep Tanjung Selor and is expected to be ready in PT PLN (Persero) SS 500 kv Existing Plan SS 275 kv Existing Plan SS 150 kv Existing Plan SS 70 kv Existing Plan SS kv Existing Plan SS kv Existing Plan SS kv Existing Plan SS kv Existing Plan TL 70 kv Existing Plan TL 150 kv Existing Plan TL 275 kv Existing Plan TL 500 kv Existing Plan SYSTEM PLANNING SOUTH AND CENTRAL KALIMANTAN SYSTEM PP Existing Plan GT GT GTPP Existing Plan GEO GEOPP Existing Plan H H HEPP Existing Plan CC CC CCPP Existing Plan GE GE GEPP Existing Plan MH MH MHPP Existing Plan D D Diesel PP Existing Plan PP Existing PP Plan Edit November 2013 GEO ACSR 2x240 mm 2 96 km Puruk Cahu 2015 D 2013 Bangkanai GEPP 140 MW 2015 Bangkanai GTGE PP 2x70 MW ACSR 2x240 mm 2 GE 47 km xZebra 50 km to Melak SS (East Kalimantan) Sukamara Nangabulik Pangkalan Bun PP 2x7 MW Kalselteng 3 PP 2x50 MW 2018 Pangkalan Banteng PangkalanBun Kalselteng 1 PP 2x100 MW ACSR 1x240 mm km Sampit Sampit PP 2x25 MW 2016 Parenggean 2011 D Kuala Pambuang PP 2x3 MW Kuala Kurun ACSR 2x240 mm km ACSR 2x240 mm 2 65 km Kasongan Palangkaraya ACSR 2x240 mm 2 80 km Pulang Pisau PP 2x60 MW 2015 D D Selat New Palangkaraya Seberang Barito Trisakti Mantuil Asam-Asam PP (FTP 1) 2x65 MW 2013 Kalselteng 2 PP 200 MW 2017 D D Kayutangi Muara Teweh Buntok Kalsel PP (FTP 2) 2x100 MW ACSR 2x240 mm km ACSR 2x240 mm km Amuntai D ACSR 2x240 mm km Rantau Barikin ACSR 1x240 mm 2 69 km Tanjung H Batu Licin Ulin H Riam Kanan HEPP 3x10 MW 2011 Cempaka Bandara Satui ACSR 2x240 mm km Pelaihari D 2 to Kuaro SS (East Kalimantan) 2012 ACSR 2x240 mm km Kusan HEPP 65 MW 2022 Kotabaru Asam-Asam 1,2 PP 2x65 MW ACCC 460 mm 2 37 km RUPTL Figure-17. Transmission System Development Plan in South and Central Kalimantan 24 Executive Summary Electricity Supply Business Plan

31 BRUNEI DARUSSALAM SABAH (MALAYSIA) SARAWAK (MALAYSIA) Kelai HEPP 55 MW 2022 ACSR 2x240 mm 2 26 km Tidang Pale Malinau ACSR 2x240 mm km 2017 Tanjung Selor PP Tj. Selor 2x7 MW 2014 GE Tanjung Selor GEPP ACSR 2x240 mm 2 15 MW km Lati PP Tj. Redep 3x7 MW 2015 Tanjung Redep PP 2x7 MW 2014 H Talisayan ACSR 2x240 mm km WEST KALIMANTAN PT PLN (Persero) SS 500 kv Existing Plan SS 275 kv Existing Plan SS 150 kv Existing Plan SS 70 kv Existing Plan SS kv Existing Plan SS kv Existing Plan SS kv Existing Plan SS kv Existing Plan TL 70 kv Existing Plan TL 150 kv Existing Plan TL 275 kv Existing Plan TL 500 kv Existing Plan SYSTEM PLANNING CENTRAL KALIMANTAN NORTH AND EAST KALIMANTAN SYSTEM GT GEO H CC GE MH D PP Existing Plan GT GTPP Existing Plan GEO GEOPP Existing Plan H HEPP Existing Plan CC CCPP Existing Plan GE GEPP Existing Plan MH MHPP Existing Plan D Diesel PP Existing Plan PP Existing PP Plan Edit November 2013 Embalut (Expansion) PP 1x50 MW 2014 Melak to Bangkanai GTGE PP (Central ACSR 2x240 mm 2 Kalimantan) 100 km Komam To Tanjung SS (South Kalimantan) Kaltim 4 PP 100 MW 2018 Kuaro Muara Wahau Kota Bangun Sangatta Bontang Karangjoang Sepaku GT Kariangau CC ACSR 2x240 mm 2 G Manggarsari 155 km New Balikpapan Industri Grogot Petung Longikis ACSR 2x240 mm 2 47 km New Smd G GT Sambera Sambutan Maloi SOUTH KALIMANTAN ACSR 2x240 mm 2 80 km Sepaso Kaltim PP (FTP2) 2x100 MW Kaltim Peaking GTPP 2x50 MW 2014 Kaltim (Mine Mouth) PP 2x27.5 MW 2018 Kaltim 3 PP 2x150 MW Senipah GTPP 2x41 MW 2014 Senipah (ST) CCPP 35 MW 2017 Kaltim Peaker 3 GTGE PP 50 MW 2021 Kaltim Peaker 2 GTGECC PP 100 MW 2016 Muara JawaTeluk Balikpapan PP (FTP1) 2x110 MW 2014 Figure-18. Transmission System Development Plan in North and East Kalimantan CENTRAL SULAWESI SOUTH SULAWESI Demand for High Speed Diesel (HSD) and Marine Fuel Oil (MFO) in the Kalseltengtimra system is expected to trend downwards, from 598,000 kiloliters in 2013 to 69,000 kiloliters in 2022, while the use of coal will increase from 1.5 million tons in 2013 to 6.5 million tons in The volume of gas utilization in the form of CNG and LNG will also increase from 3 bcf in 2013 to 22 bcf in Electricity production from hydro-power will also increase from 106 GWh in 2013 to 580 GWh in Projected composition of power generation by fuel type in Kalseltengtimra is shown in Figure ,000 14,000 GWh 12,000 10,000 8,000 6,000 4,000 2, SolarHybrid HSD MFO LNG Gas Coal Geot Hydro Figure-19. Projected Composition of Power Generation by Fuel Type in Kalseltengtimra Executive Summary Electricity Supply Business Plan

