feasibility study of power supply upgrading in north west of java

Study on Economic Partnership Projects

in Developing Countries in FY2015

Feasibility Study of power supply upgrading

in North West of Java Island

Final Report

February, 2016

Prepared for:

Ministry of Economy, Trade and Industry

Prepared by:

KPMG AZSA LLC

Tokyo Electric Power Services Co., Ltd.

Reproduction prohibited

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Contents Chapter1. Summary ................................................................................................................................... 1-1

1.1 Needs and Background of the Project ................................................................................................. 1-1

1.2 Outline of the Project .......................................................................................................................... 1-1

1.2.1 Required transmitting capacity ....................................................................................................... 1-1

1.2.2 Selection of the method to upgrade the transmission capacity ....................................................... 1-1

1.2.3 Selection of the type of HTLS ........................................................................................................ 1-3

1.2.4 Re-conductoring Work ................................................................................................................... 1-4

1.2.5 Total Project Cost ........................................................................................................................... 1-4

1.3 Content and Result of Economical Evaluation ................................................................................... 1-5

1.4 Content and Result of Financial Evaluation ....................................................................................... 1-6

1.5 Comparison between Reconductoring and New Transmission Line .................................................. 1-6

1.6 Environmental and Social Practicability ............................................................................................. 1-6

1.7 Project Implementation Schedule ....................................................................................................... 1-7

1.8 Advantages of Japanese Enterprises in Technologies ......................................................................... 1-7

1.9 Financing Options for the Project ....................................................................................................... 1-7

1.10 A Concrete Schedule and a Risk of Realization ................................................................................. 1-8

1.11 Project Implementation Map of West Jawa ........................................................................................ 1-8

Chapter2. Objective of the Study, Content and Methodology ................................................................ 2-1 2.1 Study Objective .................................................................................................................................. 2-1

2.2 Study Contents .................................................................................................................................... 2-1

2.3 Details of study contents ..................................................................................................................... 2-3

2.4 Implementation Schedule of the Study ............................................................................................... 2-5

Chapter3. Background of the Study and Review of the Previous Study ................................................ 3-1 3.1 Outline of the study area ..................................................................................................................... 3-1

3.1.1 Overall of Indonesian economic situation ...................................................................................... 3-1

3.1.2 The economic situation of Java northwestern area ......................................................................... 3-3

3.2 Demand ............................................................................................................................................... 3-5

3.2.1 Demand record ............................................................................................................................... 3-5

3.2.2 Demand forecast ............................................................................................................................. 3-5

3.2.3 Power generation development plan ............................................................................................... 3-7

3.2.4 Transmission line projects in RUPTL 2015-2024 .......................................................................... 3-9

3.3 Review of the previous report ........................................................................................................... 3-11

3.3.1 Necessity study in the previous report in 2008 ............................................................................. 3-11

Chapter4. System Analysis ......................................................................................................................... 4-1 4.1 Conducted survey ............................................................................................................................... 4-1

4.2 Analysis condition .............................................................................................................................. 4-1

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4.2.1 Target year ...................................................................................................................................... 4-1

4.2.2 Latest transmission augmentation plans in the northwestern region of Jawa-Bali system ............. 4-3

4.2.3 Demand assumptions ...................................................................................................................... 4-7

4.2.4 Loading conditions of generators ................................................................................................... 4-7

4.2.5 Allowable voltage range ................................................................................................................. 4-9

4.2.6 Transmission line capacity ............................................................................................................. 4-9

4.2.7 Other conditions for the system analyses ....................................................................................... 4-9

4.3 Power flow analyses ......................................................................................................................... 4-10

4.3.1 Result of power flow analyses under the normal (N-0) conditions before reconductoring .......... 4-10

4.3.2 Result of power flow analyses under the N-1 conditions ............................................................. 4-11

4.3.3 Necessary capacity of reconductored transmission lines .............................................................. 4-13

4.4 Fault current analyses ....................................................................................................................... 4-13

4.4.1 Conditions for the fault current analyses ...................................................................................... 4-13

4.4.2 Result of fault current analysis ..................................................................................................... 4-13

4.4.3 Overview of the rsult of fault current analysis ............................................................................. 4-16

4.5 Measures against fault current problems .......................................................................................... 4-17

4.6 Stability analyses .............................................................................................................................. 4-29

4.7 Recommendations ............................................................................................................................. 4-35

Chapter5. Technical Feasibility of the Project ......................................................................................... 5-1 5.1 Scope of the Project ............................................................................................................................ 5-1

5.2 Transmission Line Project .................................................................................................................. 5-1

5.2.1 Selection of the Method to Upgrade the Transmission Capacity .................................................... 5-1

5.2.2 Selection of the Type of HTLS ....................................................................................................... 5-6

5.2.3 Evaluation of transmission losses ................................................................................................. 5-11

5.2.4 Re-conductoring Work to HTLS .................................................................................................. 5-12

5.2.5 Re-conductoring Costs ................................................................................................................. 5-19

5.2.6 Construction Schedule .................................................................................................................. 5-20

5.2.7 Points to be Considered for Stringing Work ................................................................................. 5-21

5.3 Substation Project ............................................................................................................................. 5-25

5.3.1 Overview of Existing 500 kV Substations .................................................................................... 5-25

5.3.2 Adaptation and Replacement Works for Substation Equipment ................................................... 5-34

5.3.3 Substation Project Costs ............................................................................................................... 5-36

5.4 Total Project Costs ............................................................................................................................ 5-36

Chapter6. Environment and Social Practicability ................................................................................... 6-1 6.1 Environmental and Social Impact of the Project .................................................................................... 6-1

6.1.1 Social resettlement .......................................................................................................................... 6-1

6.1.2 Electric and Magnetic Field Intensities .......................................................................................... 6-1

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6.1.3 Corona Noise .................................................................................................................................. 6-2

6.1.4 Radio Noise .................................................................................................................................... 6-2

6.2 Review according to the Japan International Cooperation Agency (JICA) Guidelines for

Environmental and Social Considerations .......................................................................................................... 6-2 6.2.1 Assessment of Environmental Checklist under JICA Guidelines ................................................... 6-2

6.2.2 Project classification according to JICA’s Guidelines .................................................................... 6-8

6.3 Host country’s environmental regulations and standards ................................................................... 6-8

6.3.1 Outline of Environment-Related Laws and Regulations of Host Country ....................................... 6-8

6.3.2 Details of Environmental Impact Assessment of the Host Country required for the Project ....... 6-12

Chapter7. Financial and Economic Feasibility ........................................................................................ 7-1 7.1 Capital Costs of Project ....................................................................................................................... 7-1

7.1.1 Construction Process and Implementation Period .......................................................................... 7-1

7.1.2 Capital Costs and Assumptions ...................................................................................................... 7-1

7.2 Economic Analysis .............................................................................................................................. 7-4

7.2.1 General Approach and Methodology .............................................................................................. 7-4

7.2.2 Economic Benefit ........................................................................................................................... 7-5

7.2.3 Economic Cost ................................................................................................................................ 7-6

7.2.4 Project Life and Operation Period ................................................................................................... 7-7

7.2.5 Result of economic evaluation ........................................................................................................ 7-7

7.2.6 Sensitivity analysis of economic results ....................................................................................... 7-10

7.3 Financial Analysis ............................................................................................................................. 7-11

7.3.1 General Approach and Methodology ............................................................................................ 7-11

7.3.2 Financial Benefit .......................................................................................................................... 7-11

7.3.3 Financial Cost ............................................................................................................................... 7-13

7.3.4 Project Life and Operation Period ................................................................................................. 7-14

7.3.5 Results of Financial Evaluation .................................................................................................... 7-14

7.3.6 Sensitivity Analysis from a Financial Standpoint.......................................................................... 7-16

7.4 Conclusion of Financial and Economic Analysis ............................................................................... 7-16

7.4.1 Economic Analysis ........................................................................................................................ 7-16

7.4.2 Financial Analysis ......................................................................................................................... 7-16

7.4.3 Comparison between reconductoring and new transmission line ................................................. 7-16

Chapter8. Project Implementation Schedule ........................................................................................... 8-1 8.1 Entire Schedule ................................................................................................................................... 8-1

8.2 The schedule to the EPC agreement ................................................................................................... 8-1

8.3 Construction schedule ......................................................................................................................... 8-1

Chapter9. Advantages of Japanese Enterprises in Technologies and Financing Options for the Project9-1 9.1 Comprehensive Advantage of Japanese Enterprises in Technologies ................................................. 9-1

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9.1.1 International Competition and Possibility to obtain this Contract by Japanese Entities ................ 9-1

9.1.2 Possible Materials Supplied from Japan and their Relevant Cost .................................................. 9-1

9.1.3 Necessary Countermeasure to Promote securing of the Contract by Japanese Entities ................. 9-1

9.2 Financing Options for the Project ....................................................................................................... 9-2

9.2.1 Overview of Transmission Line Financing in other countries ........................................................ 9-2

9.2.2 Overview of Financing in the Indonesian Power Sector ................................................................ 9-2

9.2.3 Overview of Financing at PLN ....................................................................................................... 9-7

9.2.4 Use of Japanese ODA Loan Requirements in the Proposed Project ............................................... 9-7

9.2.5 Implementation Capability of Relevant Agencies of Indonesia ..................................................... 9-8

9.2.6 Evaluation of Implementation Capability of the Relevant Agencies of Indonesia ....................... 9-11

9.2.7 PLN’s Financial Conditions ......................................................................................................... 9-13

9.2.8 Current Situation for the Japanese ODA Loan ............................................................................. 9-15

9.2.9 Implementation Plan for Japanese ODA Loan ............................................................................. 9-17

(Appendix) Workshop

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A list of abbreviations

Abbreviation Official name AC Alternate Current ACSR Aluminum Conductor Steel Reinforced BT Bus Tie cct circuit CB Circuit Breaker CFCC Carbon Fiber Composite Cables COD Commercial Operation Date CT Current Transformer DC Direct Current DIY Daerah Istimewa Yogyakarta (Special Region of Yogyakarta ) DS Disconnecting Switch EIA Environmental Impact Assessment EIS Environmental Impact Statement EMoP Environmental Monitoring Plan EMP Environmental Management Plan EPC Engineering, Procurement and Construction F/S Feasibility Study FTP II Fast Track Program II GCB Gas Circuit Breaker GIS Gas Insulated Switchgear GPS Global Positioning System

GTACSR Gap type Thermal-resistant Aluminum alloy Conductors, Steel

Reinforced HTC High Temperature Conductor HTLS(C) High Temperature Low Sag Conductor HVDC High Voltage Direct Current ICNIRP International Commission on Non-Ionizing Radiation Protection IEC International Electrotechnical Commission IEE Initial Environmental Examination IPP Independent Power Producer JICA Japan International Cooperation Agency LAA Land Acquisition Act LAP Land Acquisition Plan MVA Mega Voltage Ampere MW Megawatt NGO Non-Governmental Organizations ODA Official Development Assistance O&M Operation and Maintenance

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P3B-JB Penyalurandan Pusat Pengatur Beban Jawa-Bali (Java-Bali

Transmission and Load Dispatching Center ) PB Project Brief PQ Prequalification PLN Perusahaan Listrik Negara Persoro PLTA Pusat Listric Tenga Air (Hydro Power Plant) PLTG Pusat Listric Tenga Gas (Gas Power Plant) PLTGU Pembangkit Listrik Tenaga Gas & Uap (Combined Cycle Power Plant) PLTMG Pembangkit Listrik Tenaga Mesin Gas (Gas Engine Power Plant) PLTP Pembangkit Listrik Tenaga Panas Bumi (Geothermal Power Plant) PLTU Pembangkit Listrik Tenaga Uap (Steam Power Plant) PSS Power System Stabilizer PSS/E Power System Simulator for Engineering RJBR REGION JAWA BARAT RJKB REGION JAKARTA & BANTEN RJTD REGION JAWA TENGAH & DIY ROW Right Of Way

RUKN Rencana Umum Ketenagalistrikan Nasional (General National Power

Plan)

SNI Standar Nasional Indonesia (Standard of Indonesia) SR Shunt Reactor SRB Sub Region Bali S/S Substation SVC Static Var Compensators TACFR Thermal-resistant Aluminum alloy Cable, Fiber Reinforced TACSR Thermal-resistant ACSR TAL Thermal-resistant Aluminum alloy wires T/L Transmission Line TR Transformer UTACSR Ultra Thermal-resistant ACSR WB World Bank

XTACIR/AC Extra Thermal-resistant Aluminum alloy Conductor, Aluminum-Clad

Invar Reinforced

XTAL Extra Thermal-resistant Aluminum alloy wire

ZTACIR/AC Super Thermal-resistant Aluminum alloy Conductor, Aluminum-Clad

Invar Reinforced ZTAL Super Thermal-resistant Aluminum alloy wire

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Chapter1. Summary

1.1 Needs and Background of the Project

The power system on the Java Island of Indonesia is connected with the one of Bali Island, and is integrally

operated as Jawa-Bali power system. The maximum power demand of Jawa-Bali power system in 2014 was

33,321MW, which was equivalent to 72 % of the entire power demand in Indonesia including Sumatra Island and

others. And as for the transmission lines in Java-Bali power system, there are 150kV transmission lines which

covers most of the region together with 500kV transmission lines on two circuits running from west to east of Java

area.

PLN plans substantial power supply in West Java with its policy aiming to reduce pressure against transmission

system and prioritizing power supply closer to the region near the demand centre, Jakarta. Nevertheless, in West

Java, it is difficult to transmit power generated from newly constructed power plants to Jakarta due to lack of

capacity of existing transmission lines. In this background, PLN has planned new transmission lines in West Java.

But a number of challenges are anticipated, namely difficult land acquisition due to highly populated area,

increase in construction cost, longer construction period, limited financing and risk allocation.

With such objectives, background and review of the previous study result (Study on Upgrading Transmission

Capacity of Existing 500kV Lines in West Java, Indonesia in March 2008), and the Indonesian government’s plan

of new power generation, transmission and distribution, this study evaluates and proposes feasibility of upgrading

the facilities of the existing 500kV transmission lines between Suralaya (Lama) power stations in Banten region

and Gandul substations in West Java region and the equipments of related substations (“Project”) in the following

manner.

1.2 Outline of the Project

1.2.1 Required transmitting capacity

The Survey Team deemed that reconductoring of the 500 kV transmission line from Suralaya (Lama) through

Balaraja to Gandul will be necessary. Necessary capacity of reconductored transmission line was 3,443MVA

(3,976A) per circuit from the results of power flow analyses jointly conducted by P3B-JB and the Survey Team

within a restricted time frame. However, this capacity was derived from the result under the conditions in 2020,

and could be short-sighted. Although the Survey Team was not able to obtain data to evidence the future necessary

capacity of the to-be-reconductored transmission line, they deemed that the preferable capacity should be as large

as rationally achievable considering generation development in western Jawa region in future. According to PLN,

the expected capacity was 4,680 MVA after reconductoring.

1.2.2 Selection of the method to upgrade the transmission capacity

From the results of the system analysis in 2020 conducted in the Study, the transmission capacity more than

987 amperes per conductor in the Previous Study is found to be necessary. Therefore methods to upgrade as much

capacity as possible are considered in this section. However the upgrading method by constructing a new

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transmission route is excluded because acquiring the lands and right-of-ways for a new transmission line is

extremely difficult in Indonesia.

The following several methods to upgrade the transmission capacity are candidates for the Project.

(1) Upgrading by using conventional ACSR

(2) Adoption of HTC (High Temperature Conductor)

(3) Adoption of HTLS (High Temperature Low Sag Conductor)

Each method and the result of study are described as follows.


This method enables the transmission capacity to increase by increasing the number of conductors per phase, or

replacing the existing conductors with larger ones, in the case of using conventional ACSR. If the existing

conductors are replaced by both methods, it goes without saying that the components of the towers such as the

main posts and the foundations do not have enough strength to support the loads due to the increased weight and

wind pressure. Consequently, reconstruction of the existing towers is not avoidable, and this method is not

appropriate for the Project because the Project cost and period will be increased.


HTC such as TACSR (Thermal resistant AACSR) and UTACSR (Ultra Thermal resistant AACSR) has higher

allowable temperature than conventional ACSR, and therefore has greater current capacity. On the other hand,

conductors with higher temperature have larger sag and cannot probably keep the clearances between conductors

and objects. Reducing the span length is a solution to keeping the same sag at the maximum allowable

temperature. The span length can be reduced by installing a new tower between each span. This method enables

the transmission capacity to increase under keeping the required ground clearance. However, due to installation of

many new towers, the Project cost and period will be increased. In this method, new towers have to be installed at

all the mid-spans. Therefore, this is not appropriate for the Project.


HTLS has as high allowable temperature as HTC, and also has lower sag than HTC. Generally, the characteristic

is realized by using a material with the low co-efficient of linear expansion value as the core. This method enables

the transmission capacity to increase under keeping the required ground clearance.

The merits in this method are as follows.

• Modifications to existing towers, such as reinforcements or reconstruction, are not necessary.

• HTLS has twice as much current carrying capacity as the existing conductor.

• Only re-conductoring enables the transmission lines to be upgraded, and it leads to the shorter

implementation period of the Project.

• No additional lands are acquired, and there are few environmental and social impacts.

From the above-mentioned, this method is the most appropriate for the Project.

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1.2.3 Selection of the type of HTLS

Although there are several types of HTLS, the required design conditions for up-rating conductors are as

follows.

• Not to exceed the sag of the existing conductor, 21.70 m at the 500 m span.

• Not to exceed the maximum tension (23,025 N) of the existing conductor.

• Not to exceed the weight (1,140 kg/km) and the diameter (23.53 mm) of the existing conductor.

The following conductors are selected as candidate from the viewpoints of the above.

① Thermal-resistant Aluminum Alloy Cable, Fiber Reinforced (TACFR)

② Super Thermal-resistant Aluminum Alloy Conductor, Aluminum-clad Invar Reinforced (ZTACIR/AC)

③ Extra Thermal-resistant Aluminum Alloy Conductor, Aluminum-clad Invar Reinforced (XTACIR/AC)

(1) Outline of conductors

① Thermal-resistant Aluminum Alloy Cable, Fiber Reinforced (TACFR)

The conductor is up-rated by the use of thermal-resistant aluminum alloy wire (TAL) which has the continuous

allowable temperature up to 150°C. The sag is lowered by the use of carbon fiber composite cable (CFCC) with

the low co-efficient of linear expansion value.

② Super Thermal-resistant Aluminum Alloy Conductor, Aluminum-clad Invar Reinforced (ZTACIR/AC)

To increase the current carrying capacity, super thermal-resistant aluminum alloy wire (so-called “ZTAL”),

which can utilize up-to 210°C continuously, is used. And to restrain the sag to increase, Invar core wire, whose

co-efficient of linear expansion value is smaller, is adopted to satisfy the requirement.

③ Extra Thermal-resistant Aluminum Alloy Conductor, Aluminum-clad Invar Reinforced (XTACIR/AC)

To increase the current carrying capacity, extra thermal-resistant aluminum alloy wire (so-called “XTAL”),

which can utilize up-to 230°C continuously, is used. And to restrain the sag to increase, Invar core wire, whose

co-efficient of linear expansion value is smaller, is adopted to satisfy the requirement.

(2) Evaluation

XTACIR/AC 230mm2 has the most current carrying capacity of the candidates for the new conductor, and is

recommended for the Project. The capacity is approximately 2.4 times as much as that of the existing conductor.

(3) Transmission loss

In the case of flowing the same current, the losses of XTACIR/AC 230mm2 are about 1.3 times as much as those

of the existing conductor because the AC resistance of XTACIR/AC 230mm2 is about 1.3 times as high as those of

the existing conductor.

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1.2.4 Re-conductoring Work

(1) Conductors’ replacement methods

There are two kinds of conductors’ replacement methods, the tension stringing method and the cradle block

method. Each method is described as follows.

① Conventional tension stringing method (in the general location)

This method is conducted by connecting the up-rating conductors to the existing conductors, and then by pulling

out the existing conductors to replace to the up-rating conductors. To implement this method the construction

workers will have to be cautious with the obstacles in the line crossings by setting up the sufficient scaffold on top

of the obstacles to avoid contact with replaced conductors. But as a merit, this method can be paid out all 4

conductors simultaneously and therefore the time of construction will be minimized.

② Cradle block stringing method (for urban housing area or important line crossing)

For the urban housing area or important line crossing, the location to set up the scaffold will be very difficult to

obtain. Therefore the construction will be conducted by means of so-called cradle block system method. The

cradle block system is a method to distribute twin rollers in 20 to 30 meters’ intervals in the relevant span, to hang

upper roller on the existing conductor and to replace the up-rating conductor by means of the roller installed

underneath. By using this method, the sag of this conductor will be restrained by the existing conductors therefore

even if there are urban housing area or important line crossing it is not necessary to set-up any scaffoldings to pay

out the up-rating conductors. However for his method the construction speed will be slower since the each

individual conductor can be re-conducted one by one.

(2) Recommended sections suitable for Cradle Block Method

As a result of the site survey, it is found that this method has to be adopted in the densely populated areas near

Gandul SS, and also at many main roads, express way, railway or other transmission line crossings. This method

will be applied to 36% of the total length of the lines.

(3) Construction Period

If the re-conductoring is conducted by conventional tension stringing method, paying out of 4 conductors can be

simultaneously carried out. So, the progress of about 8 km/month/circuit per crew is anticipated On the other hand,

if cradle block system is adopted, since this method needs to pay out conductor one by one, the progress of only 4

km/month/circuit per crew can be expected. Either method is selected by the situation along the transmission line.

If four crews are adopted, the construction period excluding a design and product manufacture is estimated to

about 10 months.

1.2.5 Total Project Cost

The total project cost is composed of the construction cost of the transmission lines and substations, the

consulting cost and the administration cost etc. The total project cost is shown in Table 1-1.

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Table 1-1 Total Project Cost

Unit：US$ Mil

Component Cost

Construction cost of transmission

line 83.60

Construction cost of substation 24.20

Contingency 10.78

Consulting cost 5.39

Administration cost 10.78

Total 134.75

The following items are not included in total Project cost.

• EIA implementation cost

• Public official approval cost and license acquisition cost

• Tax

• Price escalation

1.3 Content and Result of Economical Evaluation

In this economic analysis, the "With and Without Principle" is applied, and the case where the proposed project

(re-conductoring of transmission lines and substation remodelling) is implemented (With) and the case where an

alternative plan (new construction of transmission lines and substations) is implemented (Without) are compared.

As shown in Table 1-2 below, EIRR of this project is calculated at 12.58%, and it exceeds 10%, the assumed

discount rate (opportunity cost of capital) of Indonesia, it can be concluded that this project is feasible from an

economic standpoint. And also, the B/C ratio is calculated at 1.028, and it exceeds 1.0. So it can be concluded that

this project is feasible from an economic standpoint.

Sensitivity analysis where the economic cost increases by 5% and where the economic benefit deceases by 5%

are 8.03% and 8.10% respectively.

Table 1-2 Results of Ccost-Effectiveness Evaluation

EIRR (%) B/C Ratio B-C (1000 US$)

12.58% 1.028 3,205

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1.4 Content and Result of Financial Evaluation

As shown in Table 1-3, the Financial Internal Rate of Return (FIRR) of this project was calculated at 14.31%, it

is slightly higher than the market interest rate of ordinary commercial banks in the Indonesian financial market

(12.0%), allowing us to conclude that this project is financially feasible.

Table 1-3 Results of Financial Evaluation

FIRR (%) NPV (US$1000)

14.31% 45,359

Sensitivity analysis where the economic cost increases by 5% and where the economic benefit deceases by 5%

are 13.53% and 13.57% respectively, they are slightly higher than the market interest rate, allowing us to conclude

that this project is financially feasible.

1.5 Comparison between Reconductoring and New Transmission Line

Due to the substaibive power supply in West Java, the existing transmission lines are ecpected to be overloaded.

For the capacity of the steady supply, the increase of the capacity of the transmission is a immideate theme.

Between the proposed reconductoring and the alternative project for a new transmission line, the reconductoring

project is more attractive for various reasons.

① The proposed reconductoring project does not require land acquisition or right-of-way access as existing

transmission towers are used.

② This reduces the social and environmental impact and allows the project to be completed in a shorter

timeline.

③ Furthermore, reconductoring does not lead to an increase in O&M costs as the number of equipment and

circuits remain the same.

④ Since the proposed reconductoring project also requires lower capital investments, the reconductoring

project enables the use of higher quality and more advanced conductor technology.

1.6 Environmental and Social Practicability

In case of this project, the planned increase in the capacity of the transmission lines can be achieved simply by

re-conductoring the transmission line using the existing electric power pylons, therefore resettlement of the

residents will not be necessary in principle..

As for the electric field strength, it is reported that the transmission line conductor with the minimum height of

15 m above the ground has the values a little more than 5 kV/m, and that the actual conductor height above the

ground, 16 m or so, has the electric fiel

d strength of 4.9 kV/m.

The transmission line voltage and the height of the replaced conductors will be the same as those of the existing

line. Therefore the predicted electric field strength will also be same as that in the Previous Report, and be less

than 5 kV/m.

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Corona Noise level and radio noise level would not be much changed after the re-conductoring.

Therefore, there will be no new physical objects to adversely affect the environment.

1.7 Project Implementation Schedule

Taking into consideration the commissioning in 2019, the followings represent the Project schedule from the

conclusion of Japanese Soft Loan Agreement to the operation of the target facilities.

Pre-Construction Period

Selection of Consultant and Conclusion of Consultant Contract 6 months

Preparation of EPC Tender Documents 6 months

Preparation of Bids 3.5 months

Evaluation of Bids, Selection of EPC Contactors, Conclusion of contracts 8 months

Total（including duplication） 18 months

Construction Period

Re-conductoring of Suralaya － Gandul line 17 months

Replacement of substation facilities 18 months

Total（including duplication） 18 months

Gland Total 36 months

1.8 Advantages of Japanese Enterprises in Technologies

Invar type of conductor, XTACIR/AC, was invented and developed in Japan, and three Japanese manufacturers

have produced the conductor. The extra thermal-resistant aluminum alloy wire (so-called “XTAL”) requires

manufacturing know-how, which cannot be easily imitated. At present, there seem to be no manufacturers of the

wire in countries other than Japan, and therefore the Japanese manufactures have high possibilities to win the

order.

The replacement works, Cradle Block Method, was developed in Japan, where the conductor erection works

have been frequently conducted in densely populated areas. Therefore Japanese contractors have extensive

experiences and international competitiveness in the method.

1.9 Financing Options for the Project

As part of the Government’s effort to resolve key issues hampering the acceleration of infrastructure

development. Committee for the Acceleration of Priority Infrastructure Development (Komite Percepatan

Penyediaan Infrastruktur Prioritas / KPPIP) was established under Presidential Regulation Number 75 of 2014,

dated 17 July 2014, regarding the acceleration of priority infrastructure development..

In the transmission sector, PLN raises financing for transmission lines through various means such as

government loans, domestically syndicated commercial loans and bond issues.

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In a summit meeting held between Mr Shinzo Abe, Prime Minister of Japan and Mr Joko Widodo, President of

the Republic of Indonesia on 23 March 2015 in Japan, both leaders expressed strong commitment to expand

bilateral trade and investment cooperation. In the meeting, both leaders also concurred in launching “PROMOSI:

Japan-Indonesia Investment and Export Promotion Initiative”. Under the PQI, Japan will streamline the ODA loan

procedures from around 3 years to 1.5 years and also to allow ODA loans to be extended to sub-sovereign entities.

At present, there is no official request for the Japanese ODA Loan in this project. However, together with the

preceding Central West Java transmission line project, which PLN and JICA have been developing and appraising,

it is expected to put in the process as PLN is positively considering to take up this project which further

strengthens power transmission capacity. Application for Japanese ODA Loan will be filed according to the

subsequent process of the request for the Japanese ODA Loan by the Government of Indonesia.

1.10 A Concrete Schedule and a Risk of Realization

New generators connected with the power system cause increase of fault current. Some measure(s) have to be

prepared since the fault current level in Jawa-Bali power system will exceed the existing equipment rating in the

near future by connecting generators including Jawa 5 and Jawa 7. One of measures against the fault current

increase is to upgrade the fault current level from 50 kA to 63 kA. This fault current level upgrading, which takes

many years in general, might have a dampening effect on new power plant constructions.

1.11 Project Implementation Map of West Jawa

The project is to upgrade the transmission capacity by re-conductoring the existing 500 kV transmission lines

with 111 km length from Suralaya Power Plat in Banten province to Gandul substation in West Java province. The

Project implementation map is shown in Figure 1-1.

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Figure 1-1 Project implementation map

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Chapter2. Objective of the Study, Content and Methodology

2.1 Study Objective

There are transmission facilities in Java-Bali region in Indonesia, such as main two routes of 500kV running

from east to west of Java and 150kV covering entire region. However, imbalance of supply and demand in the

grid zone has become more imminent. In other words, 60% of demand is in West Java, where Jakarta City lies,

whereas power generation facilities are almost evenly distributed across east to west (about 900km) in Java. In

such environment, power is transmitted from east to west.

PLN plans substantial power supply in West Java with its policy aiming to reduce pressure against transmission

system and prioritizing power supply closer to the region near the demand centre, Jakarta.

Nevertheless, in West Java, it is difficult to transmit power generated from newly constructed power plants to

Jakarta due to lack of capacity of existing transmission lines. This undermines stable power supply in the future.

In this background, PLN has planned new transmission lines in West Java. But a number of challenges are

anticipated, namely difficult land acquisition due to highly populated area, increase in construction cost, longer

construction period, limited financing and risk allocation.

With such objectives, background and review of the previous study result (Study on Upgrading Transmission

Capacity of Existing 500kV Lines in West Java, Indonesia in March 2008), Indonesian government’s plan of new

power generation, transmission and distribution, this study evaluates and proposes feasibility of facilities of

transmission and substation (replacement and new construction) in the following manner.

2.2 Study Contents

A) Objective of this feasibility study

This assessed feasibility of upgrading of transmission lines, in line with major new power generation

construction plan (Java 5, Java 7 and Lontar etc.) in North West part in Java Island (PLN’s power supply

construction general plan / RUPTL 2015-2024). More specifically, we studied 500kV transmission lines including

Suralaya-Gandul line that the previous study focused.

2-2

【Banten province, North West of Java Island】

Assumption

Construction of respective power plants (including transmission line construction which connects with the

neighboring power system）

Upgrading construction of transmission capacity (line replacement) and replacement of equipments of

substations, which are required for connection with respective power plants

However, construction which addresses against increased fault occurrence is outside the scope.

Existing substations

Existing substations

New power plants

Transmission line for grid connection

Existing transmission lines This requires capacity increase to

support New connection of power plants （line replacement）（substation replacement）

Existing transmission lines

Existing transmission lines

Objective of this feasibility study

2-3

B) Assessment of necessity of equipment upgrade based on power distribution system analysis

In cooperation with PLN, conduct analysis and evaluate necessity of facility upgrading, based on RUPTL

2015-2024.

Analysis of power flow, stability and fault occurrence.

C) Examination of construction process required

Analysed construction of conductor’s replacement and substation replacement through the result of the previous

report. Specifically, based on the previous study, collect samples in minimum level in case conducting site visits to

existing power facilities.

D) Economic, financial analysis and environmental and social assessment

Based on the result of technical evaluation, we conducted, economic and financial analysis and propose

financing measures.

In environment and social aspects, reviewed changes in regulations that have been made since the previous

study.

2.3 Details of study contents

① Confirmation of project background

Review RUPTL 2015-2024 by comparing the result of the then RUPTL in the previous study (2008) in

terms of power demand, power supply development, geographical distribution of demand/supply and

transmission upgrading plan.

② Review of the power distribution system analysis conducted in the previous study

We reviewed the results of the previous study from the view point of comparing in terms of power

demand, power supply development, geographical distribution of demand/supply and transmission

upgrading plan.

③ Rationale of equipment expansion based on the power system analysis

We analysed based on PSS/E data. And we interviewed PLN and so on during the field works, and

confirmed whether there were the similar studies which had done or not, and the difference of recognition.

④ Fault occurrence analysis and identification of counter measures

We analysed based on PSS/E data. And we interviewed PLN and so on during the field works, and

confirmed whether there were the similar studies which had done or not, and the difference of recognition.

⑤ Assessment of upgrading the transmission capacity

After reviewing the previous report, evaluated update of existing transmission line （conductor’s size,

ground clearance etc.）、existing substations（devices installed etc.） and power flow status.

2-4

⑥ Economic and financial analysis

We analysed economic and financial feasibility considering the results of the above and the previous

report.

⑦ Confirmation of environmental and social issues

We conducted documentary searching and the field works including the interviews to the related

person and ministries.

⑧ Evaluation of Japanese companies’ technical competitiveness and proposition and Outlook of project

financing

We conducted documentary searching and interviewed the Japanese companies, financial institutes,

and related ministries in the partner’s country such as Ministry of Finance, PLN and P3B JB.

And, our study team was consisted of the below,

Company name Role

KPMG AZSA LLC Overall coordination, Implementation coordination, support to

reporting of the study result

TOKYO ELECTRIC POWER

SERVICES CO., LTD.

Power system analysis*, Technical coordination, transmission line

assessment, cost estimation, Substation assessment, cost estimation

KPMG ASPAC Infrastructure

Group

Economic and financial analysis, Environment and social

consideration , Outlook of project financing etc,

* A part of power system analysis was done by TOKYO ELECTRIC POWER COMPANY, INCORPORATED

2-5

2.4 Implementation Schedule of the Study

The study period is as follows.

August 31, 2015 (contract date) - 29 February 2016

Figure 2-1 shows the schedule of this survey. Also 1st, 2nd and 3rd of the field survey schedule as well as an

outline of the local reporting event are shown in Figure 2-1 and from Table 2-1 to Table 2-4.

Figure 2-1 Implementing Schedule

Sep Oct Nov Dec Jan Feb

Work in Japan

The second field work (Nov 8～14）

The third field work(Nov15～21）

Briefing session (Feb 10)

Submission of report

Work in Japan

2-6

Table 2-1 Outline of the first field work

Date Contents 1 Sep 6, 2015 (Sun) Transfer to Djakarta from Tokyo

2 Sep 7, 2015(Mon) Interviews

・PT.PLN (Directorate of Finance, Directorate of Planning)

・Ministry of Energy and Mineral Resources

・PT.PLN(System Planning)

3 Sep 8, 2015(Tue) ・Japanese Embassy interview

・Ministry of Finance (Directorate General of Financing and Risk management,

Directorate of Government Guarantee) interview

・Coordinating Ministry of Economic Affairs interview

・P3B-JB interview and Power system analysis

4 Sep 9, 2015(Wed) ・Ministry of Environment interview

・Ministry of Finance(Fiscal Policy Agency) interview

・PT Indonesia Infrastructure Guarantee Fund interview

・Ministry of National Development Planning interview

・JICA Indonesia interview

A part of study team return to Japan form Djakarta.

5 Sep 10, 2015(Thu) ・P3B-JB (System Planning) Power system analysis

・Multfab interview

・PLN(Corporate Finance, Foreign Loan and ODA) interview

A part of study team return to Japan or Singapore form Djakarta.

6 Sep 11,2015(Fri) ・P3B-JB (System Planning) Power system analysis

Transfer from Djakarta

7 Sep 12, 2015(Sat) Transfer to Tokyo

Table 2-2 The Outline of the Second Field Work Date Contents

1 Nov 8, 2015(Sun) Transfer from Tokyo to Djakarta

2 Nov 9, 2015(Mon)

-Nov 11,2015(Wed)

Power system analysis in P3B-JB

3 Nov 12, 2015(Thu) ・Preparation for the wrap-up meeting of the power system analysis

・Asia development bank interview

4 Nov 13, 2015(Fri) the wrap-up meeting of the power system analysis and the additional study in P3B-JB


5 Nov 14,2015(Sat) Return to Tokyo

Table 2-3 The outline of the third field work Date Contents

1 Nov 15, 2015(Sun) Transfer from Tokyo to Djakarta

2 Nov 16, 2015(Mon) ・Kick-off meeting in the P3B-JB office

2-7

・the inspection of Gandul substation and transmission line

3 Nov 17, 2015(Tue) ・the inspection of Gandul substation and transmission line

4 Nov 18, 2015(Wed) ・the inspection of Balaraja substation and transmission line

5 Nov 19, 2015(Thu) ・the inspection of Suralaya substation and transmission line

・PLN (Corporate Finance) interview

・JICA interview

・KfW interview

・PLN(Environment) interview

6 Nov 20, 2015(Fri) ・the wrap-up meeting of the power system analysis and the transmission lines in

P3B-JB

・the interviews for the construction companies

In the Indonesia

・PLN System Planning interview


7 Nov 21, 2015(Sat) Return to Tokyo

Table 2-4 The outline of the Briefing session Date Contents

1 Feb 9, 2015(Tue) Transfer from Tokyo to Djakarta

2 Feb 10, 2015(Wed) The Briefing session in Workshop*


3 Feb 11, 2015(Thu) Return to Tokyo

*see (Appendix) Workshop

3-1

Chapter3. Background of the Study and Review of the Previous

Study

3.1 Outline of the study area

In Indonesia, there are 33 provinces including DKI JAKARTA, DI YOGYAKARTA etc.. This study area is

particularly DKI JAKARTA and BANTEN in Java northwest. After looking the bird's-eye view of the economic

situation in Indonesia, we explain about outline of the Java northwest.

*

Range of the above table indicates the provinces of Java island and Jakarta Capital Territory State (table above 31.DKI

JAKARTA) and BANTEN (table above 36.BANTEN) are located in the northwestern part of Java Island.

3.1.1 Overall of Indonesian economic situation

According to IMF, after the collapse of Lehman Brothers in 2009, the real GDP growth rate in Indonesia

recovered in 2010, but it has decreased gradually through 2015. Economic growth of Indonesia had been

supported by robust consumer spending and stable exchange rates. The decrease of the real GCP growth rate was

caused from the policy interest rates raised due to increase of the current-account deficit and the expansion of

inflationary pressures.

However, in the IMF's forecast, the growth rate after 2015 will be in the range from 5% to 6%, the stable

economic growth is expected. Figure 3-1 shows the trends of the real GDP growth rate and its estimate, 2005 –

2020 by IMF.

3-2

Figure 3-1: Real GDP growth rate

(Source: International Monetary Fund, World Economic Outlook Database, October 2015) * Estimated value

Figure 3-2 shows the trends of nominal GDP and the government gross debt. The government gross debt is not

large elongation relative to the growth of nominal GDP. The ratio of government gross debt vs. the GDP decreased

from about 87% in 2000 to about 24% in 2010. Also, in the prediction of 2020 by IMF, the ratio is expected to be

flat.

Figure 3-2：GDP at Current Market Prices General and Government Gross Debt, the ratio of

Government Gross Debt vs. GDP (Billion Rupiahs, %)


Also, from the transition of the fiscal balance, the total amount of government revenue and the total of

government expenditure have been increasing year after year. The fiscal balance has become some of the negative

in recent years.

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%

Gross domestic product, constant prices

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Rp0

Rp5,000,000

Rp10,000,000

Rp15,000,000

Rp20,000,000

Rp25,000,000

2000 2005 2010 2015* 2020*

Gross domestic product, current prices

General government gross debt

General government gross debt (Percent of GDP)

3-3

Figure 3-3：General Government Revenue, General Government Expenditure and General government

primary net lending/borrowing (Billion Rupiahs)


In addition, as a feature of Indonesia's fiscal spending, a percentage of the financial expenditure of government

energy subsidies is as large as about 30%. Though this energy subsidy is devoted to compensation of the fuel and

electricity prices, the Indonesian government is committed to the subsidy reform and efforts to reduce it.

3.1.2 The economic situation of Java northwestern area

Population in Java is approximately 140 million people in the estimate of fiscal 2015, it has accounted for about

57 percent of the entire Indonesia. And the population of both DKI Jakarta and BANTEN province located in Java

northwest is approximately 15% of the population in Java in total. According to the IMF forecast, while a large

increase in the West Java Province is expected, the populations in DKI Jakarta and BANTEN province are going

to gradually increase.

(Rp1,000,000)

(Rp500,000)

Rp0

Rp500,000

Rp1,000,000

Rp1,500,000

Rp2,000,000

Rp2,500,000

Rp3,000,000

Rp3,500,000

Rp4,000,000

2000 2005 2010 2015* 2020*

General government revenue

General government total expenditure

General government net lending/borrowing

3-4

Figure 3-4：Population of Indonesia by Province 2000-2035 (Thousand)

(Source: BPS STATISTIK INDONESIA) * Estimated value

In addition, the total of real GDP in Java occupies about 60% of it in Indonesia entire. The trends of the GDP

growth rate in Java have been similar to the movement of the rate of the entire Indonesia, it has achieved strong

economic growth at about 5-6%. Total of both DKI Jakarta and BANTEN province has become a about less than

40%. Absolute figures of GDP become larger in the order of DKI Jakarta, Jawa Timur (East Java) and Jawa

Barathas (West Java).

Figure 3-5：Gross Regional Domestic Product at 2000 Constant Market Prices by Provinces in Java Island,

2000 - 2013 (Billion Rupiahs)

(Source: BPS STATISTIK INDONESIA)

-

10,000

20,000

30,000

40,000

50,000

60,000

2000 2010 2015* 2020* 2025* 2030* 2035*

Banten

DKI Jakarta

Jawa Barat

Jawa Tengah

DI Yogyakarta

Jawa Timur

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

Rp-

Rp200,000

Rp400,000

Rp600,000

Rp800,000

Rp1,000,000

Rp1,200,000

Rp1,400,000

Rp1,600,000

Rp1,800,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Jawa Timur

DI Yogyakarta

Jawa Tengah

Jawa Barat

DKI Jakarta

Banten

GDP growth rate （Java Island）

3-5

3.2 Demand

3.2.1 Demand record

The power system on the Java Island of Indonesia is connected with the one of Bali Island, and is integrally

operated as Jawa-Bali power system. The maximum power demand of Jawa-Bali power system in 2014 was

33,321MW, which was equivalent to 72 % of the entire power demand in Indonesia including Sumatra Island and

others. Electricity sales of 2014 in the power system were approximately 150TWhs, which were equivalent to

18% of the total electricity sales of nine utilities in Japan. Table 3-1 shows electricity sales records by region in

Jawa-Bali power system

Table 3-1 Electricity sales records by region in Jawa-Bali power system

Unit: TWh per Year

Region 2009 2010 2011 2012 2013 2014)

Average

from 2009 to

2014

Jawa-Bali 104.1 113.4 120.8 132.1 142.1 149.9

Growth rate 3.3 8.9 6.5 9.3 7.6 5.5 7.1

Sumatera 17.6 19.7 21.5 24.2 25.8 27.9

Growth rate 7.2 11.6 9.3 12.6 6.4 8.2 9.4

Kalimantan 4.7 5.1 5.7 6.4 7 7.8

Growth rate 9.7 10.3 10.1 12.9 9.6 11.8 10.5

Sulawesi 4.6 5.1 5.6 6.4 7.3 7.8

Growth rate 8.8 10.7 11 13.7 13.3 7.7 11.5

Maluku, Papua & Nusa

Tenggara 2.2 2.4 2.7 3.1 3.6 4.0

Growth rate 9.7 10.7 13 16.1 13.8 11.4 12.7

Indonesia 133.1 145.7 156.3 172.2 185.7 197.3

Growth rate 4.3 9.4 7.3 10.2 7.8 6.3 7.8

*) Estimated value

(Source: RUPTL 2015-2024)

The electricity sale growth has been decreasing since 2013. Especially Jawa-Bali system was the worst among

all Indonesia. This was due to the slowdown in the Indonesian economy and electricity tariff raises.