32 NORTH SULAWESI SYSTEM DEVELOPMENT PLAN The planned additional new generating capacity in North Sulawesi is relatively large, as can be seen from the annual reserve margin, which lies between 34% and 58%. A high reserve margin of 58% has been planned due to uncertainty of completion of the Kotamobagu I and II geothermal power plants. In 2013 and 2014, the reserve margin is relatively low. This is mainly due to delays to several projects, namely the Sulut 1 coal-fired power plant, Minahasa combined cycle gas turbine or gas turbineengine peaker plant, Lahendong V and VI geothermal plants, which are behind the original schedule. The power generation plan for North Sulawesi is shown in Table-10. New power generation capacity planned during the period is 1,087 MW, consisting of coal fired power plants (675 MW), geothermal power plant (120MW), gas fired turbineengine peaker with gas storage (250 MW) and hydro-electric plants (44 MW). Table-10. Power Generation Development Plan in Northern Sulawesi RUPTL Projects Demand Sulut - Gorontalo - Tolitoli Interconnection (2016) Energy production GWh 1,777 2,000 2,182 2,536 2,787 3,075 3,391 3,740 4,119 4,539 Load Factor % Peak Load MW Supply Installed Capacity MW Net Capacity MW PLN 22.6 MW IPP 5.3 MW Rental MW Retired & Mothballed Additional Capacity Rental Amurang (2x25) Rental PP PP 50 PLN On Going & Committed Gorontalo (FTP1) PP 50 Sulut I (FTP1) PP IPP On Going & Committed Molotabu PP 20 - Gorontalo (Terkendala) PP 12*) PLANNED ADDITIONAL CAPACITY Tolitoli PP Sulut 3 PP 100 Sulbagut 1 PP Sulbagut 2 PP Sulbagut 3 PP 60 Poigar 2 HEPP 30 Sawangan HEPP 12 Minahasa Peaker GTGECCPP Gorontalo Peaker GTGECCPP 100 Kotamobagu 1, 2 (FTP2) GeoPP 40 Kotamobagu 3, 4 (FTP2) GeoPP 40 Lahendong 5 (FTP2) GeoPP - 20 Lahendong 6 (FTP2) GeoPP - 20 Total Additional Capacity MW TOTAL INSTALLED CAPACITY MW ,002 1,102 1,282 TOTAL NET CAPACITY MW ,075 1, Executive Summary Electricity Supply Business Plan

33 The projected composition of power generation by fuel type in North Sulawesi from 2013 to 2022 is shown in Figure-20. The role of oil for power generation in North Sulawesi in 2013 is remain high, at around 732 GWh (41%). From 2015, the use of oil for power generation is expected to be reduced and replaced by natural gas with the availability of combined cycle gas-firedgas-fired turbineengine peaker using LNGCNG gas and coal-fired power plants. Coal-fired power generation will increase from 278 GWh (16%) in 2013 to 2749 GWh (62%) in From 2016, power generated from coal will be higher than geothermal plants after most of the coal-fired power plant projects become operational. Power generated from geothermal plants will increase from 552 GWh (31%) in 2013 to 791 GWh (18%) in 2022, when Lahendong IV-V and Kotamobagu geothermal plants become operational. Oil consumption in North Sulawesi will continue to decline from 197,000 kiloliters in 2013 to 9,000 kiloliters in 2022, after the non-oil power plants become fully operational. The use of coal is expected to increase from 172,000 tons in 2012 to 1.73 million tons in 2022, or an increase of 10 times. LNG will be used from 2016 at 3 bcf and will increase to 4 bcf in LNG will be used to operate peaking power plants. The