3.2.2 Demand forecast

Figure 3-6 compares some demand forecasts. Minister of Energy and Mineral Resource (MEMR) issued the

General National Power Plan, (RUKN), which was the comprehensive power development plan based on the

national energy policies, then PLN developed the RUPTL in accordance with the RUKN.

3-6

Figure 3-6 Comparison of demand forecasts


The latest RUPTL 2015-2024 revised the demand forecast downward since 2019 from the Draft RUKN

2015-2034.

The demand forecast in the previous report conducted in 2008 was in accordance with the RUPTL 2007. Figure

3-7 compares the demand forecast of Jawa-Bali power system in the RUPTL 2007 and the demand record of the

same power system. There was little difference in the demand with the previous report. Figure 3-7 also shows

demand forecast of Jawa-Bali power system based on the RUPTL 2015-2024.

Figure 3-7 Comparison of the demand forecast with the previous study

(Source: Created by the survey team in accordance with RUPTL 2015-2024 and RUPTL 2007)

3-7

3.2.3 Power generation development plan

Table 3-2 shows the demand forecast and generation development plans of the total Jawa-Bali power system in

the RUPTL 2015-2024. There was enough generation reserve margin till 2024 this RUPTL.

Table 3-2 Demand forecast and generation development plans of the total Jawa-Bali power system in

RUPTL 2015-2024 Unit: MW

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Total available

power 32,757 34,738 37,426 42,172 54,024 55,172 57,306 59,463 62,767 65,550

Demand 25,875 27,840 29,993 32,213 34,578 37,103 39,960 43,031 46,376 49,934

Demand and

Supply Balance 6,882 6,898 7,433 9,959 19,446 18,069 17,346 16,432 16,391 15,616

Reserve Margin 27% 25% 25% 31% 56% 49% 43% 38% 35% 31%


Specific generation development plans are listed in Table 3-3.

3-8

Table 3-3 Generation development plan in the Jawa-Bali power system


Project Type 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Pembangkit PLN on Going and Committed

Tj. Awar-awar (FTP1) PLTU1 350

Adipala (FTP1) PLTU 660

Indramayu #4 (FTP27) PLTU 1,000

Upper Cisokan PS (FTP2) PLTA2 1,040

Peaker Pesanggaran PLTMG3 200

Sub Total PLN on Going & Committed 860 350 1,915

Pembangkit IPP on Going and Committed

Celukan Bawang PLTU 380

Banten PLTU 625

Sumsel-8 MT PLTU 1,200

Sumsel-9 MT (PPP) PLTU 600 600

Sumsel-10 MT (PPP) PLTU 600

Cilacap exp PLTU 614

Jawa Tengah (PPP) PLTU 1,900

Rajamandala PLTA 47

Patuha (FTP2) PLTP4 110

Kamojang-5 (FTP2) PLTP 30

Karaha Bodas (FTP2) PLTP 30 110

Tangkuban Perahu 1 (FTP2) PLTP 55 55

Ijen (FTP2) PLTP 110

Iyang Argopuro (FTP2) PLTP 55

Wilis/Ngebel (FTP2) PLTP 55 110

Cibuni (FTP2) PLTP 10

Tangkuban Perahu 2 (FTP2) PLTP 60

Cisolok - Cisukarame (FTP2) PLTP 50

Ungaran (FTP2) PLTP 55

Wayang Windu 3-4 (FTP2) PLTP 220

Dieng (FTP2) PLTP 55 55

Tampomas (FTP2) PLTP 45

Baturaden (FTP2) PLTP 110 110

Guci (FTP2) PLTP 55

Rawa Dano (FTP2) PLTP 110

Umbul Telomoyo (FTP2) PLTP 55

Gn. Ciremai (FTP2) PLTP 110

Gn. Endut (FTP2) PLTP 40

Sub Total IPP On Going & Committed 1,024 655 47 - 1,770 3,575 1,040 205 110 -

Rencana Tambahan Kapasitas

Jawa-1 (Load Follower ) PLTGU5 1,600

Jawa-2 (Load Follower ) PLTGU 800

Jawa-3 (Load Follower ) PLTGU 800

Muara Tawar Add-on Blok 2,3,4 PLTGU 650

Grati Add-on Blok 2 PLTGU 150

Peaker Muara Karang PLTGU 500

Peaker Grati PLTGU 300 150

Peaker Jawa - Bali 1 PLTGU/ MG6 400

Peaker Jawa - Bali 2 PLTGU/ MG 500

Peaker Jawa - Bali 3 PLTGU/ MG 500

Peaker Jawa - Bali 4 PLTGU/ MG 300 150

Karangkates #4-5 PLTA 100

Kesamben PLTA 37

Jatigede (FTP2) PLTA 110

Matenggeng PS PLTA 450 450

Indramayu #5 PLTU 1,000

Lontar Exp #4 PLTU 315

Jawa-1 (FTP2) PLTU 1,000

Jawa-3 (FTP2) PLTU 660 660




Jawa-7 PLTU 2,000

Jawa-8 PLTU 1,000

Jawa-9 PLTU 600

Jawa-10 PLTU 660

Jawa-11 PLTU 600

Jawa-12 PLTU 1,000 1,000

Jawa-13 PLTU 2,000

Bedugul PLTP 10

Total additional rated power MW 1,884 1,755 2,897 5,115 13,005 2,162 2,300 2,325 3,560 3,000

Total rated power of generators MW 35,304 37,439 40,336 45,451 58,224 59,461 61,761 64,086 67,646 70,646

Total net power of power plants MW 32,757 34,738 37,426 42,172 54,024 55,172 57,306 59,463 62,767 65,550

1. PLTU : Steam Power Plant2. PLTA : Hydro Power Plant3. PLTMG : Gas Engine Power Plant4. PLTP : Geothermal Power Plant5. PLTGU : Combined Cycle Power Plant, which is high efficiency multi generators system mainly fueled by gas.6. PLTGU/ MG : PLTGU or PLTMG7. FTP2 : Fast Track Program II; Pursuant to President Regulation No.4/2010, PLN was assigned to build coal-fired steam power plants with a total capacity of 10,000 MW.

3-9

3.2.4 Transmission line projects in RUPTL 2015-2024

The following tables list transmission line projects in Jawa-Bali power system in RUPTL 2015-2024.

Table 3-4 Transmission line projects in the Special Capital Region of Jakarta From To Voltage Conductor type Length(km) COD

Bekasi Tx. Mtawar-Cibinong 500 kV 2 cct, 4xDove1 12 2016

Cawang Baru (GIS) Gandul 500 kV 2 cct, 4xZebra 40 2017

Kembangan Durikosambi (GIS) 500 kV 1 cct, 4xZebra 6 2017

Tx Kembangan Durikosambi (GIS) 500 kV 1 cct, 4xZebra 6 2017

Priok Muaratawar 500 kV 2 cct, 1xCU2500 30 2018

Priok Muarakarang (GIS) 500 kV 2 cct, 1xCU2500 20 2018

Muarakarang (GIS) Durikosambi (GIS) 500 kV 2 cct, 4xZebra 30 2018

PLTU Jawa-5 Balaraja 500 kV 2 cct, 4xZebra 60 2021

Total 204


Table 3-5 Transmission line projects in Banten province From To Voltage Conductor type length(km) COD

Bojanegara Balaraja Baru 500 kV 2 cct. 4xDove 120 2015

Suralaya Baru Bojanegara 500 kV 2 cct. 4xDove 32 2015

PLTU Banten Inc2.(Suralaya Baru- Balaraja) 500 kV 2 cct. HTLSC (4xDove) 40 2016

Lengkong 500 kV Inc. (Blrja-Gndul) 500 kV 4 cct. 4xDove 4 2017

Balaraja Kembangan 500 kV 1 cct. 4xZebra 80 2017

Bogor X Tpcut 500 kV DC 2 pole. HVDC OHL3 220 2019

Bogor X Inc (Clgon-Cibinong) 500 kV 2 cct. 4xDove 60 2019

Bogor X Inc (Depok-Tsmya) 500 kV 4 cct. 4xDove 6 2019

Tpcut Keteranganapang 500 kV DC 2 pole. HVDC CABLE 80 2019

PLTU Jawa-7 Inc(Suralaya Baru - Balaraja) 500 kV 4 cct. HTLSC (4xDove) 20 2019

Bojanegara Balaraja Baru 500 kV 2 cct. HTLSC (4xDove) 120 2019

Suralaya Baru Bojanegara 500 kV 2 cct. HTLSC (4xDove) 32 2019

Balaraja Gandul 500 kV 2 cct. HTLSC (4xDove) 92 2019

Suralaya Lama Balaraja 500 kV 2 cct. HTLSC (4xDove) 129 2020

Total 1,035


As the abouve Table 3-5, reconductoing the Balaraja-Gandul transmission line is planed in 2019 and

reconducting Suralaya (Lama) -Balaraja transmission line is planned in 2020.

1 4xDove: Four bundle conductor: Dove is a code word of an ACSR 2 Inc: the transmission line for interconnection substation or power plant which will be built between the existing transmission lines 3 OHL: Overhead Line

3-10

Table 3-6 Transmission line projects in West Jawa province From To Voltage Conductor type length(km) COD

Tambun 500 kV Inc. (Bkasi-Cibinong) 500 kV 2 cct, 4xDove 2 2016

Bandung Selatan Inc. (Tasik-Depok) 500 kV 2 cct, 4xGannet 4 2016

Delta Mas Inc. (Cbatu-Cirata) 500 kV 4 cct, 4xGannet 8 2017

Cikalong Dbphi. (Tasik-Depok) 500 kV 4 cct, 4xGannet 4 2017

Cibatu Baru Inc (Muaratawar-Cibatu) 500 kV 4 cct, 4xGannet 20 2018

PLTGU Jawa-1 Cibatu Baru 500 kV 2 cct, 4xZebra 80 2018

Mandirancan Bandung Selatan 500 kV 2 cct, 4xZebra 118 2019

Upper Cisokan

Incomer (Cibng-Sglng) 500 kV 2 cct, 4xGannet 30 2019

PLTU Jawa-1 Mandirancan 500 kV 2 cct, 4xZebra 116 2019

Indramayu Delta Mas 500 kV 2 cct, 4xZebra 260 2019

Suralaya Lama Suralaya Baru 500 kV 1 cct, 4xZebra 2 2019

PLTU Jawa-3 Switching S/S Jawa-3 Inc 500 kV 4 cct, 4xZebra 40 2021

Matenggeng PLTA Inc (Tasik-Rawalo) 500 kV 2 cct, 4xDove 20 2022

Total 704


Table 3-7 Transmission line projects in Central Jawa province From To Voltage Conductor type length(km) COD

Rawalo/Kesugihan Dbphi (Pedan-Tasik) 500 kV 4 cct, 4xGannet 4 2015

Rawalo/Kesugihan PLTU Adipala 500 kV 2 cct, 4xZebra 28 2015

PLTU Cilacap Exp Adipala 500 kV 2 cct, 4xDove 10 2015

Tanjung Jati B Tx Ungaran 500 kV 2 cct, 4xZebra 260 2016

Ampel Inc (Ungaran-Pedan) 500 kV 2 cct, 4xGannet 2 2017

PLTU Jateng Pemalang 500 kV 500 kV 2 cct, 4xZebra 40 2019

PLTU Jawa-12 (KBN) Inc (Muaratawar - Priok) 500 kV 2 cct, 1xCU2500 10 2019

Tx Ungaran Pemalang 500 kV 2 cct, 4xZebra 63 2020

Pemalang Indramayu 500 kV 2 cct, 4xZebra 256 2020

Ungaran Pedan 500 kV 1 cct, 4xZebra 60 2020

Total 733


Table 3-8 Transmission line projects in East Jawa province From To Voltage Conductor type length(km) COD

Surabaya Selatan Grati 500 kV 2 cct, 4xGannet 160 2015

Bangil Inc. (Paiton-Kediri) 500 kV 2 cct, 4xGannet 4 2017

Paiton Watu Dodol 500 kV 2 cct, 4xZebra 262 2018

Watu Dodol Segararupek 500 kV 2 cct, ACS 380 8 2018

Tandes Gresik 500 kV 2 cct, 4xZebra 24 2018

Total 458


3-11

Table 3-9 Transmission line projects in Bali province From To Voltage Conductor type length(km) COD

Gilimanuk Antosari 500 kV 2 cct, ACSR 4xZebra 185 2018

Segararupec Gilimanuk 500 kV 2 cct, ACSR 4xZebra 20 2018

Total 205


3.3 Review of the previous report

3.3.1 Necessity study in the previous report in 2008

The previous study “Study on Upgrading Transmission Capacity of Existing 500kV Lines in West Java,

Indonesia” was carried out in fiscal year 2007 by Tokyo Electric Power Services Co., Ltd (TEPSCO) and

Mitsubishi Corporation. Essential conditions such as the total demand forecast, generation expansion plans and

transmission equipment augmentation plans were based on the RUPTL 2007 for the system analyses, while

demand at each substation and output power from each generator were revised from this RUPTL as the latest

information at that time.

a Generation expansion plan in the western region of Java-Bali power system in the RUPTL 2007

The table below shows existing and planned generator capacities in the RUPTL 2007.

Table 3-10 Power development projects in the west Java area

Unit：MW

Site Existing 2008 2009 2010 2011 2012 -16 Capacity at the end

of 2016

Suralaya 3,400 - - 600 - - 4,000

Cilegon 740 - - - - - 740

Teluk Naga - - 300 600 - - 900

Anyner - - - - 300 - 300

Labuan - - 600 - - - 600

Total 4,140 - 900 1200 300 - 6,540

(Source: RUPTL 2007)

The figure below illustrates locations of planned generators noted in the above table.

3-12

Figure 3-8 Locations of new generators planned in the RUPTL 2007

(Source: RUPTL 2007)

b Target years for system analyses

As shown in the table above, large scale power development projects were expected to be completed during

2009 and 2010. Thus, system analyses were conducted under the conditions including demand and generation

expansions in 2010 and 2016, which was the time horizon year in the RUPTL 2007.

c Revised system configuration in 2016

On the basis of the latest generator connection plans as of then, system analyses were conducted under the

conditions of the revised connection of a new power plant (Bojonegara) as illustrate below.

3-13

Legend Connection plan in the RUPTL 2007 Revised connection plan

Figure 3-9 Revised connection of a new power plant at Bojonegara

Muara Tawar

Cawang

Bekasi

Cibinong

Depok

Gandul

Kembangan

Balaraja

Suralaya

Cilegon

Bojonegara

(Source: Created by the survey team from “Study on Upgrading Transmission Capacity of Existing 500kV Lines in West Java,

Indonesia”, 2007, JICA)

d Results of power flow analyses

The figure below illustrates power flow diagram in 2010. A Number in black letter with an arrow means

power flow under the normal (N-0) condition without any outage. Regarding the transmission line between

Suralaya and Balaraja, 2,586MW in black means the total power flow of two circuits under the normal (N-0)

condition without any outage. 2,332MW in red means power flow though the healthy circuit under the N-1

condition with the same section outage. Since load-carrying capacity of the existing transmission line is 1,628MW,

healthy circuit of Suralaya–Balaraja transmission line would be overloaded under the N-1 conditions with one

circuit outage of the same transmission line as expressed in the inequality below.

2,332MW>1,628MW

Regarding the transmission line between Balaraja and Gandul, 1,505MW in blue means power flow though the

healthy circuit under the N-1 condition with the same section outage. Healthy circuit of Balaraja-Gandul

transmission line would not be overloaded under the N-1 conditions with one circuit outage of the same

transmission line as expressed in the inequality below.

1505MW<1,628MW

3-14

Figure 3-10 Power flow in West Java Network (2010)

115

473

Cibinong

Depok

661

Gandul

319 Kembangan

699

Balaraja

318098

Suralaya

-219

Cilegon

917

319

880 759

560139

N-Suralaya

421

1873(1505)

1135(1389)(1398)

2586(2332)

( ):Contingency of 1circuit Red : Suralaya-Balaraja Blue : Balaraja-Gandul

Transmitting Cap.(2472A)

2033MW (PF0.95)

Transmitting Cap.(1980A)

1628MW (PF0.95)

Unit (MW)

(Source: “Study on Upgrading Transmission Capacity of Existing 500kV Lines in West Java, Indonesia”, 2007, JICA)

1,654MW in blue means power flow though the healthy circuit between Balaraja and Gandul under the N-1

condition with the same section outage. Healthy circuit of Balaraja-Gandul transmission line would be overloaded

under the N-1 conditions with one circuit outage of the same transmission line as expressed in the inequality

below.

1,654MW>1,628MW

Figure 3-11 Power flow in West Java Network (2016)

565Depok

1014

Gandul

529

Kembangan

Balaraja

2387160

Suralaya

354

Cilegon

Bojonegara

1459

1777

1420

530

244 1064

Lengkong

550226

N-Suralaya

324

1254(1654)

448

858

22501565685

DC

3000

Parung

18771995

539

( ):contingency ofBalaraja-Gandul

534

901

Unit (MW)

(Source: “Study on Upgrading Transmission Capacity of Existing 500kV Lines in West Java, Indonesia”, 2007,

e Construction year

It would take about one and half year to reconductor the transmission line. During the relatively long

reconductoring period, generator output would have to be suppressed to some extent at Suralaya power plant.

Considering the supply demand balance in Java-Bali power system, the previous report recommended that the

reconductoring start from 2010, when supply power was expected to be more sufficient than previous years.

3-15

f Power flow analyses during the reconductoring work

Suralaya-Balaraja transmission line would be overloaded during the reconductoring work under the same

conditions noted above. To prevent from this overloading, output from Suralaya power plant had to be suppressed

by 1,200MW (from 3,740MW to 2,540MW) in the power flow analyses.

g Stability analyses

Stability analyses were conducted under the conditions in 2010 during the reconductoring work. The system was

stable even under these very severe conditions.

h Conclusion of the previous report

From the power flow and stability analysis results shown above, the previous report concluded that the

transmission lines between Suralaya and Gandul needed to be reconductored.

i Review of the previous report with regard to the system analyses

Suralaya-Balaraja transmission line was expected to be overloaded due to connections of new generators

listed in Table 3-10. Reconductoring of this transmission line should have been implemented earlier than the

connections of those new generators in an ordinary manner. From the results of power flow analyses,

Suralaya coal fueled power plant including a new generator would be forced to suppress its output power

during the reconductoring work. It was unusual for the just expanded power plant to be forced to suppress its

output in general. This previous report recommended this reconductoring be started the implementation in

2010 because additional supply power was expected to be sufficient as of then owing to the “Crash

Program”.

However, this program did not work well as expected due to the shortage of fund and poor performance of

the coal power plants mainly provided by Chinese manufacturers. The survey team considers in this study

that that situation can be said rather accidental under the circumstance that the transmission lines should have

been upgraded if the new plant started its operation on planned schedule.

Taking those into consideration, the proposal by the former survey team at the previous report in 2008, the

year before the financial service firm Lehman Brothers was filed for Chapter 11 bankruptcy protection,

which recommended the reconductoring of the existing transmission line rather than time-consuming

construction of a new transmission line, was deemed to be proper recommendation under the economic

situation with very tight gap between supply and demand in electricity in the country at the time.

4-1

Chapter4. System Analysis

4.1 Conducted survey

Before the connection of new generators with the power grid or when the augmentation necessity of

transmission facilities is confirmed, the transmission system reliability has to be analyzed. If any problems are

expected to occur through power flow, fault current, and stability analyses, some measures have to be prepared.

System analyses conducted by the Study Team include the following.

• Power flow analysis

• Fault current analysis

• Stability analysis

4.2 Analysis condition

4.2.1 Target year

Table 4-1 lists generation expansion plans which affect loading condition of the transmission line between

Suralaya power plant and Gandul substation.

Table 4-1 Generation expansion plan which affect the loading condition of the transmission line between

Suralaya(Lama) power plant and Gandul substation

Power plant Connecting point Rate output power COD

Banten #1 Banten S/S 660MW 2017

Jawa-9 Banten S/S 600MW 2019

Jawa-5 Tanara S/S 1000MW 2019

1000MW 2020

Jawa-7 Bojonegara S/S 1000MW 2019

1000MW 2020 (Source: Information from P3B-JB)

The following Figure 4-1 illustrates the connecting points of the new generators listed in Table 4-1. From those

connecting points and the year of the connection, the survey team assumed that the second unit of Jawa-5 and the

second unit of Jawa-7 would be a trigger to cause heavy loading of the Suralaya-Gandul transmission line. Thus,

the survey team deemed that this study should be conducted under the conditions in 2020 as the target year.

4-2

Figure 4-1 Generation expansion plan in the north western region of Jawa-Bali grid

(Source: Information from P3B-JB)

4-3

4.2.2 Latest transmission augmentation plans in the northwestern region of Jawa-Bali

system

The latest information of transmission augmentation plans in the Special Capital Region of Jakarta and in

Banten province was provided by PLN.