use of geothermal energy will continue to increase from 552 GWh in 2013 to 797 GWh in The increase in hydropower is relatively small since the potential is low - from 215 GWh in 2013 to 369 GWh in GWh HSD MFO LNG Gas Coal Geothermal Hydro Figure-20. Projected composition of Power Generation by Fuel Type in Northern Sulawesi SOUTH SULAWESI SYSTEM DEVELOPMENT PLAN The integration of the Sulbagsel system which comprises Central Sulawesi (Sulteng), West Sulawesi (Sulbar), South East Sulawesi (Sultra) and South Sulawesi (Sulsel), is planned to be completed in Presently, the Central Sulawesi system relies on supply from Tawaeli 2x15 MW coal-fired IPP, PLN and rental diesel engine plants. In 2014, additional supply will be obtained from Poso hydro power plant after the 150 kv transmission line between Poso hydro power and New Palu is in operation. The Sulteng and Sulbar systems will be interconnected with the Sulsel system through the Poso Palopo 275 kv transmission line and the Silae Pasangkayu 150 kv transmission line. With this interconnection, the use of coal-fired power plants on a larger scale can be implemented in Central Sulawesi. The Sulsel system receives sufficient supply of power from the Jeneponto coal-fired IPP, Barru coal-fired plant and Poso hydro power plant. In the Sultra system, the shortage of power has not been fully resolved due to the lack of reliability of Kendari 2x10 MW coal-fired power plant (Fast Track 1 Project), which still requires im Executive Summary Electricity Supply Business Plan

34 provement. To overcome these power shortages, short-term efforts are being made to improve the reliability of the Kendari coal-fired power plant and to accelerate the Wotu Malili Lasusa Kolaka Unaaha Kendari 150 kv transmission line project, which is currently under construction. In order to meet long term electricity needs over the period of , non-oil power plant projects with a total capacity of 3,639 MW in System Sulbagsel have been planned. These projects consist of hydro power mini-hydro power plants (1,392 MW), coal-fired power plants (1,475 MW), combined cycle gas-fired turbine engine plants (600MW) and geothermal power plants (95 MW). Within the plan includes the Karama 450 MW hydro power project in West Sulawesi. Karama is a hydro power project involving an unsolicited IPP procur ement process which will be carried out by the PPP scheme. The power generation development plan for Sulbagsel is shown in Table-11. Table-11. Power Generation Development Plan in South Sulawesi RUPTL Projects Sulsel interconnection with Palu (2014) and Sultra (2016) Demand Energy Production GWh 5,776 6,892 8,066 9,491 10,431 11,474 12,482 13,849 15,014 16,191 Load Factor % Gross Peak Load MW 1,042 1,241 1,451 1,690 1,842 2,013 2,186 2,426 2,626 2,830 Supply Installed Capacity 1,533 1,495 1,490 1,270 1, Net Capacity MW 1,396 1,366 1,361 1,141 1, PLN MW IPP MW Rental MW Retired & Mothballed Additional Capacity PLN On Going & Comitted Sulsel Barru #1 (FTP1) PP Nii TanasaKendari #2 (FTP1) PP Nii TanasaKendari (Expansion) PP Scattered MHPP MHPP IPP On Going & Committed Sengkang (GT 22) GTPP Sengkang (ST 28) CCPP Mamuju PP Tawaeli Expansion PP PLANNED ADDITIONAL CAPACITY Makassar Peaker GTGECCPP Punagaya (FTP2) PP Jeneponto 2 PP Kendari 3 PP Sulsel Barru 2 PP Sulsel 2 PP Palu 3 PP Sulsel 3Takalar PP Wajo GEPP Poso 2 HEPP Poko HEPP Konawe HEPP Watunohu HEPP Bakaru 2 HEPP Karama Baseload (Unsolicited) HEPP Karama Peaking (Unsolicited) HEPP Bonto Batu (FTP2) HEPP Malea (FTP2) HEPP Bora Pulu (FTP2) GeoPP MaranaMasaingi (FTP2) GeoPP Lainea GeoPP Scattered MHPP MHPP Total Additional Capacity MW TOTAL INSTALLED CAPACITY MW 1,713 1,703 1,744 2,143 2,401 2,846 3,156 3,615 4,213 4,574 TOTAL NET CAPACITY MW 1,576 1,575 1,615 2,015 2,274 2,771 3,081 3,540 4,138 4, Executive Summary Electricity Supply Business Plan

35 GEO GEO GEO GEO CC GE MH D GEO CC GE MH D GEO GEO GEO Apart from power distribution from the power supply center to the demand center, the transmission system also aims to build an interconnection among sub-systems, connect isolated electrical systems to the grid, overcome any bottlenecks, and to meet the N-1 reliability criteria. The transmission system development plan in Sulbagsel system (Figure-21) is as follows: 275 kv transmission line connecting Karama hydro power plant Mamuju Enrekang Sidrap Makassar (Daya Baru) Bantaeng, together with a kv EHV substation, to evacuate 450 MW of power from the Karama plant; 275 kv transmission line connecting Enrekang Palopo, in anticipation of the Poso II hydro power, to be developed simultaneously to improve system stability (especially Kendari), as well as gain operational flexibility; 275 kv EHV substation at Enrekang to evacuate power from Bonto Batu, Poko, Malea, as well as Bakaru II hydro power and channeled to the load center through the 275 kv Enrekang Sidrap Makassar Bantaeng transmission line. Minahasa Peaker GTGECC PP 150 MW Bitung Diesel PP 57 MW EAST KALIMANTAN Tolitoli PP 3x15 MW Tolitoli Leok Gorontalo PP (FTP1) 2x25 MW 2015 Sulbagut 1 PP 2x50 MW GORONTALO Sulut I PP (FTP1) 2x25 MW Buroko Sawangan HEPP 12 MW 2019 Lopana Diesel PP 10 MW Amurang PP 2x25 MW Amurang Rental PP 2x25 MW Sulbagut 2 PP 2x100 MW Bintauna Lolak Otam G Likupang Paniki Teling Bitung Ranomut D Tasik Ria H Kema Sawangan Tomohon Tonsealama D Kawangkoan Lopana Sulut 3 PP 2x50 MW H Lahendong I&II GeoPP 2x20 MW Bangkir Tambu Moutong Isimu Marisa Tilamuta G Telaga Diesel PP 24 MW Gorontalo Peaker GTGECC PP 100 MW 2017 Molotabu PP 2x10 MW 2013 Gorontalo Energy PP 2x6 MW 2014 DBotupingge NORTH SULAWESI Molibagu Lahendong III&IV GeoPP 2x20 MW Lahendong V&VI GeoPP 2x20 MW Poigar 2 HEPP 32 MW 2019 Kotamobagu I GeoPP 2x20 MW 2022 Kotamobagu II GeoPP 2x20 MW 2022 Sulbagut 3 PP 2x30 MW 2018 Palu 3 PP 2x50 MW Silae Diesel PP Silae 45 MW D Talise Tawaeli Expansion PP 2x15 MW MaranaMasaingi (FTP2) GeoPP 20 MW Borapulu (FTP2) GeoPP 55 MW Ampana Ampana PP 2x3 MW 2016 Bunta Luwuk PP 2x10 MW 2016 Palu Baru Luwuk Poso Toili Pasangkayu CENTRAL SULAWESI GE Luwuk Peaker GEPP 2x10 MW WEST SULAWESI Poso HEPP 3x65 MW Poso 2 HEPP 2x66 MW H H Tentena Kolonedale Mamuju (FTP2) HEPP 2x25 MW Topoyo Karama (Unsolicited) HEPP 450 MW Mamuju Baru H Mamuju Malea HEPP 2x45 MW 2017 Bakaru II HEPP 2x63 MW 2020 Wotu Malili Bungku to to Barru SS Sidrap SS Pangkep Tonasa Majene Poko HEPP 2x117 MW Bakaru 1 HEPP 2x63 MW Sulsel Barru PP 2x50 MW Sulsel Barru 2 PP 2x50 MW Polman Pinrang Pare D Barru Pangkep Tello D G Sungguminasa H H H Bakaru H Makale Enrekang Tonasa Maros Bosowa Daya Baru Jeneponto Tallasa Sulsel 2 PP 2x200 MW Punagaya Sulsel-3Takalar PP 2x100 MW 2022 Punagaya PP (FTP2) 2x100 MW 2016 Jeneponto PP 2x100 MW Jeneponto 2 PP 2x100 MW 2016 H Sidrap Sengkang GT CC GE Soppeng Palopo Bonto Batu HEPP 2x50 MW 2017 Sinjai Siwa SOUTH SULAWESI Bone Kajuara Bantaeng Bulukumba Bantaeng Smelter Lasusua Sengkang GTPP (GT 22) 60 MW 2013 Sengkang CCPP (ST 28) 60 MW 2013 Wajo GEPP 20 MW 2015 H SOUTH EAST SULAWESI Wotunohu HEPP 15 MW 2021 Kolaka Konawe HEPP 2x25 MW 2021 H Unaaha Kasipute Andolo Bau-Bau PP 2x10 MW Bau-Bau 2 PP 2x10 MW Kendari P Bau-Bau KendariNii Tanasa PP 2x10 MW Kendari (Expansion) PP 1x10 MW Kendari 3 PP 2x50 MW 2018 Laenia GeoPP 2x10 MW Raha Bau-Bau PP 2x7 MW Makassar Peaker GTGECC PP 300 MW MW MW-2018 Raha (FTP2) PP 2x3 MW 2016 Raha 2 PP 2x3 MW 2018 Tello GTPP 123 MW Wangi-Wangi PP 2x3 MW PT PLN (Persero) Maros Mandai Bosowa G Tallo G Daya Kima Lama Bontoala Daya Baru Tello Panakukang Tanjung Bunga Sungguminasa to Takalar PP SS 500 kv Existing Plan SS 275 kv Existing Plan