Table 4-2 Transmission line projects in the Special Capital Region of Jakarta

From To Voltage Conductor type Length (km) COD

Bekasi Tx. Muara Tawar-Cibinong 500kV 2 cct, ACSR 4xDove4 12 2016

Kembangan Durikosambi (GIS) 500kV 2 cct, ACSR 4xZebra 6 2018

Muarakarang (GIS) Durikosambi (GIS) 500kV 2 cct, ACSR 4xZebra 30 2018

Priok Muara Tawar 500kV 2 cct, ACSR 4xZebra 30 2019

Priok Muarakarang (GIS) 500kV 2 cct, ACSR 4xZebra 20 2019

Cawang Baru (GIS) Gandul 500kV 2 cct, ACSR 4xZebra 40 2020

Total 138


Table 4-3 Transmission line projects in Banten province

From To Voltage Conductor type Length (km) COD

Bojanegara Balaraja Baru 500 kV 2 cct, ACSR 4xDove 120 2016

PLTU Banten Inc.5(Suralaya Baru-Balaraja) 500 kV 2 cct, HTLSC (Existing

40 2016

Suralaya Baru Bojanegara 500 kV 2 cct, ACSR 4xDove 32 2016

Balaraja Kembangan 500 kV 2 cct, ACSR 4xZebra 80 2017

Lengkong Inc. (Balaraja-Gandul) 500 kV 4 cct, HTLSC (Existing

8 2017

Suralaya(Lama) Suralaya Baru 500 kV 1 cct, ACSR 4xZebra 1 2018

Bogor X Inc. (Depok-Tasikmalaya) 500 kV 4 cct, ACSR 4xDove 6 2019

Bogor X Inc. (Cilegon-Cibinong) 500 kV 2 cct, ACSR 4xDove 60 2019

Bogor X Tanjung Pucut / Salira 500kV DC 2 cct, 2 pole, HVDC OHL6 220 2019

Bojanegara Balaraja Baru 500 kV 2 cct, HTLSC (Existing

120 2019

PLTU Jawa-7 Inc.(Suralaya Baru-Balaraja) 500 kV 4 cct, HTLSC (Existing

20 2019

Suralaya(Lama) Balaraja 500 kV 2 cct, HTLSC (Existing

129 2019

Tanjung Pucut / Salir Kaetapang 500kV DC 2 cct, HVDC CABLE 80 2019

Balaraja Gandul 500 kV 2 cct, HTLSC (Existing

92 2020

Suralaya Baru Bojanegara 500 kV 2 cct, HTLSC (Existing

32 2020

Total 1,040


As listed in Table 4-3, PLN has plans to reconductor the transmission lines between Suralaya (Lama) and

Balaraja in 2019 and between Balaraja and Gandul in 2020. Those projects might be changed in the next RUPRL

4 4xDove: Four bundle conductor: Dove is a code word of an ACSR 5 Inc.: the transmission line for interconnection substation or power plant which will be built between the existing transmission

lines 6 OHL: Overhead Line

4-4

2016-2025, which will be released soon, the Study Team conducted system analyses under these transmission line

augmentation conditions as the latest ones.

Figure 4-2, Figure 4-3, and Figure 4-4 illustrate transmission augmentation and relevant generation expansion

plans with their CODs.

Figure 4-2 Latest generation expansion and transmission augmentation plans during 2016-2018

(Source: Created by the survey team from information provided by P3B-JB)

4-5

Figure 4-3 Latest generation expansion and transmission augmentation plans in 2019


4-6

Suralaya (Lama) Suralaya Baru

BojonegaraJawa - 71000MW, 20191000MW, 2020

BalarajaKembangan

Gandul

Lengkongl

Jawa - 51000MW, 20191000MW, 2020

ReconductoringBalaraja - Gandul,

129km

ReconductoringSuralaya Baru -Bojonegara, 32km,

BantenBanten-1 (660MW), 2017Jawa-9 (600MW), 2019

A

Figure 4-4 Latest generation expansion and transmission augmentation plans in 2020


4-7

4.2.3 Demand assumptions

Jawa-Bali power system can be divided into five demand areas from area I to area V as shown in Figure 4-5.

Figure 4-5 Demand areas of five in Jawa-Bali grid

(Source: RUPTL 2015 and information from P3B-JB)

From the interview with P3B-JB, the recorded peak demand during the daytime had been growing year after

year more than the recorded peak demand during the nighttime in all five demand areas in Jawa-Bali power

system, and P3B-JB projected this trend would continue in future. The peak demand of the area-I during the

daytime was already higher than the peak demand during the nighttime in the said area as of year 2015. According

to P3B-JB, this maximum demand time shift from night to day would occur during 2019 and 2020 in the whole

Jawa-Bali power system.

In general, transmission lines in the generation rich area do not necessarily tend to be heavily loaded under the

maximum demand condition. If generated power from power plants is large in the area-I and demand of the said

area is small, the evacuated power will cause Suralaya(Lama)-Gandul transmission line to be heavily loaded.

Evacuated power from Suralaya Baru and Lama power stations to Gandul substation was larger in the night

peak time than the day peak time since the demand in the night peak time was smaller than the one in the day peak

time. Thus, the survey team assumed that analyses would be conducted under the conditions of night peak demand

in 2020 as a conservative condition.

4.2.4 Loading conditions of generators

The power grid, which consists of transmission lines, transformers, etc., should be constructed so as not to

restrict power plant operations. The survey team assumed that generators in the northwestern region (Area I) of

Jawa-Bali power system generated at the rated power as a conservative viewpoint. Other generators were assumed

to generate at about 45% of the rated power to balance the supply and demand in the whole Jawa-Bali power

system as shown in Figure 4-6.

VI I I

I

I

V

4-8

Figure 4-6 Loading conditions of generators in Jawa-Bali power system

(Source: RUPTL 2015 and information from P3B-JB)

Table 4-4 summarizes the supply – demand balance in Jawa-Bali power system for the system analyses as

reference.

PRATU LBSTU

SGLNG

CGRLG

CRATA

JTAKE

CKNDE

CITRATGRSA

SRPNGDPK2

BKASI

CWANG

CNJUR

SALAK BARU

BUNAR

RKBTG

TSMYA

MTWARTLNGA

SPTAN

MENES

SKETI

SRANG

ASAHI

MTSUI

SLAYA SLIRA

BGBRU

DEPOK

CMGISCIBNG

PRYMA

PRIOKMKRNG

UU

UPLTU LBUAN

NBLRJA

A

BAYAH/CEMINDO

KRCAK

SLAYA2

PKMIS

MPING

PCADM

KOPO

CWANG2

CBATU

BUNAR II

CBTBR

UBRUG

HVDC

DUKSMBI

PLTU BANTEN

TGRNG

CKRNG

TMBUN

U

CLGMA

KMBNG

BOGOR X

SRANG II

GNDUL

PCADM IIIDMYU7

CBDKBR

U

CIAWI

SALAK LAMA

NTGRNGPLTU LONTAR

U

PLTU PRATU

CLGON

LEGOK

PTKNGBNTRO

CKUPA

KSTEL

PRETYPENI

KDBDK

P

CLGN 2

SURADE

TJLSNG

TOJNG/SRANG III

CNDRAASRI

ASAHI III

ASAHI II/CNGKA

NKOMAS

IDKIAT

IDFERO

LAUTSTELSPINMIL

MILENIUM

SENTULITP SCBNG

SOETTABLRJA

CILEDUG

PRWDNO

CURUG

ALMSUTRA

BGRKT

TAJURCIOMAS

SMTRKIEC

LKONG

BSD/LKONGIII

RJMDLAA

CIPANAS

CMGISII

TNGGEUNG

SMNJWA

CIAWI II

CBDKBRII/CCRUG

P CSLOKCSKRME

PGNENDUT

PLTGU JAWA-12 x 800 MW

U

SMTRCKNDE

GORDA

GI 150 KV BARU TERKAIT KTTGI 150 KV BARUGI 150 KV EKSISTING

GITET 500 KV EKSISTING

GITET 500 KV BARU

GI 70 KV EKSISTING

LEGENDA :

U

U PLTU 2x1.000 MW

POSCO

GU

CLGON

PRATU/JMPGKULON

1x660 MW

Region where generators generated at the rated power

Region where generators generated at 45% of the rated power

4-9

Table 4-4 Supply–demand balance in Jawa-Bali power system for system analyses7

Region

Adjusted power from

generators Demand Balance (MW),

(MW), (A) (MW), (B) (A) - (B)

I RJKB 15,045.6 14,413.0 632.6

II RJBR 8,030.4 7,309.0 721.4

III RJTD 5,343.5 4,896.9 446.6

IV RJTB 4,778.3 6,847.0 -2,068.7

V SRB 750.0 1,116.0 -366.0

VI SMRT 1,230.2 0.0 1,230.2

TOTALS 35,178.0 34,581.9 596.1

(Source: Result of PSS/E power flow analysis provided by P3B-JB)

4.2.5 Allowable voltage range

According to the connection code of P3B, allowable voltage range in 500 kV system is ±5% under the normal

(N-0) conditions. Although the connection code did not give a voltage range under N-1 conditions, the survey

team assumed the same range as N-0 conditions for N-1 conditions on a conservative standpoint.

4.2.6 Transmission line capacity

Transmission line capacity was given as the apparent power8 for the power system planning in P3B-JB.

Overloading9 of transmission lines were not allowed under N-0 and N-1 conditions for the power system

planning in P3B-JB.

4.2.7 Other conditions for the system analyses

On the basis of the agreement on the conditions for the system analyses with P3B-JB on Nov. 10 during the

second mission, a new 500 kV/150 kV substation which was not listed in the latest RUPTL 2015 -2024 was

assumed to start the operation from 2019. According to B3B-JB, the new substation would be constructed as a

measure against the heavy-loading of Balaraja and Kembangan substations. However, the location of this new

substation had not been decided yet as of then.

7 Difference between the total supply and total demand means transmission loss (35,178.0MW-34,581.9MW=596.1MW). Since

area I, II, III is supply rich areas, the power flowed will flow from the west to east in this study. 8 The apparent power (S) is defined as a kind of AC power that is computed by multiplying the current (I) by the voltage (V): S

= I x V Apparent power is measured in the unit of Volt-Amps (VA) 9 If the apparent power is larger than the equipment capacity, the transmission line is overloaded.

4-10

~~

~

~

~

~

Suralaya #8 =625.0 MW

Suralaya #1-7 =3400.0 MW

Jawa 9 =600.0 MW

Jawa 7 =2000.0 MW

Banten #1 =660.0 MW

Jawa 5 =2000.0 MW

17016SLAYA7 501.0 501.0

17003BLRJA7 502.8

17005CLGON7 500.8

557

.127

.8

557.

1 2

8.7

567

.720

.4

567.

8 2

1.4

153

3.8

224.

2

1547

.1 1

22.7

153

3.8

224.

2

1547

.1 1

22.7

700

.720

.970

1.2

27.

4

700

.720

.970

1.2

27.

4

15226BOGORX7-HVDC 514.5 1

540.

546

1.9

1562

.4 2

97.3

17263BNTEN7

501.1

283

.2 1

1.8

283.29.9

283

.2 1

1.8

283.29.9

501.2

346.8 54.7

346.638.8

346.8 54.7

346.638.7

133

5.6

180.

3

1346.7 114.1

133

5.5

180.

3

1346.6 114.1

17301BJGRA7

509.8

17203CKUPA7 503.4502.4

1390

.9 3

68.2

1384.8

416.

8

1390

.9 3

68.2

138

4.8

416.

8

1935

.1 2

23.9

193

1.3

259.

3

1935

.1 2

23.9

193

1.3

259.

3

998

.398

.0

1000

.0 9

7.4

998

.398

.0

1000

.0 9

7.417302

TNARA7

17197LKONG7 1

559.

341

4.0

1561

.8 3

93.8

155

9.3

414.

015

61.8

393

.8

17010GNDUL7

509.6

1004.2443.0

1006

.6 4

38.0

1004.2443.0

1006

.6 4

38.0

172.2 12.3

172.

2 1

9.3

172.2 12.3

172.

2 1

9.3

505.1

17011KMBNG7

17017SLAYA7-2

25% I

26% I

78%

I

78% I

32%

I

32%

I72

% I

14%

I 14%

I

18% I

18% I

68%

I

68%

I

55% I

55% I

98%

I

98%

I

38% I

38% I

81%

I

81%

I 55% I

55% I

8% I

8% I

Cilego

Banten

Lengkong

Tanara

Bojonegar

Kembang

Gan

A

Balaraj

Bogor X

Gandul

4.3 Power flow analyses

4.3.1 Result of power flow analyses under the normal (N-0) conditions before

reconductoring

The Survey Team conducted a power flow analysis on the night peak demand in 2020 without any outage before

reconductoring. From the result of power flow analysis, the Survey Team found neither overloaded equipment nor

voltage range violations under the N-0 conditions.

Figure 4-7 Result of power flow analysis under N-0 condition

(Source: Results of the PSS/E power flow analyses)

Suralaya

(Lama)

Suralaya Baru #8 625MA

Legend Voltage (kV)

Upper row: Active power (MW) Lower row: Reactive power (MVar)

Loading ratio which is calculated by current as a

4-11

4.3.2 Result of power flow analyses under the N-1 conditions

P3B-JB and the survey team conducted N-1 contingency analyses together to confirm the necessity of

transmission line reconductoring between Suralaya(Lama) and Gandul substations. In this study, power flow

analyses were conducted under the conditions of one circuit outage. Results of the analyses were summarized in

Table 4-5. The loading ratio, which was defined as the ratio of power flow in MVA to Nominal rate in MVA is not

allowed to exceed 100% on the planning stage in PLN.

Table 4-5 Results of N-1 contingency analyses Outage circuit Most heavily loaded circuit

among all monitored circuits

Transmission

capacity (MVA10)

Power Flow

(MVA)

Loading

ratio11

(A) (B) (B)/(A)

Suralaya(Lama)-Balaraja Suralaya(Lama) – Balaraja 1,985 2,079 105%

Balaraja-Cikupa Balaraja-Cikupa 1,985 3,443 173%

Cikupa-Lengkong Cikupa-Lengkong 1,985 2,867 144%

Lengkong-Gandul Lengkong-Gandul 1,985 1,740 88%


From the results of these analyses, one circuit outage caused an overloading of the healthy circuit in the same

transmission line section for Suralaya(Lama) – Balaraja, Balaraja – Cikupa and Cikupa – Lengkong sections.

These results meant that reconductoring of the transmission line between Suralaya(Lama) and Lengkong would be

necessary.

Although the power flow loading ratio through Lengkong – Gandul section was less than 100%, the Study Team

conducted a further analysis from a conservative standpoint. As referred to hereinafter, splitting the grid is very

effective to reduce the fault current. P3B-JB and the survey team conducted an N-1 contingency analysis under

the network condition that the transmission line section between Lengkong and Gandul would be switched off as a

conservative configuration condition for the power flow. . Figure 4-8 shows the power flow analysis result under

the N-1 condition with one circuit outage of Lengkong – Gandul section and grid splitting between Kembangan

and Gandul.

As shown in Table 4-6 and Figure 4-8, the healthy circuit between Lengkong and Gandul was overloaded with

103% of loading ratio to its capacity under the conditions with an outage of the same transmission section. Thus,

reconductoring of Lengkong – Gandul section was necessary under this condition.

10 VA: unit of apparent power, M: Mega, 106 11 The loading ratio is defined by a quotient of power flow divided by the transmission capacity

4-12

Suralaya (Lama)


103% (Overload)

A

Normally open

Kembang

Gandul

Table 4-6 Results of N-1 contingency analyses with grid splitting between Kembangan and Gandul Outage circuit Most heavily loaded circuit

among all monitored circuits

Transmission

capacity (MVA)

Power Flow

(MVA)

Loading

ratio

(A) (B) (B)/(A)

Lengkong-Gandul Lengkong-Gandul 1,985 2,05012 103%


Figure 4-8 Result of power flow analysis under the one circuit outage of Lengkong – Gandul section


12 P: Active power, Q: Reactive power, S: Apparent power, Apparent power is calculated by the formula: S=√(P2+Q2) =√(1903.62+761.52) = 2,050

Legend Voltage (kV)

Upper row: Active power (MW) Lower row: Reactive power (MVar)

Loading ratio which is calculated by current as a

4-13

4.3.3 Necessary capacity of reconductored transmission lines

The Survey Team deemed that reconductoring of the 500 kV transmission line from Suralaya (Lama) through

Balaraja to Gandul will be necessary as noted above. Necessary capacity of reconductored transmission line was

3,443MVA (3,976A13) per circuit from the results of power flow analyses jointly conducted by P3B-JB and the

Survey Team within a restricted time frame. However, the reconductored transmission line current carrying

capacity should be larger than the said capacity considering generation development in western Jawa region in

future. Although the Survey Team was not able to obtain data to evidence the future necessary capacity of the

reconductored transmission line, the capacity should be as large as rationally achievable PLN had supposed that

the reconductored capacity was 4,680 MVA (5,404A14).

4.4 Fault current analyses

4.4.1 Conditions for the fault current analyses

On the basis of the agreement with P3B-JB, the survey team assumed the following conditions for the fault

current analyses.

Calculation methodology: Based on IEC 60909.

AC component of the fault current at 500kV buses around northwestern region of Jawa-Bali power system

was monitored.

Type of the fault: Three phase short circuit15

Target year: 2020

The highest fault current level at 500kV system at this time: 50kA16

4.4.2 Result of fault current analysis

Figure 4-9 shows the result of fault current analysis in 2020.

13 Formula: of apparent power S: S(MVA) = √3 ×500kV×Ｉ(A) 14 Same formula above 15 Three phase short circuit current is calculated by the formula: I (pu) = 1/ X (pu) Fault current I and the impedance from the fault point are expressed in the Per Unit method. The fault current varies in inverse

proportion to the impedance. New transmission line constructions and new generator connection with the grid both decrease the impedance.

Impedance: The impedance in the alternating-current circuit is the ratio of voltage to current in ohm. This expression can be deemed to be an extended Ohm's law.

Per Unit method: One of methods to express quantities such as power, current, voltage, and impedance. 1. Define the base capacity, 2. The base current and the base impedance can be calculated, and 3. Power, current, voltage, and impedance are expressed as ratios of the actual values to the base capacities respectively. 16 Estimated maximum fault current which PLN uses on the planning stage.

4-14

Cilego

Bojonegar

Banten

Kembang

Balaraj

Tanara

Bogor X

A

Gandul

Lengkong

Figure 4-9 Result of the fault current analysis in 2020

(Source: Results of the PSS/E fault current analyses)

Suralaya

(Lama)

Suralaya Baru

#8 625MA

Legend 57244.1, -85.1

Fault current value (A), Fault current

angle (deg.)

4-15

Suralaya

(Lama)

Suralaya Baru

#8 625MA

Kembang

Gandul

A

Lengkong

Current analysis in 2016 is shown in Figure 4-10 for comparison.

Figure 4-10 Result of the fault current analysis in 2016


Fault currents at Gandul and Kembangan substations would have been exceeded 50 kA in 2016. Comparing the

results of fault current analyses in 2016 and 2020, Fault currents exceeding 50kA at power plants of Suralaya

(Lama) and Suralaya Baru and substations of Balaraja, Cikupa, Bojonegara, Lengkong and Bogor X would have

been caused by connecting new generators including Jawa 5, Jawa 7, Jawa 9 and Banten.

Legend 57244.1, -85.1


angle (deg.)

4-16

4.4.3 Overview of the rsult of fault current analysis

(1) Overview of the rsult of fault current analysis

Substations and power plants where the fault current at the bus exceed 50 kA are listed in Table 4-7.

Table 4-7 Substations and Power plants where the fault current exceeds 50 kA

Substation / Power plant Fault current

Kembangan 65.7 kA

Balaraja 63.8 kA

Gandul 63.0 kA

Suralaya (Lama) 57.2 kA

Suralaya Baru 56.8 kA

A substation 57.9 kA

Bojonegara 56.0 kA

Lengkong 55.5 kA

Bogor X 53.0 kA (Source: Results of the PSS/E fault current analyses)

Some measures had to be taken against this increased fault current problem. If the situation is not improved, the

following problems would occur.

System stability relies heavily on the fault clearance function of circuit breakers in the power system. If

circuit breakers fail to break the fault current, it will tend to become hard to maintain the system stability,

consequently the risk of black out will be higher and the affected area will be broader.

If circuit breakers fail to break the fault current, the circuit breakers can be damaged. Since it takes

relatively long time to replace those damaged circuit breakers, power system operators will have to operate

the system under certain restrictions for a certain time period.

4-17

4.5 Measures against fault current problems

Some measure(s) will have to be prepared against the said fault current problems as soon as possible. Candidate

directions or measures to take against the fault current increase problem are listed below.

1. To leave the maximum fault current level as it is (50 kA)

(1) Introduction of current limiting reactors

(2) Grid splitting

2. To upgrade the maximum fault current level to 63 kA

(3) Upgrade to 63 kA and grid splitting

(4) Upgrade to 63 kA, grid splitting, and power system augmentation

(5) Upgrade to 63 kA, grid splitting, and introduction of the high impedance transformer

Each measure is explained in the following.

4-18

1. To leave the maximum fault current level as it is (50 kA)

(1) Introduction of current limiters

On the premise that existing equipment17 in substations and power plants is used, introduction of current

limiters18 can be a measure to suppress the fault current during the fault. Due to A current limiting reactor

inserted in series in the grid, the impedance19 from the fault point is to be increased and consequently the fault

current will be decreased20. On the other hand, current through the current limiting reactor causes voltage drops of

the grid around the reactor as an adverse effect. If the voltage decreases to less than the allowable range -5%,

consumer facilities can malfunction. Thus, the installation of shunt capacitor banks, which have a function to

increase the voltage, is usually a practical and feasible countermeasure for the voltage drops. In this case, enough

spaces to install the current limiting reactor and the shunt capacitor banks are necessary. The current limiting

reactor can cause another problem called a DC offset of the fault current. The following figure shows an example

of fault current waveform.

Figure 4-11 DC offset of current through a circuit breaker (image)

Fault current

Fault occurrence Zero-crossing delay period Current zero-crossing

The circuit breaker can break the current only when the alternating current instantaneous value becomes zero.

The current break is completed in the following sequences.

A protective relay detects the fault.

Contacts of the circuit breaker get apart by an actuator of the circuit breaker. Since arcs in the plasma state exist

between contacts at this moment, the current has not been broken. Then, the gas is compressed in a space called a

puffer in the circuit breaker simultaneously with the contacts actuator.

The puffer naturally blows the compressed gas at the contacts to lower the arc temperature.

When current crosses the zero, the arcs get extinguished.

17 There are two specifications of circuit breakers in substations and power stations, 40kA and 50kA. 18 500kV current limiting reactors have been introduced at Yanghang substation in Shanghai, China in October 2014. 19 Impedance: The impedance in the alternating-current circuit is the ratio of voltage to current in ohm. This expression can be

deemed to be an extended Ohm's law. 20 The three phase short circuit fault current varies in inverse proportion to the impedance.