SS 150 kv Existing Plan SS 70 kv Existing Plan SS kv Existing Plan SS kv Existing Plan SS kv Existing Plan SS kv Existing Plan TL 70 kv Existing Plan TL 150 kv Existing Plan TL 275 kv Existing Plan TL 500 kv Existing Plan Figure-21. Transmission System Development Plan for Sulawesi to Tallasa SS SYSTEM PLANNING SULAWESI SYSTEM PP Existing Plan GT GT GTPP Existing Plan GEOPP Existing Plan H H HEPP Existing Plan CCPP Existing Plan GEPP Existing Plan MHPP Existing Plan Diesel PP Existing Plan PP Existing PP Plan Edit December Executive Summary Electricity Supply Business Plan

36 Development of the 150 kv transmission line associated with coal-fired power plants, hydro power plants, gas turbineengine plants and interconnection among sub-systems will be carried out as part of the establishment of the Sulbagsel integrated system. The 150 kv transmission line extending to scattered locations is intended to overcome the transmission bottleneck, improve service voltage and operational flexibility, and meet the reliability criteria (N-1). The development of the transmission grid throughout Sulawesi for the period covers 7,751 kms and requires investments of US$1.082 billion. Projected power generation in Sulbagsel from 2013 to 2022 is shown in Figure-22. Power generation from oil in 2013 is expected to remain high, at 1,250 GWh (22%). However, beginning from 2018, power generated from oil will be replaced by power generated from natural gas in the form of LNG when the Makassar gas turbineengine peaker plant and coal fired power plant become operational. Power generated from gas fired power plants will increase nominally but decrease in terms of percentage, i.e. from 1,693 GWh (33%) in 2013 to 2,902 GWH (18%) in This is due to additional capacity from gas fired power plants (Sengkang combined cycle gas-fired plant) owned by the private sector and peaker power plants running on LNG. Power generated from coal fired power plants will increase from 1,706 GWh (30%) in 2013 to 9,160 GWh (57%) in Power generated by hydropower will increase from 1,127 GWh (20%) in 2013 to 3,650 GWh (23%) in 2022 when several hydropower projects become operational, namely Bonto Batu, Malea, Karama, Bakaru II, Poko, Poso II, Konawe and Watunohu. Oil consumption in the Sulbagsel system is expected to decrease from 297,000 kiloliters in 2013 to 57,000 kiloliters in 2022 after non-bbm plants become operational. The use of coal will continue to increase from 1.06 million tons in 2013 to 5.6 million tons in 2022, or an increase of 5 times. The volume of natural gas usage, including LNG, will also continue to rise from 13 bcf in 2013 to 24 bcf in LNG will only be used for operating peaking power plants. Production from geothermal plants amounting to 479 GWh will commence in The use of hydropower will increase sharply given the construction of many new hydro power plants, increasing from 1,127 GWh in 2013 to 3,650 GWh in 2022, or an increase of 3 times. 16,000 14,000 12,000 10,000 GWh 8,000 6,000 4,000 RUPTL 2, SolarHybrid HSD MFO LNG Gas Coal Geothermal Hydro Figure-22. Projected Composition of Power Generation by Fuel Type in Sulbagsel 30 Executive Summary Electricity Supply Business Plan

37 Meanwhile, the gas supply for power plant in East Indonesia power system can be seen in Table-12. Table-12. Gas Supply for Power Plant in Eastern Indonesia No Power plant Gas Supplier Sei Raya LNG PLN Batam (Plant) Pontianak Peaker LNG PLN Batam (Plant) Bangkanai Salamander Kalsel Peaker Salamander (Potential) Bontang Salamander Lapangan Tutung (Potential) Bontang Total Bontang Tanjung Batu TAC Semco Sambera VICO (Potential) Kaltim Peaker JOB Simenggaris (Potential) Nunukan Pertamina EP TAC Sembakung Nunukan 2 Medco South Sebuku Bengara (Potential) Tarakan GSA Pertamina EP Tarakan Manhattan KI Tanjung Selor Perusda Nusa Serambi Persada Senipah Total Senipah Minahasa Peaker LNG Sengkang Gorontalo Peaker Donggi (Potential) Morowali Tiaka (Potential) Sengkang Energy Equity Epic (Sengkang) Makassar Peaker LNG Sengkang Lombok Peaker Marine CNG dari Gresik KTI Scattered LNG Sengkang (Potential) Perusda Salawati (Potential) Sorong Petrochina (plant) BP Berau (Potential) Total DEVELOPMENT PLAN FOR NEW AND RENEWABLE ENERGY PLN has prepared a development plan for New and Renewable Energy (EBT) as shown in Table -13. The development plan comprises of 1) Mini hydro power plants: PLN encourages the development of mini-hydro plants by the private sector to meet the local demand and to be distributed to the PLN grid 2) Wind turbine generating plants: As the potential for wind power in Indonesia is limited, the development of wind turbine generating plants will be limited to areas with wind power potential 3) Biomass: PLN intends to build biomass power plants if PLN has control over the biomass supply. PLN cooperating with several local government for biomass industry pioneer 4) Marine energy: While the potential of marine energy is estimated to be large, the technology and economics of marine power plant development are still unknown, hence PLN will conduct small scale pilot tests as research and development projects 5) Biofuel: Depending on the readiness of the biofuel market, PLN is prepared to utilize biofuel if it is available 6) Solar power plants: PLN will develop solar plants in 1,000 locationsislands, especially in outlying and isolated areas to improve the electrification ratios Executive Summary Electricity Supply Business Plan

38 Development of Solar Power Plants Taking into account the wide geographical distribution of the population and difficulties in reaching remote areas, PLN plans to build solar power plants as follows: centralizedcommunal solar power plants (independent or hybrid operating mode); small scale and dispersed solar home systems (solar panel + LED lamps with battery), limited to provinces where application of renewable energy is still low and in areas where there will be no conventional electricity available within 5 years. The development of these solar power plants is intended to electrify remote areas as soon as possible, avoid utilization of oil if they are served by diesel engine generating units, and to reduce the generation costs in certain areas where transportation of oil is very expensive, e.g. around the mountain peaks of Jayawijaya Papua. The electrification program with solar home systems or super energy saving lantern (SEHEN) is not a capacity development program for the power system. The SEHEN electrification program is intended to be a temporary program and is limited to areas with low electrification ratios, such as in West Nusa Tenggara, East Nusa Tenggara and Papua, after first conducting a feasibility study. The SEHEN program can be substituted by centralizedcommunal solar power plants. The construction of solar power plants and installation of solar home system will be preceded by a feasibility study. Table-13. Development Plan for New and Renewable Energy No New and renewable energy power plant Capacity Total 1 MHPP MW ,481 2 Solar Power MWp Wind Power MW Biomas PP MW Ocean PP MW Biofuel PP Thousand Kilo Liter ,815 Total MW ,786 DEVELOPMENT PLAN FOR ISOLATED POWER SYSTEMS Besides the 6 interconnected power systems, there are more than 100 isolated systems spread throughout the Eastern Indonesia region. The systems are spread over the provinces of Maluku, North Maluku, Papua, West Papua, West Nusa Tenggara, East Nusa Tenggara and Riau Islands. Even in islands where the power systems are interconnected, there are isolated systems such as in Nias, Belitung, Buton, Selayar, Karimun Jawa, Bawean and many other islands. RISK ANALYSIS Based on the probability and impact if the risks occur, the risks have been mapped as shown in Figure-23. The assessment of the risks and impact have been conducted with qualitative method based on PLN s experience in carrying out similar programs in the past, and PLN s experience in handling such risks in the past. RUPTL Determination of the risk impact is based on the impact to company cash flow and the impact on smooth operation of the company. 32 Executive Summary Electricity Supply Business Plan