Dc component attenuation

(file zm1.pl4; x- var t) c:X0012A- BEG2A 0.00 0.05 0.10 0.15 0.20 0.25 0.30[s]

- 2

0

2

4

6

8

10

12

14[kA]

4-19

If contacts of a circuit breaker physically get apart under the conditions that the current does not become zero,

an arc or arcs will continue to exist between the contacts. After the circuit breaker operation ends and compressed

gas has been used up without extinguishing the arcs, the arcs never can be extinguished by this circuit breaker.

The long lasting fault current would melt the contacts of the circuit breaker and give thermal damage to equipment,

such as disconnector, serially connected with the circuit breaker. If the replacing equipment or parts are imported,

it will take some months. Thus, it can cause long lasting blackout.

Thus this zero-crossing delay period should be short enough to recover from this situation before the circuit

breaker actuation.

The fault current consists of an AC component and a DC component. The DC component exponentially

attenuates with the time constant decided by the power system impedances. This time constant is expressed as the

following formula.

τ = L/R,

where

L (H21): Inductance from the fault point

R (ohm): Resistance from the fault point

If the time constant is short enough, zero-crossing delay period will be also short enough to recover from the

zero-crossing delay situation before the actuation of a circuit breaker.

The current limiting reactor has its own time constant, which is usually much longer than the one of power

system. If the current limiting reactor is inserted in the power system, time constant of DC component attenuation

will become longer, consequently the risk of DC offset problem will increase. The Survey Team would

recommend that PLN conduct analyses of the DC offset problem if the current limiting reactor is introduced.

21 Henry: unit of inductance

4-20

(2) Grid splitting

On the premise that existing equipment in substations and power plants is used, splitting the grid by switching

off some circuit breakers and suppressing the fault current which comes from all generators into the fault point

can be one of measures against the fault current increase.

There are some patterns to split the grid to reduce the fault current as illustrated below, Figure 4-12, Figure 4-13

and Figure 4-14.

Grid configuration change system splitting Figure 4-12 Image of a loop configuration of the grid

(Source: Created by the survey team)

Figure 4-13 Image of a radial configuration Figure 4-14 Image of independent systems

by splitting the grid by splitting22

(Source: Created by the survey team) (Source: Created by the survey team)

22 Independent system operation in Figure 4-14 is not so common. Since supply and demand have to be balanced in each

independent system, system operation would become less efficient in economic load dispatching.

From loop to radial

Splitting into two systems

4-21

Bus split by opening circuit breaker under normal conditions in a substation

Bus splitting under normal conditions can also reduce the fault current. Figure 4-15 illustrates an image of bus

splitting at Gandul substation. Blue filled squares show circuit breakers (CBs) switched on, and void squares show

circuit breakers switched off. Bus-A and Bus-B were split at Gandul substation by switching off some circuit

breakers.

Figure 4-15 Image of bus split at Gandul substation


4-22

Figure 4-16 shows an image of fault current flow under the condition that fault was occurring on one of

Gandul-Lengkong transmission line circuits. Fault current would come from transformer #1 and from Bus B, not

from Bus A. Fault current with bus split would be smaller than the one under the normal bus condition with all

circuit breaker switched on.

Figure 4-16 Image of bus fault current flow under bus split configuration at Gandul substation


4-23

2. To upgrade the maximum fault current level to 63 kA

(3) Upgrade to 63 kA23 and grid splitting

The equipments in substations and power plants which are showed in Table 4-4 should be upgraded. Figure 4-17

shows an example of fault current analysis result to reduce fault currents by opening Kembangan-Gandul

transmission line.

Figure 4-17 Grid configuration change from the loop to the radial by opening Kembangan-Gandul

transmission line


Comparing Figure 4-9 and Figure 4-17, fault currents at 500 kV buses of Kembangan and Gandul substations

was reduced by opening Kembangan-Gandul transmission line, or splitting the grid. However, fault current at the

500 kV bus of Balaraja substation was still larger than 63kA. To reduce the fault current at the 500 kV bus of

Balaraja substation, bus split operation at Balaraja substation would be effective.

23 80kA is listed as a fault current breaking ability level in the IEC standard. However, the 80kA circuit breaker in 500kV system has not implemented in the any actual power systems, upgrading to 80kA is not dealt with in this study.

Suralaya (Lama)


Open

Gandul

Kembang

A

Legend 57244.1, -85.1


angle (deg.)

4-24

Busbar split operation at Balaraja substation

Bus A and Bus B of Balaraja substation can be split by switching of some circuit breakers (CBs) as shown in as

illustrated in Figure 4-18. Blue filled squares show circuit breakers switched on, and void squares show circuit

breakers switched off.

Figure 4-18 Busbar split operation at Balaraja substation


4-25

(4) Upgrade to 63 kA, grid splitting, and power system augmentation

To maintain a successful level of system reliability and to reduce the fault current to less than 63kA by splitting

the power grid including the 500kV system, introducing the higher voltage system or HVDC system can be a

measure to take.

Figure 4-19 illustrates a split grid with an additional 1,100kV transmission system to reduce the risk of power

interruption as an example of measures (4). System A and system B would be mutually interchangeable in

electricity via the 1,100 kV system.

Figure 4-19 Image of higher voltage system introduction to split the lower voltage network


4-26

Another example of (4) is shown in Figure 4-20. Figure 4-20 illustrates a split grid with an additional

HVDC 24to reduce the risk of power interruption.

Figure 4-20 Image of introduction of HVDC


Since the HVDC system controls power (or current in this case) between two AC systems at a constant value, it

will not increase the fault current. There is another splitting measure to adopt a Back to Back station25.

24 HVDC: High Voltage Direct Current, consists of high voltage DC transmission line and AC/DC convertors. 25 Back to Back station is a kind of DC link system in which the convertor and the invertor is located in the same site.

4-27

(5) Upgrade to 63 kA, grid splitting, and introducing the high impedance transformer

To reduce the fault current to less than 63kA, splitting the power grid and introduction of the higher impedance

transformer can be a measure to take. Higher impedance transformers can reduce the fault current in the same

manner as the fault current limiting reactor. The higher impedance transformer doesn’t require extra space.

As noted above, there are some measures against the fault current increase problem, and any of them can be

effective. Table below compares evaluations and problems of the said measures against the fault current increase

problem.

1. Measures to maintain the current fault current level 50kA

Table 4-8 Candidate directions to take against fault current increase problem (1/2)

Measure Evaluation Problems

(1) Current

limiting

reactor

Suppression of fault current by

increasing the impedance of power

system. More economical than

upgrading of the maximum fault

current level. Possible measure in

the short run

Track records in other country are

found.

Increased time constant of the fault

current DC component due to a current

limiting reactor inserted in series in the

grid can cause DC offset of the fault

current. If the circuit breaker cannot break

the fault current because of the DC offset,

this can cause serious damage to facilities

in the substation. Possible stability

degradation

Land acquisition for shunt capacitor banks

against voltage drop

(2) Grid splitting On the premise that existing

equipment is used as it is, fault

current into the fault point can be

suppressed by splitting the power

system with least cost or without

any additional cost.

Candidate measures such as a

power system configuration change

from loop to radial or busbar

splitting at substations

Grid splitting at many points will worsen

system reliability; consequently risk of

power interruption will increase to a large

extent.

Feasibility studies are necessary. Further

system analyses including system stability

study shall be conducted before the

implementation of the grid splitting.


4-28

The survey team notes that more study will be needed to verify the effect of the current limited reactor and to

analyze the related system flows in detail even if either of the above two measures in table 4-8 is adopted. Also,

they are more suitable as one for shorter periods from the view of sustainable control of fault current. The team

concluded that the upgrading fault current level is an imperative and more effective method in the mid-term on the

consideration of the future electricity development plan in this region since the increasing supply of power flow is

probably not able to secure the current system reliability as a result of the system analysis in this study .

Thus, we will introduce the another three measures alternatively in Table 4-9, which proposes the approaches of

upgrading the fault current level up to 63kV.

2. Measures to upgrade the fault current level to 63kA

Table 4-9 Candidate directions to take against fault current increase problem (2/2)

Measure Evaluation Problems

(3) Maximum fault

current level

upgrading and

grid splitting

Although extra cost will be necessary

to replace existing equipment, power

supply with additional generators in

future is expected to be maintained. It

is preferable in the medium- and

long-term.

Track records in other country

The power interruption risk will

increase

Cost for extra additional

equipment will be necessary.

(4) The said (3)and

power system

augmentation

It is preferable in the long-term.

It will be possible to maintain the

same level of current system reliability

In addition to the said (3), further

investment cost for extra

equipment will be necessary.

(5) The said (3) and

introduction of

high impedance

transformers

Same as the said (3)

Fault current can be decreased on the

same principle as the current limiting

reactor, while extra land acquisition

will not necessary

Same as the said (3)


To upgrade the fault current level, a lot of studies will have to be conducted in general as noted below.

Circuit breakers have to be replaced

Bus structures may have to be reinforced

Transformers may have to be reinforced or even replaced

Additional spacers in bundled conductors of overhead transmission lines may be necessary

Ground wires may have to be reconductered

4-29

~~

~

~

~

~

Suralaya #8 =625.0 MW

Suralaya #1-7 =3400.0 MW

Jawa 9 =600.0 MW

Jawa 7 =2000.0 MW

Banten #1 =660.0 MW

Jawa 5 =2000.0 MW

17016SLAYA7 501.0 501.0

17003BLRJA7 502.8

17005CLGON7 500.8

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25% I

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I 23% I

23% I

8% I

8% I

Suralaya (Lama)


Cilego

Banten

Bojonegar

A substation Tanara

Lengkong

Bogor X

Kembang

Gandul

4.6 Stability analyses

P3B-JB and the survey team conducted stability analyses together to confirm the power system will be stable

under the conditions noted below.

(1) Conditions for stability analyses

Network configuration and fault locations: The network configuration and fault locations for the stability

analyses are shown in Figure 4-21.

The survey team selected sending ends of transmission lines near generators as possible severe fault

locations.

Fault type: Three phase short circuit

Fault clearance time: 90milisecons after the fault occurrence

Judgment criteria for the stability: If rotor angle oscillations of generators tend to attenuate, the system is

stable.

Figure 4-21 Fault locations for stability analyses


4-30

(2) Results of stability analyses

Table 4-10 summarizes the results of stability analyses.

Table 4-10 Results of system analyses

Transmission line Fault location Result

Suralaya(Lama)-Balaraja Suralaya Stable

Suralaya(Lama)-Cilegon Suralaya Stable

Cilegon-BogorX Cilegon Stable

Suralaya (Lama)-Suralaya Baru Suralaya

(Lama) Stable

Suralaya Baru-Banten Suralaya Baru Stable

Banten-Bojonegara Banten Stable

Bojonegara-Balaraja Bojonegara Stable

Tanara-Balaraja Tanara Stable (Source: Results of the PSS/E stability analyses)

4-31

ROTOR ANGLESURALAYA S/S FAULT 90ms

SURALAYA - BALARAJA #1 TRIP

1 - ANGL 11006[SLAYA71-COA 23.000]1 : Suralaya-Balaraja-22 - ANGL 11010[SLAYA75-COA 23.000]1 : Suralaya-Balaraja-23 - ANGL 11052[SLAYA78-COA 23.000]1 : Suralaya-Balaraja-24 - ANGL 11703[JAWA5#1-COA 23.000]1 : Suralaya-Balaraja-25 - ANGL 11708[JAWA7#2-COA 23.000]1 : Suralaya-Balaraja-26 - ANGL 11709[JAWA9#1-COA 23.000]1 : Suralaya-Balaraja-27 - ANGL 12263[BNTEN71-COA 23.000]1 : Suralaya-Balaraja-28 - ANGL 31701[JAWA4#2-COA 18.000]1 : Suralaya-Balaraja-2

Time (seconds)1512.5107.552.50

80

70

60

50

40

30

20

10

0

ROTOR ANGLESURALAYA FAULT 90ms

SURALAYA - CILEGON #1 TRIP

1 - ANGL 11006[SLAYA71-COA 23.000]1 : Suralaya-Cilegon2 - ANGL 11010[SLAYA75-COA 23.000]1 : Suralaya-Cilegon3 - ANGL 11052[SLAYA78-COA 23.000]1 : Suralaya-Cilegon4 - ANGL 11703[JAWA5#1-COA 23.000]1 : Suralaya-Cilegon5 - ANGL 11708[JAWA7#2-COA 23.000]1 : Suralaya-Cilegon6 - ANGL 11709[JAWA9#1-COA 23.000]1 : Suralaya-Cilegon7 - ANGL 12263[BNTEN71-COA 23.000]1 : Suralaya-Cilegon8 - ANGL 31701[JAWA4#2-COA 18.000]1 : Suralaya-Cilegon

Time (seconds)1512.5107.552.50

80

70

60

50

40

30

20

10

0

(Reference) Stability analyses

Rotor angles of generators were shown below as the results of stability analyses.

Figure 4-22 Suralaya(Lama)-Balaraja transmission line #1 trip after a fault at Suralaya end

(Source: Results of the PSS/E stability analyses)

Figure 4-23 Suralaya(Lama)-Cilegon transmission line #1 trip after a fault at Suralaya end


4-32

ROTOR ANGLECILEGON FAULT 90ms

CILEGON - BOGORX #1 TRIP

1 - ANGL 11006[SLAYA71-COA 23.000]1 : Cilegon-BogorX2 - ANGL 11010[SLAYA75-COA 23.000]1 : Cilegon-BogorX3 - ANGL 11052[SLAYA78-COA 23.000]1 : Cilegon-BogorX4 - ANGL 11703[JAWA5#1-COA 23.000]1 : Cilegon-BogorX5 - ANGL 11708[JAWA7#2-COA 23.000]1 : Cilegon-BogorX6 - ANGL 11709[JAWA9#1-COA 23.000]1 : Cilegon-BogorX7 - ANGL 12263[BNTEN71-COA 23.000]1 : Cilegon-BogorX8 - ANGL 31701[JAWA4#2-COA 18.000]1 : Cilegon-BogorX

Time (seconds)1512.5107.552.50

70

60

50

40

30

20

10

0

ROTOR ANGLESURALAYA LAMA FAULT 90ms

SURALAYA LAMA - SURALAYA BARU #1 TRIP

1 - ANGL 11006[SLAYA71-COA 23.000]1 : SuralayaLama-Baru2 - ANGL 11010[SLAYA75-COA 23.000]1 : SuralayaLama-Baru3 - ANGL 11052[SLAYA78-COA 23.000]1 : SuralayaLama-Baru4 - ANGL 11703[JAWA5#1-COA 23.000]1 : SuralayaLama-Baru5 - ANGL 11708[JAWA7#2-COA 23.000]1 : SuralayaLama-Baru6 - ANGL 11709[JAWA9#1-COA 23.000]1 : SuralayaLama-Baru7 - ANGL 12263[BNTEN71-COA 23.000]1 : SuralayaLama-Baru8 - ANGL 31701[JAWA4#2-COA 18.000]1 : SuralayaLama-Baru

Time (seconds)1512.5107.552.50

80

70

60

50

40

30

20

10

0

Figure 4-24 Cilegon-BogorX transmission line #1 trip after a fault at Cilegon end


Figure 4-25 Suralaya (Lama)-Suralaya Baru transmission line #1 trip after a fault at Suralaya (Lama)


4-33

ROTOR ANGLESURALAYA FAULT 90ms

SURALAYA - BANTEN #1 TRIP

1 - ANGL 11006[SLAYA71-COA 23.000]1 : Suralaya-Banten2 - ANGL 11010[SLAYA75-COA 23.000]1 : Suralaya-Banten3 - ANGL 11052[SLAYA78-COA 23.000]1 : Suralaya-Banten4 - ANGL 11703[JAWA5#1-COA 23.000]1 : Suralaya-Banten5 - ANGL 11708[JAWA7#2-COA 23.000]1 : Suralaya-Banten6 - ANGL 11709[JAWA9#1-COA 23.000]1 : Suralaya-Banten7 - ANGL 12263[BNTEN71-COA 23.000]1 : Suralaya-Banten8 - ANGL 31701[JAWA4#2-COA 18.000]1 : Suralaya-Banten

Time (seconds)1512.5107.552.50

80

70

60

50

40

30

20

10

0

ROTOR ANGLEBANTEN FAULT 90ms

BANTEN - BOJONEGARA #1 TRIP

1 - ANGL 11006[SLAYA71-COA 23.000]1 : Banten-Bojonegara2 - ANGL 11010[SLAYA75-COA 23.000]1 : Banten-Bojonegara3 - ANGL 11052[SLAYA78-COA 23.000]1 : Banten-Bojonegara4 - ANGL 11703[JAWA5#1-COA 23.000]1 : Banten-Bojonegara5 - ANGL 11708[JAWA7#2-COA 23.000]1 : Banten-Bojonegara6 - ANGL 11709[JAWA9#1-COA 23.000]1 : Banten-Bojonegara7 - ANGL 12263[BNTEN71-COA 23.000]1 : Banten-Bojonegara8 - ANGL 31701[JAWA4#2-COA 18.000]1 : Banten-Bojonegara

Time (seconds)1512.5107.552.50

80

70

60

50

40

30

20

10

0

Figure 4-26 Suralaya Baru-Banten transmission line #1 trip after a fault at Suralaya Baru end


Figure 4-27 Banten-Bojonegara transmission line #1 trip after a fault at Banten end


4-34

ROTOR ANGLEBOJONEGARA FAULT 90ms

BOJONEGARA - BALARAJA #1 TRIP

1 - ANGL 11006[SLAYA71-COA 23.000]1 : Bojonegara-Balaraja2 - ANGL 11010[SLAYA75-COA 23.000]1 : Bojonegara-Balaraja3 - ANGL 11052[SLAYA78-COA 23.000]1 : Bojonegara-Balaraja4 - ANGL 11703[JAWA5#1-COA 23.000]1 : Bojonegara-Balaraja5 - ANGL 11708[JAWA7#2-COA 23.000]1 : Bojonegara-Balaraja6 - ANGL 11709[JAWA9#1-COA 23.000]1 : Bojonegara-Balaraja7 - ANGL 12263[BNTEN71-COA 23.000]1 : Bojonegara-Balaraja8 - ANGL 31701[JAWA4#2-COA 18.000]1 : Bojonegara-Balaraja

Time (seconds)1512.5107.552.50

80

70

60

50

40

30

20

10

0

ROTOR ANGLETANARA FAULT 90ms

TANARA - BALARAJA #1 TRIP

1 - ANGL 11006[SLAYA71-COA 23.000]1 : Tanara-Balaraja2 - ANGL 11010[SLAYA75-COA 23.000]1 : Tanara-Balaraja3 - ANGL 11052[SLAYA78-COA 23.000]1 : Tanara-Balaraja4 - ANGL 11703[JAWA5#1-COA 23.000]1 : Tanara-Balaraja5 - ANGL 11708[JAWA7#2-COA 23.000]1 : Tanara-Balaraja6 - ANGL 11709[JAWA9#1-COA 23.000]1 : Tanara-Balaraja7 - ANGL 12263[BNTEN71-COA 23.000]1 : Tanara-Balaraja8 - ANGL 31701[JAWA4#2-COA 18.000]1 : Tanara-Balaraja

Time (seconds)1512.5107.552.50

70

60

50

40

30

20

10

0

Figure 4-28 Bojonegara-Balaraja transmission line #1 trip after a fault at Bojonegara end


Figure 4-29 Tanara-Balaraja transmission line #1 trip after a fault at Tanara end


4-35

4.7 Recommendations

(1) Measures against the fault current increase problem

If the fault current level upgrade to 63kA is adopted as a measure against the fault current increase problem,

PLN should prepare for it as soon as possible.

PLN should also conduct studies on introduction of high impedance transformers in western Jawa power

system. The Survey Team particularly recommends that PLN conduct studies on introduction of high

impedance step-up transformers for new generators connected with western Jawa power system. The high

impedance of the step-up transformers will contribute to suppress fault current increase to some extent

without acquisition of extra land.

Fault current at 150kV system should be also calculated in the planning stage.

One line to ground fault current should be also calculated. To calculate the one line to ground fault current,

zero-phase-sequence impedances in the system should be prepared beforehand.

(2) Activation of PSS

Results of the stability analysis showed that the system was stable. However, it took relatively many cycles for

each generator to attenuate its internal angle oscillation, which is not a preferable status for the power system

operation. This manner of transmission system oscillation can be attenuated by application of properly tuned

power system stabilizers (PSS). According to P3B-JB, PSSs were already implemented in the generator control

systems but not activated because the planning division of P3B-JP did not have most of the existing generator

control blocks. They knew it was impossible to tune the PSS without the actual generator control blocks. Hence,

the survey team recommends that P3B-JB collect generator control blocks from power plants to be ready to tune

PSSs.

5-1

Chapter5. Technical Feasibility of the Project

5.1 Scope of the Project

The scope of the Project is as follows based on the previous chapter.

Upgrading of 500 kV Suralaya – Gandul transmission line

Upgrading of three associated 500 kV substations, Suralaya, Balaraja and Gandul

5.2 Transmission Line Project

From the results of the system analysis in 2020 conducted in the Study, the transmission capacity more than 987

amperes per conductor in the Previous Study is found to be necessary. Therefore methods to upgrade as much

capacity as possible are considered in this section.

However the upgrading method by constructing a new transmission route is excluded for the following reasons.

Acquiring the lands and right-of-ways for a new transmission line is extremely difficult from

previous experiences in Indonesia.

Accordingly, the commissioning year will be seriously delayed.

5.2.1 Selection of the Method to Upgrade the Transmission Capacity

Several methods to upgrade the transmission capacity are candidates for the Project.




Each method is explained as follows.


The following methods are considered for upgrading the transmission capacity by using conventional ACSR.

① Increasing the number of conductors per phase

② Replacing the existing conductors with larger ones

5-2

Each method is described below, assuming that the existing towers will be used without any modifications such

as reinforcements.

① Increasing the number of conductors per phase

The conceptual diagram of this method is shown in Figure 5-1.