39 Very High High PROBABILITY RATE Medium Low Very Low Not Significant Minor Medium Significant Disaster IMPACT SCALE Description : EXTREME RISK : HIGH RISK : 3 Limited funding capability risk 1 Change in electricity sector orderpolicy risk 4 PLN and IPP project completion delay risk 2 Unrealized electricity tariff rationalization risk 5 Unconformity power plant and transmission line risk 6 Non-oil primary energy supply constrain risk 10 Increase of primary energy price risk 7 Electricity consumption higher than demand projection risk 8 Power plant and transmission performance degradation risk 9 Transmission line system bottlenecking risk 11 Environmental risk 12 Disaster risk Figure-23. Mapping Long-Term Risk Profile for CONCLUSION Assuming the economic growth during the next ten years average 6.9% and increasing from actual electricity demand in 2012, projected electricity sales in 2022 are estimated to reach 387 TWh or a growth rate of 8.4% over the next 10 years. Peak load in 2022 is projected to reach 64 GW. To meet electricity demand, the development of new power plants during the period with total capacity of 60 GW has been planned. In line with the development of aforementioned power plants, the development of 57,100 kms of transmission system will be required, consisting of 5,600 kms of 500 kv AC EHV transmission lines, 1,100 kms of 500 kv HVDC transmission lines, 462 kms of 250 kv HVDC transmission lines, 6,400 kms of 275 kv AC transmission lines, 39,600kms of 150 kv HV transmission lines and 3,900 kms of 70 kv HV transmission lines. Additional transformer capacity required include 134,000 MVA consisting of 72,900 MVA kv transformers, 3,700 MVA 7020 kv and 35,700 MVA kv inter-bus transformers (IBT), 17,100 MVA kv IBT, 480 MVA kvibt, 4,000 MVA kv IBT and 600 MVA 250 kv DC. In anticipation of electricity sales growth during the period , it will require additional 224,800 kms of medium voltage grids, 217,200 kms of low voltage grid and 35,600 MVA of distribution transformer capacities Executive Summary Electricity Supply Business Plan

40 The overall investment required for power generation, transmission and distribution for the period to meet the requirement of electrical power infrastructure development in Indonesia is US$125.2 billion, consisting of power generation investment (including IPP) of US$ 91.3 billion, transmission system investment of US$ 19.4 billion and distribution system of US$ 14.5 billion. The funds for PLN investment will be met by the State Budget (APBN) in the form of Government equity participation, new loan, and internal funds. PLN s internal funding capacity is limited and as such, all funds required for investment will be obtained from debt. PLN s investment needs to be supported by increasing capacity for self-funding and maintaining the ratio of debt to PLN s assets, so that it would continue to support the development of electrical power supply. The role of APBN each year will be significant because it is politically difficult to raise electricity tariff to a level higher than the basic generating cost (BPP) in the near term. RUPTL 34 Executive Summary Electricity Supply Business Plan

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