Figure5-1 Conceptual Diagram of Increasing the Number of Conductors per Phase

(Source: The Study Team)

The existing lines have four-bundled ACSR Dove. If the number of the conductors per phase is increased using

the same conductor, the transmission capacity will be upgraded as shown in Table 5-1.

Table5-1 Changes in Current Carrying Capacity by Increasing the Number of Conductors per Phase

Number of conductors per phase Current carrying capacity

[Amperes]

4 2,056

6 3,084

8 4,112


In this method the transmission capacity is proportional to the number of the conductors, because the maximum

temperature of the conductor to be added is same as that of the existing one and therefore the capacity of each

conductor is also same. It is necessary to double the number of the conductors per phase in order to double the

transmission capacity. The number will be more than eight in the Project. If eight-bundled conductors are installed

on the existing towers, it goes without saying that the components of the towers such as the main posts and the

foundations do not have enough strength to support the loads due to the increased weight and wind pressure.

Consequently, reconstruction of the existing towers is not avoidable, and this method is not appropriate for the

Project.

5-3

② Replacing the existing conductors with larger ones

The conceptual diagram of this method is shown in Figure 5-2.

Figure5-2 Conceptual Diagram of Replacing the Existing Conductors with Larger Ones


The larger conductor can send more transmission capacity. For example, if the existing conductors are

re-conductored with ACSR Falcon which is a larger conventional conductor than the existing ACSR Dove, the

transmission capacity will be upgraded as shown in the next table. ACSR Falcon has 1.67 times as large diameter

and 2.67 times as much weight as the existing one, ACSR Dove. However ACSR Falcon has only 1.84 times as

much capacity as ACSR Dove.

Table5-2 Changes in Capacity by Replacing the Existing Conductors with Larger Ones

Unit ACSR Dove

ACSR Falcon

(Increasing rate)

Cross sectional area

of aluminum strands mm2 282.1

805.7

(286%)

Overall diameter mm 23.53

39.23

(167%)

Stranded mass kg/km 1,140

3,043

(267%)

Current capacity Amperes per

conductor 514

945

(184%)


If the existing conductors are replaced with larger ones so as to satisfy the required transmission capacity, it goes

without saying that the components of the towers such as the main posts and the foundations do not have enough

strength to support the loads due to the increased weight and wind pressure. Consequently, reconstruction of the

existing towers is not avoidable, and this method is not appropriate for the Project.

As described above, the two methods, “Increasing the number of conductors per phase” and “Replacing the

existing conductors with larger ones”, are found to be inappropriate for the Project.

5-4


HTC such as TACSR (Thermal resistant AACSR) and UTACSR (Ultra Thermal resistant AACSR) has higher

allowable temperature than conventional ACSR, and therefore has greater current carrying capacity. On the other

hand, conductors with higher temperature have larger sag and cannot probably keep the clearance values shown in

Table 5-3.

Table5-3 Minimum Clearances between conductor and objects

Objects Minimum clearances [m]

Open area 12.5

Buildings and bridge 9.0

Tree 9.0

Vehicle road, highway and rail-way 15.0

Playground 18.0

Other transmission line, power line and

communication line

8.5

(Source: The Previous Report)

In the Previous Study, it was reported that the clearances were estimated to be approximately met by ensuring

the same conductor sag as that of the existing one even at the time of reinforcement by re-conductoring. Also in

the Study, the conductor sag is designed in the same way.

When HTC is operated at the maximum allowable temperature, the current capacity will be upgraded, but the

conductor sag will also be increased. As a result, the same conductor sag will not be ensured. Therefore, the

operating conductor temperature has to be limited to keep the same sag as that of the existing conductor and the

expected upgrading cannot be realized.

5-5

Reducing the span length is a solution to keeping the same sag at the maximum allowable temperature. The span

length can be reduced by installing a new tower in each span between the towers. For example, when a tower is

newly installed at the mid-span, the span length will be a half (1/2) and the sag approximately a fourth (1/4). The

conceptual diagram of this method is shown in Figure 5-3.

Figure5-3 Conceptual Diagram of Installation of New Tower at the Mid-Span


Since the new towers are installed within the existing ROW, environmental and social impacts will be mitigated.

However, due to installation of many new towers, the Project cost and period, and also the shutdown period will

be increased. In this method, new towers have to be installed at all the mid-spans. The transmission lines generally

pass through open areas between Suralaya and Balaraja SS, and therefore new towers can be installed at the many

mid-spans between the sections. On the other hand, there are densely populated areas near Gandul SS, and also

many main road, express way or other transmission line crossings in the overall sections. It will be difficult to

install new towers at those mid-spans.

From the above-mentioned, this method is not appropriate for the Project.


HTLS has as high allowable temperature as HTC, and also has lower sag than HTC. Generally, the characteristic

is realized by using a material with the low co-efficient of linear expansion value as the core.

The conceptual diagram of this method is shown in the Figure 5-4.

5-6

Figure5-4 Conceptual Diagram of Installation of HTLS


The operating conductor temperature has to be limited to keep the same sag as that of the existing conductor as

aforementioned. Since HTLS has lower sag than HTC, HTLS has more current capacity than HTC.

The merits in this method are as follows.

• Modifications to existing towers, such as reinforcements or reconstruction, are not necessary.

• HTLS has twice as much current carrying capacity as the existing conductor.

• Only re-conductoring enables the transmission lines to be upgraded, and it leads to the shorter

implementation period of the Project.

• No additional lands are acquired, and there are few environmental and social impacts.

From the above-mentioned, this method is the most appropriate for the Project.

5.2.2 Selection of the Type of HTLS

Although there are several types of HTLS, the following conductors are selected as candidates from the

viewpoints of upgrading capacity, less loading impact on the existing towers and so on. Finally the best conductor

is selected from those.

(1) Thermal-resistant Aluminum Alloy Cable, Fiber Reinforced (TACFR)

(2) Super Thermal-resistant Aluminum Alloy Conductor, Aluminum-clad Invar Reinforced (ZTACIR/AC)

(3) Extra Thermal-resistant Aluminum Alloy Conductor, Aluminum-clad Invar Reinforced (XTACIR/AC)

Concentric-lay-stranded gap type thermal-resistant aluminum alloy conductors, steel reinforced (GTACSR) was

one of the candidates in the Previous Study, but is excluded from the Project in the Study. In the case of GTACSR,

the maximum conductor tension is greater than that of the existing one and therefore it is necessary to study

further whether the existing tower structures can bear the greater tension or not. However the further study cannot

be conducted because the existing lines are very old and the tower diagrams or design reports no longer exist.

Therefore it is important to select the conductor whose characteristics, such as the mass and the diameter, are

similar to ACSR Dove so that the tensions of the replaced conductors may not exceed those of the existing ones

on the towers.

5-7

(1) Thermal-resistant Aluminum Alloy Cable, Fiber Reinforced (TACFR)

The conductor is up-rated by the use of thermal-resistant aluminum alloy wires (TAL) which has the continuous

allowable temperature up to 150°C. The sag is lowered by the use of carbon fiber composite cables (CFCC) with

the low co-efficient of linear expansion value. The TACFR in the Study does not have normal round aluminum

alloy strands, but trapezoidal ones. The proposed TACFR has the cross sectional view as shown in Figure 5-5 and

has the following features.

• The co-efficient of linear expansion value of the CFCC is about one tenth (1/10) as low as that of

conventional steel wires in ACSR.

• Trapezoidal aluminum alloy strands are used.

• The current carrying capacity of the TACFR is approximately twice as much as that of ACSR Dove.

• When increasing the current carrying capacity to double, the sag of the replaced up-rating conductor is as

approximately same as that of the existing ACSR used at 75ºC.

• The weight of the CFCC is about one sixth (1/6) as much as that of conventional steel wires, and the overall

weight is lighter than that of conventional ACSR.

• The strand configuration of the core cables makes the bending stiffness of the conductor low, and allows it

to be easily handled.

• In Indonesia and China, conductors with carbon cores which have the core part made in Japan and the

aluminum part made in foreign countries have been adopted. On the other hand, in Japan, conductors with

carbon cores which have both parts made in own country have been used.

Figure5-5 Cross Sectional View of TACFR


(2) Concentric lay stranded, Super thermal-resistant aluminum alloy conductor, aluminum-clad Invar

reinforced, so-called “Invar Type Conductor” (ZTACIR/AC)

To increase the current carrying capacity, super thermal-resistant aluminum alloy wire (so-called “ZTAL”),

which can utilize up-to 210 ˚C continuously, is used. In order to restrain the sag to increase, Invar core wire,

whose co-efficient of linear expansion value is smaller, is adopted to satisfy the requirement. The “Invar Type

Conductor” has the cross sectional view as shown in Figure 5-6, which is same as the conductor proposed in the

Previous Study, and has the following features.

• The construction of ZTACIR/AC is same as that of conventional ACSR conductors. In the core wire part,

5-8

“Invar Wire” is adopted, and the co-efficient of linear expansion value is smaller. The value of the Invar

wire is about 1/3 of that of the conventional steel wire used in ACSR.

• ZTAL is used.

• It is possible to increase the current carrying capacity to almost double, compared with ACSR Dove.

• When increasing the current carrying capacity to double, the sag of the replaced up-rating conductor is as


• ZTACIR/AC made in Japan has been used in China and Japan. The similar products have been

manufactured in Korea, and they have been adopted in Korea, Malaysia, India and China etc.

Figure5-6 Cross Sectional View of ZTACIR/AC


(3) Concentric lay stranded, Extra thermal-resistant aluminum alloy conductor, aluminum-clad Invar reinforced,

which is so-called “Invar Type Conductor” (XTACIR/AC)

To increase the current carrying capacity, extra thermal-resistant aluminum alloy wire (so-called “XTAL”),

which can utilize up-to 230 ˚C continuously, is used. In order to restrain the sag to increase, Invar core wire,

whose co-efficient of linear expansion value is smaller, is adopted to satisfy the requirement. The proposed “Inver

Type Conductor” has the cross sectional view as shown in Figure 5-7 and has the following features.

• In the core wire part, “Invar Wire” is adopted, and the co-efficient of linear expansion value is smaller. The

value of the Invar wire is about 1/3 of that of the conventional steel wire used in ACSR.

• Trapezoidal XTAL is used.

• The current carrying capacity of the XTACIR/AC is about 2.4 times as much as that of ACSR Dove.

• When increasing the current carrying capacity to 2.4 times, the sag of the replaced up-rating conductor is as


• Japanese manufactures only can produce XTACIR/AC. They have been installed in China, USA and

Australia as well as Japan.

5-9

Figure5-7 Cross Sectional View of XTACIR/AC


(4) Evaluation

The properties and the calculation results of the sag and the current carrying capacity for each up-rating

conductor are shown in the next tables.

The required design conditions for up-rating conductors in the Study are as follows.

• Not to exceed the sag of the existing conductor, 21.70 m at the 500 m span.

• Not to exceed the maximum tension (23,025 N) of the existing conductor.

• Not to exceed the weight (1,140 kg/km) and the diameter (23.53 mm) of the existing conductor.

Under the required conditions, XTACIR/AC has the most current carrying capacity of the candidates for the new

conductor, and is recommended for the Project. The capacity is approximately 2.4 times as much as that of the

existing conductor. Moreover the conductor needs no special tools for installation.

5-10

Table5-4 Properties of Each Up-Rating Conductor

Description Unit

Existing

Conductor

(ACSR Dove)

TACFR

315mm2

ZTACIR/AC

225mm2

XTACIR/AC

230mm2

Composition Nos/mm

26/3.716 (HAL) 10/4.98

(TW-TAL) 34/2.9 (ZTAL)

14/3.5

(TW-XTAL)

- 6/4.98 (TW-TAL) - 10/3.5

(TW-XTAL)

7/2.891 (St) 7/2.6 (CFCC) 7/3.55 (IR/AC) 7/3.46 (IR/AC)

Min. breaking load kN 101.0 122.6 107.2 97.6

Cross-Section

al Area

AL

mm2

282.1 311.7 224.6 230.9

St 45.95 37.20 69.29 65.80

Total 328.1 348.9 293.9 296.7

Nominal Diameter mm 23.53 22.36 22.30 20.8

Nominal Weight kg/km 1,140 923.7 1,117 1,105

DC Resistance at 20 ºC Ω/km 0.1024 0.0950 0.1224 0.1229

Modulus of

Elasticity

Cond. GPa

82.0 61.8 83.1 81.8

Core 205.9 155.0 152.0 152.0

Coefficient

Linear

Expansion

Cond.

x10-6/ºC

19.0 23.0 14.7 15.0

Core 11.5 1.0 3.7 3.7

Max. Allowable

Temperature ºC 75 150 210 230

(Source: The Previous Report and the Study Team)

Table5-5 Calculation Results of Sag and Current Carrying Capacity for Each Up-Rating Conductor

Description Unit

Existing

Conductor

(ACSR Dove)

TACFR

315mm2

ZTACIR/AC

225mm2

XTACIR/AC

230mm2

Sag in 500 m Span m

21.70

20.91

21.70

21.66

at 75ºC at 150ºC at 158ºC at 230ºC

Current under the above

condition

A 514 1,080 987 1,252

Max. Tension N 23,025 23,025 22,855 23,025


5-11

5.2.3 Evaluation of transmission losses

The transmission losses are compared between the existing conductor, ACSR Dove, and the up-rating conductor,

XTACIR/AC 230mm2. It is assumed that Suralaya – Gandul line has double circuits, that the maximum current

flow on another one during shutdown of a circuit, and that each circuit has a flow of a half of the value, 2,504

Amperes, in the normal conditions,.

On the other hand, the existing conductor has the maximum current of 2,056 Amperes per phase. For the

purpose of comparison, the losses of the existing conductor are calculated assuming that the same current, 2,504

Amperes per circuit, flow also on the existing conductor.

Since the transmission losses are largely caused by the electrical resistance, the corona loss26 is not taken into

account.

The transmission losses are calculated and shown in Table 5-6. The transmission losses produced in

XTACIR/AC 230mm2 is 1,485.06 kW/km, and is about 1.3 times as much as those of the existing conductor,

ACSR Dove. The increase is due to the greater value of the AC resistance of the conductor.

Table5-6 Transmission Losses

Description Unit ACSR Dove XTACIR/AC 230mm2

Operating Voltage kV 500

Frequency Hz 50

Current per Phase A 2,504

AC Resistance Ω/km 0.1254 0.1579

kW Loss

(for double circuits)

kW/km 1,179.40 1,485.06

kW 130,913 164,842


Also, the annual energy lost in the transmission lines is calculated by the product of the transmission losses, the

total hours per year (8,760 hours) and a loss factor, Fr. Here, Fr is calculated from the following Buller-Woodrow

formula, assuming the load factor, f, is 0.7.

Fr = 0.7 x f2 + 0.3 x f = 0.553

The calculated results are shown in the Table 5-7. The annual transmission losses in the re-conductored lines are

about 1.3 times as much as those of the existing lines for the same reason as mentioned above.

26 A corona discharge is an electrical discharge produced by non-uniform electrical fields around a pointed electrode. When it

rains, the corona frequently occurs at the conductor surface in high-voltage transmission lines, and also causes power loss.

5-12

Table5-7 Annual Transmission Losses

Description Unit ACSR Dove XTACIR/AC 230mm2

kWh Loss

(for double circuits)

kWh/km 5,713,344 7,194,046

kWh 634,181,184 798,539,106 (Source: The Study Team)

5.2.4 Re-conductoring Work to HTLS

There are two kinds of conductors’ replacement methods, the tension stringing method and the cradle block

method. The former method needs countermeasures against great sags of the conductors during re-conductoring,

such as installation of bamboo scaffoldings over main roads and so on. The latter method, which can prevent the

conductor sags during re-conductoring, is adopted in densely populated areas, because there are many road

crossings and so on and installation of many scaffoldings takes much work. The cradle block method is frequently

used in Japan, where there are many densely populated areas.

In the following subsections, the conductors’ replacement methods are introduced, then the current situations

around the existing transmission line routes are described, and finally the proper replacement method in each

section is selected.

(1) Conductors’ replacement methods

① Tension Stringing Method

The sufficient scaffolding shall be installed by means of bamboo etc. before the commencement of the

conventional paying out works. In the tension tower, all jumper conductors shall be dismantled and both sides of

conductors shall be connected by means of suitable connection wires. Putting the existing conductor on the

stringing roller, all conductors shall be pulled off. Installing the counter weight at the tail of the existing conductor

to avoid the rotation of conductor during paying out and connecting the replaced conductor afterwards, the

replacement works shall be carried out.

Or replacement of conductor after changing the existing conductor to the pulling wire first may also be realistic.

In both cases, four-bundled conductors can be replaced simultaneously, and therefore the construction speed is

usually fast.

② Cradle Block Method

In the urban crowded housing area or at the important obstacles’ crossing, where the installation of the

scaffolding seems difficult, so-called “Cradle Block Method” may be applicable which install twin small rollers in

each span intervals of about 20 to 30 meters on the existing ACSR and to pull out the bottom replaced conductor.

If this method is adopted, the sag during the installation can be bound by means of the anchored ACSR. So even

though there are some obstacles such as houses underneath the line, paying out works can be held without

constructing any scaffolding. However in case of 4 bundled conductors, each conductor shall be replaced one by

one, so the installation speed becomes slow.

The outline of Cradle Block Method is described in Table 5-8.

5-13

Table5-8 A stringing method by means of cradle block system

No. Major Procedure Major Work Step

1 Before Commencement

2 Distribute cradle blocks and

pulling/connection rope by means of

motor car etc.

At that time, cradle blocks shall be

hung down on the existing

conductor.

To avoid any induced current,

so-called “Kevlar Rope” may be

suitable to adopt.

3 At the tail of the pulling wire,

connect the replaced conductor and

paying out works shall be

commenced.

To avoid rotation, some suitable

unti-twisting counter weight may be

applicable.

4 Finish the paying out works.

Initial ConditionExisting Conductor

Distribution of Cradle BlocksExisting Conductor

Nylon Rope

Cradle Block

Motor Car

Nylon Rope

ExistingAbout 20-30m

Pull New Conductor by Nylon RopeExisting Conductor

Nylon Rope

Cradle Block

New Conductor

Winch

Drum

Counter Weight

Existing

Nylon Rope

New

Completion of New Conductor’s paying out

Existing Conductor

Nylon Rope

Cradle Block

New Conductor

Winch

Drum

ExistingNylon Rope

New

5-14

No. Major Procedure Major Work Step

5 Releasing the tension of the

existing conductor, change the sag

location between the existing and

replaced conductor.

6 Hanging the cradle blocks on the

replaced conductor, connecting the

anchored rope at the tail of the

existing conductor to be collected

up.

7 At the tail of the anchord tope,

installing a braking instrument,

collect up the rope together with

cradle blocks.

8 Fish the replacement


The tension stringing method and the cradle block method are compared as shown in Table 5-9.

Change Sag between Existing and New Conductor

Existing Conductor

Nylon Rope

Cradle Block

New Conductor

ExistingNylon Rope

New

Collection of existing Conductor

Existing Conductor

Nylon Rope

Cradle Block

New Conductor

Winch

Drum

Existing

Nylon Rope

New

Collection of Nylon Rope and Block

Nylon Rope

Cradle Block

New Conductor

Winch

Nylon Rope

New

Brake Instrument

Completion of Paying-outNew Conductor

5-15

Table5-9 Comparison between Tension Stringing Method and Cradle Block Method


5-16

(2) Selection of replacement method

① Tension stringing method

The tension stringing method is used for open areas with few residents or no important crossings. After the site

survey, it is found that the existing lines generally pass through open areas. Therefore, this method can be used for

many route sections, excluding the densely populated areas near Gandul SS, and also many main roads, express

way, railway or other transmission line crossings.

Figure5-8 Route Sections Suitable for Tension Stringing Method


② Cradle block method

The cradle block method is used for densely populated areas or important crossings. After the site survey, it is

found that this method has to be adopted in the densely populated areas near Gandul SS, and also at many main

roads, express way, railway or other transmission line crossings.

Figure5-9 Route Sections Suitable for Cradle Block Method


5-17

Figure5-10 Mapped Route Sections Suitable for Cradle Block Met (Source: Map in the Previous Report, modified by the Study Team)

* C

radl

e B

lock

Met

hod

may

be

used

in o

ther

pla

ces s

uch

as e

xist

ing

T/L,

hig

hway

, mai

n ro

ad a

nd ra

ilroa

d cr

ossi

ng.

5-18

The following table shows that there are densely populated areas or important crossings such as railways or

express ways in the stringing sections according to the site survey. Since it is difficult to install scaffoldings in

these areas or points, these sections are suitable for the cradle block method.

Table5-10 Recommended Stringing Sections Suitable for Cradle Block Method

Line Route Stringing Section Line Length

(km)

Crossing

(Reasons to adopt cradle system)

Line I

(North)

No.21-No.22 0.4 Other T/L crossing

No.32-No.38 3.0 Highway, railway, other T/L crossing

No.54-No.58 2.4 Factory



No.133-No.138 3.1 Populated area, other T/L crossing




No.192-Gandul SS 17.3 Populated area, other T/L crossing

Other sections 5.0 Main roads with much traffic

Sub Total 39.8 －

Line II

(South)


No.31-No.37 3.0 Highway, railway, other T/L crossing




No.132-No.137 3.1 Populated area, other T/L crossing




No.191-Gandul SS 17.6 Populated area, other T/L crossing

Other sections 5.0 Main roads with much traffic

Sub Total 40.0 －

Total 79.8 －


5-19

Finally, the route lengths suitable for the tension stringing or the cradle block method are shown in the Table

5-11.

Table5-11 Route Length by Each Replacement Method (Unit: km)

Line Route Method Suralaya -

Balaraja

Balaraja -

Gandul Sub Total Total

Line I Tension Stringing 53.2 17.8 71.0

110.8 Cradle Block 8.8 31.0 39.8

Line II Tension Stringing 52.9 18.2 71.1

111.1 Cradle Block 8.7 31.3 40.0


5.2.5 Re-conductoring Costs

The quantities of materials for the re-conductoring work are shown in Table 5-12.

Table5-12 Quantities of Materials for Re-Conductoring Work Line

Route Conductor

Suspension

Clamp

Tension

Clamp

Jumper

Spacer

Spacer

damper

Armour

Rods

Mid-span

Joint

Repair

Sleeve

Line I 1,400 km 2,192 680 246 4,671 2,192 700 75

Line II 1,400 km 2,155 806 293 4,675 2,155 700 75

Total 2,800 km 4,347 1,486 539 9,346 4,347 1,400 150


The re-conductoring unit costs for erection work are estimated as follows.

• Tension stringing method： 523,200,000 IDR/km

• Cradle block method： 443,200,000 IDR/km

Based on the above, as a result of estimated construction costs relating to reconducting transmission lines, the

grand total was USD 83 millions as shown in Table 5-13.

5-20

Table5-13 Re-Conductoring Costs (Unit: Million US$)

No Items Costs

1 Conductor 60.1

2 Hardware 2.1

3 Stringing 9.1

4 Scrap of conductor -3.5

Total 67.8

5 Contingency 10% 7.5

6 Overhead 10% 8.3

Grand Total 83.6 (Source: The Study Team)

5.2.6 Construction Schedule

If the conventional tension stringing method is adopted, 4-bundled conductors can be paid out simultaneously.

Therefore, the progress speed is expected to be about 8km/month/circuit per a stringing crew. On the other hand, if

the cradle block method is adopted, each individual conductor shall be paid out one by one. Therefore, the

progress speed is only about 4km/month/circuit per one crew.

The construction duration by each method is estimated as follows.

• Conventional Tension Stringing Section: 142.1 km / 8 km per month = 17.8 Months per crew

• Stringing Section by Cradle Block system: 79.8km / 4 km per month = 20.0 Months per crew

In the Project, the Study Team assumed that four crews would work taking into consideration the

commissioning in 2019. If further crews are added, the management of them and the securing the skilled workers

are concerned. If four crews are adopted, the construction duration may be as shown in Table 5-14.

Table5-14 Estimated Construction Duration (Unit: Month)

Line Route Duration

Tension Stringing Method Cradle Block

Total

Line I Suralaya - Balaraja 1.7 0.6 2.3

Balaraja - Gandul 0.6 2.0 2.6

Line II Suralaya - Balaraja 1.7 0.6 2.3

Balaraja - Gandul 0.6 2.0 2.6

Total 4.6 5.2 9.8 (Source: The Study Team)

5-21

5.2.7 Points to be Considered for Stringing Work

There are some points to be considered for the stringing work and they are listed below. The first two points

result from changes in the transmission facilities from the year 2007, and the third is the one which was already

noted in the Previous Report.

(1) Tower re-construction associated with new construction of Balaraja SS

(2) Additional 150 kV double circuits on towers of Line I near Gandul SS

(3) Countermeasures against insufficient clearances

(1) Tower re-construction associated with new construction of Balaraja SS

In the Previous Study, the Balaraja SS had been planned to construct in 2009, and the Study Team confirmed

that the Balaraja SS was constructed as planned. It was also found out through the on-site survey that the single

circuit towers of the Line I and II had been re-constructied to the double circuit ones associated with the new

construction of Balaraja SS. The towers before and after the re-construction are shown in Figure 5-11 and 5-12.

5-22

Figure5-11 Towers before and after Construction of Balaraja SS

(a) Before Construction of Balaraja SS

(b) After Construction of Balaraja SS (Source: The Study Team)

Figure5-12 Present Double Circuit Towers near Balaraja SS

(a) The First Tower to Suralaya SS (b) The First Tower to Gandul SS (Source: The Study Team)

5-23

The Study Team had the information that some towers, which had been constructed by local companies (or

workers) in Indonesia, had defects such as missing nuts & bolts or members, and therefore observed the

re-constructed towers carefully. As a result, the towers appeared to have been built firmly without any defects and

to have no problems with the future re-conductoring work. However, ropes or wires have possible contacts with

another energized circuit during the stringing work on the double circuit towers, unlike on the single circuit ones.

It may cause electrical shock hazards by the contacts or the induced currents. The shutdown of the other circuit

may also be necessary.

(2) Additional 150 kV double circuits on towers of Line I near Gandul SS

Most of the towers of the lines have a single circuit line configuration. In the Previous Study, it was reported

that the towers in the eight-km section of Line I near the Gandul SS had been designed for an existing 500 kV

single circuit and future 150 kV double ones.

After the site survey, it was found that the 150 kV double circuit lines had been installed on those towers. The

150 kV lines go from the Gandul SS to the no. 212 tower on the same towers as those of the 500 kV Line I, and

then go to the Serpong SS on the different route.

As stated in (1), ropes or wires have possible contacts with other energized circuits during the stringing work in

the section. The shutdown of the other circuits may also be necessary.

5-24

Figure5-13 Additional 150 kV Double Circuits on Towers of Line I near Gandul SS

(a) Pictures in the Previous Study

(b) Pictures in the Study


(3) Actions against insufficient clearances

According to the Previous Study, it was reported that the clearance for 70 kV and 150 kV line would be quite

severe. In the Study, it was impossible investigate in detail the clearances from the two 500 kV lines with the

length of approximately 100 km respectively. In the actual re-conductoring work, therefore, detailed investigation

and study for ground clearance and other clearance for all obstacles under the entire lines shall be carried out.

Where the clearance is insufficient, it is necessary to study the proper countermeasures to be taken.

5-25

5.3 Substation Project

5.3.1 Overview of Existing 500 kV Substations

Before studying the substation project, the Study Team surveyed Gandul, Balaraja and Suralaya substations. The

survey results are as follows.

(1) Gandul substation

The site photographs and the existing facilities are shown in the next figure and table, respectively.

Figure5-14 Site Photographs at Gandul SS

ＣＴ


Line

Overview

Circuit Breaker (Convention

type)

5-26

Ratedshortt ime

No.Name of

equ ip.Qt 'y

ManufacturerMaker

CountryRated

vo ltageRated

Currentwithstandcurrent

kV A kA (3S)

1 CB ABB Sweden 525 4 ,000 50

14 GEC Alstom not sure 525 3 ,150 40

AREVA France 525 3 ,150 40

Magr in i G. not sure 525 3 ,150 40

2 CT 69 not sure not sure 525 3 ,150 40

3 DS 39 not sure not sure 525 3 ,150 40

4 Line t rap 6 not sure not sure 525 3 ,150 40

Ｒｅｆ） Tr. Unit 1&2 El in France

Unit 3 ABB China

Rated capacity : 500 MVA

500kV １５0kV ６６kV√３ √３ √３

1,520

1,520

1,520

Present cur rentA

1,5201,5201,5201,520

<Red shows the result of site survey>

PRESENT(As ofNov.17 2015)Existing Facilities (Start operation in1981)

Table 5-15 Existing Facilities at Gandul SS


5-27

Figure 5-15 Single Line Diagram (Gandul S/S)

Marks show the scope of this study, to be replaced.

5-28

Overview

CT

Line Trap


type)

(2) Balaraja substation


Figure5-16 Site Photographs at Balaraja SS


5-29

Ratedshortt ime

No.Name of

equ ip.Qt 'y

Manufacturer

CountryRated

vo ltageRated

Currentwithstandcurrent

kV A kA (3S)

1 ＣＢ 12 AREVA France 550 3 ,150 40

2 CT 90 AREVA France 550 3 ,150 40

3 ＤＳ 37 AREVA France 550 3 ,150 40

4 Line t rap 6 AREVA France 550 3 ,150 40

Ｒｅｆ） Tr. 9/3bay AREVA Turkey

Rated capacity : 500 MVA

500kV １５0kV ６６kV√３ √３ √３


1,520

Existing Facilities (Start operation in 2009) PRESENT(As ofNov.18 2015)

Present cur rentA

1,520

1,520

1,520

Table 5-16Existing Facilities at Balaraja SS


5-30

Figure 5-17 Single Line Diagram (Balaraja S/S)


5-31

(3) Suralaya substation


Figure5-18 Site Photographs at Suralaya SS


Overview

500/150 kV Transformer (made in Japan)


5-32

Ratedshortt ime

No.Name of

equ ip.Qt 'y

Manufacturer

MakerCountry

Ratedvo ltage

RatedCurrent

withstandcurrent

kV A kA (3S)

GCB (3 bay分)

1 GCB 8 ALSTOM France 550 3,150 40

2 CT 54 ALSTOM France 550 3,150 40

3 DS 21 ALSTOM France 550 3,150 40

CB (4 bay分)

1 GCB 12 AREVA France 550 3,150 40

2 CT 45 BBC Switerland 550 3,150 40

3 DS 35 BBC Switerland 550 3,150 40

4 Line trap 4 AREVA France 550 3,150 40

Ｒｅｆ） Tr. 1Mitsubish iElectr ic .

Japan

1,315

1,315

1,315

1,315

1,315

1,315

1,315

Present cur rentA


Existing Facilities (Start operation in 1984) PRESENT(As ofNov.19 2015)

Table 5-17Existing Facilities at Suralaya SS


5-33

Figure 5-19 Single Line Diagram (Suralaya S/S)


5-34

5.3.2 Adaptation and Replacement Works for Substation Equipment

(1) Consideration of adaptation

By re-conductoring and upgrading of the transmission lines, the current capacity of the substation equipment

which connects directly to the transmission line becomes insufficient, and the equipment has to be replaced. The

specifications of the rated currents of the series devices at the substations associated with re-conductoring of

Suralaya – Balaraja – Gandul T/L have to satisfy the maximum load currents at all time after re-conductoring.

The specifications of the existing series devices are shown in the next table. The future values exceed the

capacity of the existing equipment. The newly installed equipment has to satisfy these values.

Table 5-18 Rating of Existing and Newly Installed Circuit Breakers Present situations

(As of November 2015)

Predicted values Newly installed equipment

Substation Rated

voltage

Rated

current

Rated short

time withstand

current

Maximum

load current

at all time

Fault

current

Rated

current

Rated short

time withstand

current

GANDUL 525 kV 3150 A 40 kA 5008 A 63.0 kA 6000 A 63 kA

BALARAJA 525 kV 3150 A 40 kA 5008 A 63.8 kA 6000 A 63 kA

SURALAYA 525 kV 3150 A 40 kA 5008 A 57.28 kA 6000 A 63 kA

Note: The fault current in “Predicted values” is greater than 63 kA in the substation. The value should be less than 63 kA by the

power system operation.


(2) Replacement works

The rated currents of the series devices related to the transmission line after re-conductoring are insufficient, and

therefore have to be replaced. The replacement works at the substation are as follows.

(Common to three substations)

① Replacement of the existing 500kV circuit breakers.

② Replacement of the existing 500kV disconnectors.

③ Replacement of the existing 500kV current transformers.

④ Replacement of the existing 500kV line trap.

⑤ Replacement of the existing conductors for transmission line bays.

⑥ Replacement of the existing supporting structure for equipment

⑦ Replacement of the foundations of the above equipment.

⑧ Setting and adjustment of the existing protection relays and meters.

5-35

The implementation schedule or the points to be considered are as follows.

• The required construction period is estimated to be 36 months. The period includes equipment

manufacturing, transportation, local construction (Civil work: foundation dismantling and new construction,

Equipment work: existing equipment removal work including equipment support structure dismantling and

new equipment installation work including new equipment support structure), and the field tests. Of these,

Site work is expected to take about 20 months. However, if more crews are adopted, it is possible to shorten

the construction period.

• The replacement works at the substations need to be implemented together with the transmission line

re-conductoring works. The both works should be implemented in a coordinated way also taking into

considerations the operations of the 500kV grid and suitable shutdown plans.

The quantities of substation equipment to be replaced and their rated currents are shown in the next table.

Table 5-19 Quantities of Substation Equipment to be Replaced and Rated Currents

Substation Gandul Balaraja Suralaya

No. of transmission line

circuits 2 2 2

3-phase circuit breaker

(Rated current)

6

(6000 A)

6

(6000 A)

6

(6000 A)

Single-phase current

transformer

(Rated current)

24

(6000 A)

42

(6000 A)

24

(6000 A)

3-phase disconnector

(Rated current)

14

(6000 A)

22

(6000 A)

14

(6000 A)

Line Trap

(Rated current)

2

(6000 A)

2

(6000 A)

2

(6000 A)


5-36

(3) Future considerations required

The newly installed equipment is larger and heavier because the rated currents increase as shown in the table

above. The followings should be considered in the future.

① Shortening the periods of replacement works

*The replacement works need shutdown, and it is necessary to consider shortening the periods of shutdown

② Measures for equipment, other than the main equipment against fault current.

③ Study on measures against fault currents more than 63 kA at Balaraja substation

④ Study on rated current of the main bus bar

5.3.3 Substation Project Costs

The substation project costs are shown in the Table 5-20. It includes all the costs such as equipment,

transportation, civil work, installation and the commissioning test. The specifications of equipment are assumed to

be air-insulated switch gears.

Table 5-20 Equipment and Local Construction Costs (Unit: US$)

GANDUL BALARAJA SURALAYA

Equipment 7,287,320 8,221,000 7,287,320

Local construction 467,000 503,510 453,104

Total 7,754,320 8,724,510 7,740,424

Grand total 24,219,254


5.4 Total Project Costs

The total construction costs for the Project including re-conductoring of the transmission lines and upgrading of

three associated 500 kV substations are shown in the next table.

Table5-21 Total Project Costs (Unit: Million US$)

Transmission Facilities 83.6

Substation Facilities 24.2

Total 107.8


5-37

(Reference) Application to Other Re-conductoring Projects

Other re-condoctoring projects such as upgrading of 500 kV New Suralaya – Balaraja transmission line are

planned. The line is illustrated in the next figure, and goes from New Suralaya to Balaraja via Banten and

Bojonegara.

Figure 5-20 Re-Conductoring of 500 kV New Suralaya – Balaraja T/L


The line has the same conductors, four-bundled ACSR Dove per phase, as Suralaya – Gandul line. Therefore,

up-rating conductors in the Study such as XTACIR/AC, ZTACIR/AC and TACFR can be applied to the

re-conductoring project.

6-1

Chapter6. Environment and Social Practicability

6.1 Environmental and Social Impact of the Project

Because of the densely populated area along the Suralaya-Gandul lines the construction work is limited to

re-conductoring of existing conductor, and there will be no new physical objects to adversely affect the

environment. The environmental impacts specific to a transmission project are social resettlement,

electromagnetic fields, corona noise and radio noise.

6.1.1 Social resettlement

When a new transmission line involving land acquisition is constructed, resettlement of residents is often

required to secure the right of way, and this often poses a social problem. In case of this project, however, the

planned increase in the capacity of the transmission lines can be achieved simply by re-conductoring the

transmission line using the existing electric power pylons, therefore resettlement of the residents will not be

necessary in principle. Suralaya ― Gandul Lines, which the feasibility study was conducted, pass through many

densely populated residential areas of West Java Province especially near Jakarta. It is quite difficult to acquire

lands in those areas, and construction of a new transmission line is considered quite difficult due to longer

construction process. Therefore, considering the circumstances of the construction sites, the re-conductoring of the

existing transmission line, which we are proposing, is regarded to be the most effective and practical means of

increasing the transmission capacity as desired.

6.1.2 Electric and Magnetic Field Intensities

According to the Previous Report, the restriction values of the electrostatic and electromagnetic field strength in

Indonesia are defined in the SNI (04-6918-2002), as shown in Table 6-1. The reference levels in the ICNIRP

Guideline are also shown the table.

Table 6-1 Limited Values for Electric and Magnetic Field

Item Object Organization

SNI ICNIRP

Electric Field

Strength

General Public 5 kV/m 5 kV/m

Occupational 10 kV/m 10 kV/m

Magnetic Flux

Density

General Public 100 μT

(1,000 mG)

200 μT

(1,000 mG)

Occupational 500 μT

(5,000 mG)

1000 μT

(10,000 mG) (Source: The Study Team)

6-2

As for the electric field strength, it is reported in the Previous Report that the transmission line conductor with

the minimum height of 15 m above the ground has the values a little more than 5 kV/m, and that the actual

conductor height above the ground, 16 m or so, has the electric field strength of 4.9 kV/m.

In the Project, the transmission line voltage and the height of the replaced conductors will be the same as those

of the existing line. Therefore the predicted electric field strength will also be same as that in the Previous Report,

and be less than 5 kV/m.

As for the magnetic flux density, though the height of the replaced conductor is the same as those of the existing

line, the strength increases in proportion to the electrical currents. In the Project, the currents will be 2.4 times as

large as those of the existing line, and the density will be 64 μT, which is less than 200 μT.

6.1.3 Corona Noise

According to the Previous Report, electric power utilities in the world propose the corona noise level of

50dB~58 dB as the target value for designing transmission line construction, and the corona noise level would be

same as the target value after the re-conductoring.


of the existing line, and the diameter of the replaced conductor will also be almost same. Therefore the predicted

corona noise level will also be same as that in the Previous Report, and be less than or equal to the target value.

6.1.4 Radio Noise

According to the Previous Report, the radio noise level would not be much changed after the re-conductoring.


of the existing line, and the diameter of the replaced conductor will also be almost same. Therefore the predicted

radio noise level will also be same as that in the Previous Report, and be same as the value of the existing line.

6.2 Review according to the Japan International Cooperation Agency (JICA) Guidelines for

Environmental and Social Considerations

6.2.1 Assessment of Environmental Checklist under JICA Guidelines

The assessment and suggested procedure for this project on the Environmental Checklist for Power

Transmission and Distributions in accordance with the JICA Guidelines is shown in Figure 6-1.

6-3

Figure 6-1 Assessment of Environmental Checklist under JICA Guidelines

Category Environmental

Item Main Check Items

Confirmation of Environmental Considerations

(Reasons, Mitigation Measures)

1 Permits and

Explanation

(1) EIA and

Environmental

Permits

(a) Have EIA reports been already prepared in official process?

(b) Have EIA reports been approved by authorities of the host country's

government?

(c) Have EIA reports been unconditionally approved? If conditions are imposed

on the approval of EIA reports, are the conditions satisfied?

(d) In addition to the above approvals, have other required environmental

permits been obtained from the appropriate regulatory authorities of the host

country's government?

(a) Based on the categorisation of this project, an EIA report is not

required.

(b) Based on the categorisation of this project, an EIA report is not

required.

(c) Based on the categorisation of this project, an EIA report is not

required.

(d) Environmental permit and licence is not required for reconductoring

project, but notification to Ministry of Environment and local state office

is required.

(2) Explanation

to the Local

Stakeholders

(a) Have contents of the project and the potential impacts been adequately

explained to the Local stakeholders based on appropriate procedures, including

information disclosure? Is understanding obtained from the Local stakeholders?

(b) Have the comment from the stakeholders (such as local residents) been

reflected to the project design?

(a) Stakeholder consultation will be performed according to

environmental regulations.

(b) Any comments from stakeholders will be incorporated into project

requirements.

(3) Examination

of Alternatives

(a) Have alternative plans of the project been examined with social and

environmental considerations?

(a) The alternative plan, which is to build a new transmission line, will

have greater environmental impact that a re-conductoring.

2 Pollution

Control (1) Water Quality

(a) Is there any possibility that soil runoff from the bare lands resulting from

earthmoving activities, such as cutting and filling will cause water quality

degradation in downstream water areas? If the water quality degradation is

anticipated, are adequate measures considered?

(a) As this is a re-conductoring of existing transmission line, no additional

impact on soil runoff is expected and no significant impact on water

quality is expected. However, any water quality degradation issues will be

countered with adequate measures.

3 Natural

Environment

(1) Protected

Areas

(a) Is the project site located in protected areas designated by the country’s laws

or international treaties and conventions? Is there a possibility that the project

will affect the protected areas?

(a) The reconductoring of the transmission line does not pass through any

protected areas

6-4





(2) Ecosystem

(a) Does the project site encompass primeval forests, tropical rain forests,

ecologically valuable habitats (e.g., coral reefs, mangroves, or tidal flats)?

(b) Does the project site encompass the protected habitats of endangered species

designated by the country’s laws or international treaties and conventions?

(c) If significant ecological impacts are anticipated, are adequate protection

measures taken to reduce the impacts on the ecosystem?

(d) Are adequate measures taken to prevent disruption of migration routes and

habitat fragmentation of wildlife and livestock?

(e) Is there any possibility that the project will cause the negative impacts, such

as destruction of forest, poaching, desertification, reduction in wetland areas,

and disturbance of ecosystem due to introduction of exotic (non-native invasive)

species and pests? Are adequate measures for preventing such impacts

considered?

(f) In cases where the project site is located in undeveloped areas, is there any

possibility that the new development will result in extensive loss of natural

environments?

(a) The project does not pass through ecologically valuable habitats.

(b) The project does not pass through protected areas

(c) There is no significant ecological impacts, however mitigated

measures will be implemented if impacts are found to be significant.

(d) The project is a re-conductoring of an existing transmission line which

would not disrupt migration routes or habitat.

(e) The project passes through watery areas but no negative impact to

water quality has been observed. Appropriate mitigation measures will be

identified for any negative impacts.

(f) This project is a re-conductoring of existing transmission lines so there

are no new developments required.

3 Natural

Environment

(3) Topography

and Geology

(a) Is there any soft ground on the route of power transmission and distribution

lines that may cause slope failures or landslides? Are adequate measures

considered to prevent slope failures or landslides, where needed?

(b) Is there any possibility that civil works, such as cutting and filling will cause

slope failures or landslides? Are adequate measures considered to prevent slope

failures or landslides?

(c) Is there a possibility that soil runoff will result from cut and fill areas, waste

soil disposal sites, and borrow sites? Are adequate measures taken to prevent

soil runoff?

(a) No such soft ground has been observed along the transmission line,

but any such issues will have appropriate mitigation measures in place.

(b) There will be minimal civil works required as this is an upgrade of the

existing transmission line. However, any issues identified will have

appropriate mitigation measures developed.

(c) Same as above

6-5





4 Social

Environment

(1) Resettlement

(a) Is involuntary resettlement caused by project implementation? If involuntary

resettlement is caused, are efforts made to minimize the impacts caused by the

resettlement?

(b) Is adequate explanation on compensation and resettlement assistance given

to affected people prior to resettlement?

(c) Is the resettlement plan, including compensation with full replacement costs,

restoration of livelihoods and living standards developed based on

socioeconomic studies on resettlement?

(d) Are the compensations going to be paid prior to the resettlement?

(e) Are the compensation policies prepared in document?

(f) Does the resettlement plan pay particular attention to vulnerable groups or

people, including women, children, the elderly, people below the poverty line,

ethnic minorities, and indigenous peoples?

(g) Are agreements with the affected people obtained prior to resettlement?

(h) Is the organizational framework established to properly implement

resettlement? Are the capacity and budget secured to implement the plan?

(i) Are any plans developed to monitor the impacts of resettlement?

(j) Is the grievance redress mechanism established?

(a) No involuntary settlement is required as the project does not require

additional land acquisition or right-of-way.

(b) Public consultation will be conducted to explain the project. No

resettlement is required.

(c) Same as above

(d) Same as above

(e) Same as above

(f) Same as above

(g) Same as above

(h) Same as above

(i) Same as above

(j) Same as above

(2) Living and

Livelihood

(a) Is there a possibility that the project will adversely affect the living

conditions of inhabitants? Are adequate measures considered to reduce the

impacts, if necessary?

(b) Is there a possibility that diseases, including infectious diseases, such as HIV

will be brought due to immigration of workers associated with the project?

Are adequate considerations given to public health, if necessary?

(c) Is there any possibility that installation of structures, such as power line

towers will cause a radio interference? If any significant radio interference is

anticipated, are adequate measures considered?

(d) Are the compensations for transmission wires given in accordance with the

(a) During construction, the project may require temporary use of land

below the transmission line. Changes to the electromagnetic fields is

expected as a result of the upgrading. However, these impacts are not

expected to be significant and will be minimised.

(b) Adequate health and safety plans will be developed for this project

during construction.

(c) No changes to the noise level is expected as a result of this project.

(d) No compensation is required since no right-of-way or land acquisition

is required.

6-6





domestic law?

4 Social

Environment

(3) Heritage

(a) Is there a possibility that the project will damage the local archeological,

historical, cultural, and religious heritage? Are adequate measures considered to

protect these sites in accordance with the country’s laws?

(a) The project does not pass through any local archeological, historical,

cultural or religious heritage.

(4) Landscape (a) Is there a possibility that the project will adversely affect the local landscape?

Are necessary measures taken?

(a) The project is an upgrade of existing transmission lines so the impact

on local landscape is minimal.

(5) Ethnic

Minorities and

Indigenous

Peoples

(a) Are considerations given to reduce impacts on the culture and lifestyle of

ethnic minorities and indigenous peoples?

(b) Are all of the rights of ethnic minorities and indigenous peoples in relation to

land and resources respected?

(a) This project does not impact on ethnic minorities and indigenous

people.

(b) Same as above.

(6) Working

Conditions

(a) Is the project proponent not violating any laws and ordinances associated

with the working conditions of the country which the project proponent should

observe in the project?

(b) Are tangible safety considerations in place for individuals involved in the

project, such as the installation of safety equipment which prevents industrial

accidents, and management of hazardous materials?

(c) Are intangible measures being planned and implemented for individuals

involved in the project, such as the establishment of a safety and health

program, and safety training (including traffic safety and public health) for

workers etc.?

(d) Are appropriate measures taken to ensure that security guards involved in the

project not to violate safety of other individuals involved, or local residents?

(a) No laws associated with the working conditions of the country will be

violated

(b) Adequate health and safety measures will be developed during

construction and operation of the transmission line.

(c) Same as above.

(d) Appropriate measures will be taken to ensure that safety of individuals

and local residents are not violated.

5 Others

(1) Impacts

during

Construction

(a) Are adequate measures considered to reduce impacts during construction

(e.g., noise, vibrations, turbid water, dust, exhaust gases, and wastes)?

(b) If construction activities adversely affect the natural environment

(ecosystem), are adequate measures considered to reduce impacts?

(c) If construction activities adversely affect the social environment, are

(a) During constructions, environmental management and monitoring

plan will be in place to reduce any impact.

(b) Same as above

(c) Same as above

6-7





adequate measures considered to reduce impacts?

(2) Monitoring

(a) Does the proponent develop and implement monitoring program for the

environmental items that are considered to have potential impacts?

(b) What are the items, methods and frequencies of the monitoring program?

(c) Does the proponent establish an adequate monitoring framework

(organization, personnel, equipment, and adequate budget to sustain the

monitoring framework)?

(d) Are any regulatory requirements pertaining to the monitoring report system

identified, such as the format and frequency of reports from the proponent to the

regulatory authorities?

(a) A monitoring program will be developed for potential impacts.

(b) Same as above.

(c) Same as above.

(d) The monitoring system will be developed in line with regulatory

requirements in consultation with regulatory authorities.

6 Note

Reference to

Checklist of

Other Sectors

(a) Where necessary, pertinent items described in the Road checklist should also

be checked (e.g., projects including installation of electric transmission lines

and/or electric distribution facilities).

(a) Not applicable

Note on Using

Environmental

Checklist

(a) If necessary, the impacts to transboundary or global issues should be

confirmed, (e.g., the project includes factors that may cause problems, such as

transboundary waste treatment, acid rain, destruction of the ozone layer, or

global warming).

(a) Not applicable

6-8

6.2.2 Project classification according to JICA’s Guidelines

(1) Category of this project

According to Appendix 3 of JICA’s Guidelines, power transmission and distribution lines involving large-scale

involuntary resettlement, large-scale logging, or submarine electrical cables are listed as sensitive sectors and

would need to be classified into Category A. However, as this project consists of a re-conductoring of existing

transmission lines, there are no sensitive characteristics and neither does it affect any sensitive areas. Thus,

according to the Guidelines, this project can be classified into Category B. This needs to be further confirmed with

JICA upon environmental review.

(2) Environmental impact assessment

It is not necessary for Category B projects to submit EIA report.

6.3 Host country’s environmental regulations and standards

6.3.1 Outline of Environment-Related Laws and Regulations of Host Country

In Indonesia, the Ministry of Environment (MoE) takes charge of the general matters related to environment in

Indonesia. It is responsible for developing and implementing policies and plans regarding environmental

management, and is engaged in prevention of environmental pollution and damage, mitigation of serious

environmental impact, and restoration of environmental quality as a part of its duties. It is the central agency

responsible for environmental assessment and management.

Indonesia first introduced a system of Environmental Impact Assessment (EIA or AMDAL, Analisis Mengenai

Dampak Lingkungan Hidup) in 1986, and details of the AMDAL are mandated in Article 2 of Law Number

32/2009 on the Environmental Protection and Management (Environmental Law), the most recent law for

environmental protection. Since the enactment of the Environmental Law, Government Regulation 27 of 2012 on

Environmental Licences has made it mandatory for businesses to procure an Environmental Licence before

getting their business licence. Obtaining an Environmental Licence entails the preparation of an AMDAL or an

environmental monitoring and management plan (UKL-UPL), depending on the categorization of the project.

Public consultation is a requisite component of the AMDAL process and is embedded in Articles 22 and 26 of the

Environmental Law.

The EIA process is composed of the following major steps:

1. Public Notice and Consultation

2. Preparation of the Terms of Reference (KA-ANDAL)

3. Preparation of ANDAL, RKL and RPL

4. Approval of ANDAL, RKL and RPL

5. Approval of AMDAL documents

6-9

The format of the AMDAL documents is provided in Section 2.1b of MoE’s Regulation No. 08/2006, which

consists of:

1. Terms of Reference (KA-ANDAL)

2. Analisis Dampak Lingkungan (ANDAL or EIA report)

3. Rencana Pengelolan Lingkungan (RKL or Environmental Management Plan)

4. Rencana Pemantauan Lingkungan (RPL or Environmental Monitoring Plan)

5. Ringaksan Eksutif (Executive Summary)

Before beginning the EIA study, the project proponent needs to inform the relevant environmental impact

agency of the project. This approving environmental agency is dependent on the nature and location of the project.

Approval for the EIA may be granted at the central government level at MoE, or at the provincial level or district

level. The geographical boundaries for the project usually define the approving agency and for a transmission

project which crosses different provinces, the approval would usually lie with the central government (i.e. MoE).

Figure 6-2 shows the procedure of implementing environmental assessment in the scenario where EIA approval

is required.

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Figure 6-2AMDAL Procedures

(Source: Ministry of Environment, 2012)

ANDAL and RKL-RPL review: 75 working days, including 10 days for public consultation

ToR Review: 30 working days

Public Notice and Public Consultation

(10 working days)

Formulate ToR (KA-ANDAL)

Submit ToR for review

Administrative Appraisal by the Secretariat

Technical Review by Technical

Team

Decision on ToR approval

by Head of EIA

commission

Formulate ANDAL and RKL-RPL

Submission of application letter for

Environmental Licence and ANDAL and RKL-RPL review

Administrative Appraisal by the Secretariat

Technical Review by Technical

Team

ANDAL and

RKL-RPL review by

EIA commission

Public notice on Environmental Licence Application

Recommend-ation

Decision on Environmental

Feasibility and issue of Environmental

Licence

Public notice of decision on

Environmental Licence

Project Proponent EIA Secretariat Technical Team and Commission

Approving agency

6-11

Ministry of Environment Regulation No. 5/2012 prescribes a list of projects and activities that require an

AMDAL. For projects dealing with power transmission lines above 150 kV, this regulation stiupalates that an

EIA is required. Table 6-2 summarizes the details of the power projects that requires an AMDAL according to the

laws of Indonesia. In the case where a new power transmission line carrying 500 kV is installed, the AMDAL

procedure in Figure 6-2 above needs to be followed.

Table 6-2List of Power sector activities that require AMDAL

Activity Criteria

Development of transmission network > 150kV

Diesel, gas, coal fired power plants ≥ 100MW in one location

Geothermal power plant ≥ 55MW

Hydropower plant Height: ≥ 15m

Area: ≥ 200ha

Capacity ≥ 50MW

Other types of power plants (solar, wind, biomass, etc.) ≥ 10 MW

(Source: MoE Regulation No. 5/2012)

As this project is to re-conductor existing transmission lines instead of installing new ones, it is considered that

its impact on environment is only minor, and that the full AMDAL procedure is not necessary. Land acquisition

and social resettlement are not required for this project, but attention must be paid to avoid damage to surrounding

vegetation during reconductoring. From PLN’s experience, the AMDAL procedure during the 1990s for the

existing transmission line from Suralaya to Gandul, did not encounter any material issues.

In our discussions with MoE so far, modifications to an existing project with a valid environmental license need

not undergo the full AMDAL procedure. Only an amendment or update to the existing AMDAL and UKL-UPL is

necessary which drastically shortens the environmental approval process. In discussions with PLN Environmental

Sub-division, as the project involves only reconductoring in the existing right of way, the reconductoring project

for the Suralaya-Gandul line requires notification to MoE, together with the local office in the state of Banten.

Still, the necessity of the environmental research should be further examined in consultation with the host

government.

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6.3.2 Details of Environmental Impact Assessment of the Host Country required for the

Project

The following are the details of contents in the AMDAL of the host country required for implementing a project

for constructing a new power transmission line carrying 500 kV.

① Introduction of project

a) Project overview

This study is to perform an upgrade of the current transmission line using the current transmission line along the

Suralaya-Gandul 500kV line, as a measure against an electrical overload of the transmission line expected in

connection with the ambitious 35GW program, especially in the West Java area with plans for new power plants.

b) Project rationale

In line with the growing electricity demand and plan for 35GW of new power plants in Indonesia, the new

transmission line will help to develop greater access to electricity and enable the connection of new installed

power capacity in more efficient and environmentally friendly way.

c) Environmental policy

Since the purpose of this project is to perform re-conductoring the transmission line, the

impact towards the environment is minimized, but if there is an impact to the environment, the laws and

regulations of Indonesia will be adhered to.

d) Relevant regulations

Indonesia Law regulates the electrostatic magnetic intensity, corona noise, radio noise, but as said in the

previous section, all such issues lie within the regulated limits.

② Items of research

While additional EIA submission would not be required for this upgrading project, typical scope of

environmental consideration is described as below.

a) Environmental impact

Climate

Air Quality

Water Quality

Land

Physical geology

Soil

b) Scope of ecological impact

The ecological impact shall be confirmed at the area of the project and will consider any Right-of-Way

encroachment, protected areas and flora and fauna. It covers the diameter of 30m from where the project is

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implemented.

c) Scope of socio-economic impact

The study would confirm the current corona noise, radio noise, and the electrostatic magnetic impact on affected

persons, including any impact as a result of loss of livelihood as a result of Right-of-Way or land acquisition

required, and appropriate compensation measures.

③ Outline of research

a) Collection of data related to environmental impact

・Climate:

Collect the data for climate, humidity, rainfall, atmospheric pressure, wind speed, wind direction for the past

10years and create a data file.

・Air quality and noise:

Air pollutants and real measurement of noise are performed for the degree of air pollution at three places. It will

be analyzed based on the ambient air quality standards under Regulation No.41 of 1999, and noise standards

based on Ministry of Environment Decree No. 48/MNLHJ III/1996.

Table 6-3Government Regulation No.41 of 1999 on Ambient Air Quality Standards

Pollutant Monitoring Duration Government Standard (mg/Nm3)

PM10 Annual Average No annual standard

24 hour average 0.15

PM2.5 1 year 15 µg/Nm3

24 hour 65 µg/Nm3

O3 1 year 50 µg/Nm3

1 hour 235 µg/Nm3

SO2 Annual average 0.100

24hour average 0.365


NO2 Annual average 0.100

24hour average 0.150


6-14

Table 6-4 MoE Decree No. 48/MNLHJ III/1996 on Noise Standards

Category One Hour Leg dB(A)

Day Night

Green Areas 50 -

Hospitals and Health Zone 55 -

Mixed residential, education and religious areas 55 -

Office and commercial 65 -

Government and public facilities 70 -

Recreation 70 -

Industrial areas 70 -

・Water quality:

The water quality must be gathered from the surrounding land, a river, and a puddle and the following pollutants

are investigated. The result shall be compared with Government Surface Water Quality Standards under

Government Regulation No. 82 of 2001.

6-15

Table 6-5 Government Regulation No 82 of 2001 on Surface Water Quality Standards

No Parameter Unit Class I Class II Class III Class IV

10.00 25.00 50.00 100.00

1 BOD5

2.00 3.00 6.00 12.00

2. DO mg/l 6 4 3 0

3. N-Nitrite mg/l 0.06 0.06 0.06 (-)

4. Sulfide (H2S) mg/l 0.002 0.002 0.002 0.002

5. Temperature o C Dev. 3 Dev. 3 Dev. 3 Dev. 5

6. pH - 6 - 9 6 – 9 6 - 9 5 - 9

7. Electric Conductivity mS/cm - - - -

8. TDS NTU 1000 1000 1000 2000

9. NO3 mg/l 10 10 10 20

10. PO4 mg/l 0 0 1 5

11. SO4 mg/l 400 (-) (-) (-)

12. Iron (Fe) mg/l 0.30 (-) (-) (-)

13. Manganese (Mn) mg/l 0.10 (-) (-) (-)

14. Copper (Cu) mg/l 0.02 0.02 0.02 0.20

15. Zinc (Zn) mg/l 0.05 0.05 0.05 2.00

16. Lead (Pb) mg/l 0.03 0.03 0.03 1.00

17. Cadmium (Cd) mg/l 0.01 0.01 0.01 0.01

18. Chromium mg/l 0.05 0.05 0.05 1.00

19. Oil & Grease µg/l 1,000 1,000 1,000 -

20. Radiation Total α Bq/l 0.10 0.10 0.10 0.10

21. Radiation Total β Bq/l 1.00 1.00 1.00 1.00

22. Fecal Coliform no/100 ml 100 1,000 2,000 2,000

23. Total Coliform no/100 ml 1,000 5,000 10,000 10,000

Notes:

Class I: water can be used for drinking and other uses that require similar water quality.

Class II: water can be used for infrastructure/water recreation facilities, the cultivation of freshwater fish, livestock, irrigating crops,

and other uses that require similar water quality.

Class III: water can be used for freshwater fish farming, animal husbandry, irrigating crops, and other uses that require similar

water quality.

Class IV: water allocation can be used to irrigate crops, and other uses that require similar water quality

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・Land use

Regarding the land for construction, the migration plan and transportation barrier should be discussed with

Bappeda (Regional Planning Agency) along with Area Space Management Plan (RTRW) during the

construction period.

・Physical geology:

The current height interval of the land and past data of the height interval shall be used to collect the materials

for the measurement of Physical geography and geology. The project shall be implemented using digital data of

geographical features.

・Soil:

Pervasion of land accompanying the project execution and change of the degree of fertility are tested by

comparison to Land Observation Guideline (LTP, 1969) through a site survey and soil investigation. The

comparison will also take into consideration a map, a height interval, precipitation, and etc. The study is

conducted by using the boring method and soil testing method which includes the physical and chemical

characteristic of the soil which is based on “Soil Characteristic Analysis Data Assessment Criteria” in 1983 by

Land Research Centre.

b) Collection of data related to ecological impact

・Flora:

To obtain data concerning types of flora in the activity plan area and its surrounding area, inventory carried

through a field investigation and creates a table. Data that are collected are then analyzed by using SDR method

(Summed Dominant Ratio).

・Fauna:

A fauna observation is carried out using a survey method, whereas its data collection technique is carried out

using a point count data collection for the community of birds and a cruise method for mammals, amphibians, and

reptiles.

c) Collection of data related to socio-economic impact

The data is collected from government and private institutions or services that are related with the project

activities along with data which includes the total population, types of institution, economy, politics, various

social data and culture. But the primary data comes from the people who are actually living at the sites by

conducting a direct interview. At the same time a study will be carried out to determine the population density, sex

distribution rate, age distribution rate.

d) Collection of data regarding health of residents

Collection of data from the regional Public Health Centre and a hearing to the residents of the project area is

required. Also a study must be conducted for environment sanitation condition, health status, types of principal

6-17

diseases, epidemiologic prevalence and existing health service should be conducted.

④ Environmental research plan

a) Members of environmental research team

The following engineers should be hired to implement the environmental study.

- High tension electricity expert

- Air and noise quality expert

- Biologist

- Geologist

- Civil Expert

- Socio-economic & cultural expert

- Public health expert

- Environmentalist

b) Activities required for environmental research

PLN, who is in charge for the stable supply of electricity in Indonesia, is liable to conduct the increase in

capacity of the transmission line.

c) Activities conducted at research area

For re-conductoring transmission line, there is the need to obtain temporary land for the drum and engine. But in

result of our field study, temporary land can be obtained from the land below the existing Transmission Line. If

up-rating conductors are not used and constructing a new transmission line is used as an alternative,

obtaining the Right-of Way would be necessary. Therefore there are the merits in up-rating conductors.

⑤ Environment of research area (current situation)

As a result of the field study most of the land is farmland and mountains there are no need to obtain new land.

But in densely populated residential areas, temporary use of land can be chosen where it best fits the condition.

Some of the transmission towers pass through watery land, but no negative impact on water quality has been

reported so far. After re-conductoring, no negative impact to water quality would be expected as well.

On 17 Nov 2015, Study Team members visited a couple of transmission towers near dense residential areas and

watery areas (towers 223-225 and 212-213), selected as potential environmentally and socially sensitive spots

with accompany of officials of PLN Planning Division and P3B. However, no material issues affecting the

environment were discovered based on the observation described in Table 6-6. Figure 6-3 shows a transmission

tower near agricultural field.

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Table 6-6 Observation near sensitive locations

Tower 223 – 225 Tower 212 – 213

Location category : Residential, surrounded

by house and small scale farming area

Pollution control :The transmission tower

223 – 225 does not pass through river or

stream; they are some other towers passing

through but reportedly didn’t have negative

impact related to water quality.

Natural environment: The transmission

tower 223 – 225 does not pass through

protected area, and no protected area has

been seen around the tower.

Location category: Slump. None of

residential house was visible around the

towers.

Pollution control : Although the

transmission towers 212 – 213 are located

in watery land, there’s no report of

negative impact related to water quality.

Natural environment : The transmission

towers 212 – 213 does not pass through

protected area and no protected area noted

around the tower.

Figure 6-3Transmission tower built in water near agricultural field along Gandul – Balaraja

Transmission Line (Tower 212-213)

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⑤ Environment of research area (forecast) As mentioned above, there is no need to obtain temporary land. Table 6-7 shows the environmental impact to

this region.

Table 6-7 Environment Impact

Items Re-conductoring Line

Environmental Impact

Before Construction ・ The current Right of Way is available therefore there is no

impact to the environment


During Construction ・ Temporary space below the existing right-of-way under the

transmission line for the drum and engine for reconductoring is required.

New felling is not needed.


During Operation ・ The electric field intensity of the new conductor for

Suralaya―Gandul Line has an electric field intensity of 4.9kV/m, which

is within regulation limits.

・ Maximum magnetic field intensity is half the regulation.

・ There are only small changes to the Radio noise level and Corona

noise level, therefore the increase to the impact to the environment is

small.


After Operation ・Same as above

7-1

Chapter7. Financial and Economic Feasibility

In order to ensure that the project is feasible on an economic and financial standpoint, an economic and financial

analysis of the project was conducted. The economic analysis will determine whether the project is feasible based

on comparison between other alternatives on the “With” and “Without (= the alternative option)” principle from

national economy point of view. The financial analysis determines whether the project provides sufficient

financial benefits to the project proponent given the amount of upfront capital investment required.

7.1 Capital Costs of Project

7.1.1 Construction Process and Implementation Period

As shown in Chapter 8, the construction process of this project takes 36 months from selection of consultant to

completion of operations including re-conductoring of power transmission lines and remodeling of substations.

The followings are the major operations included in the construction process.

• Selection of consultant: 6 months

• Selection of subcontractor (including PQ, preparation of bid documents, evaluation, contract

negotiation, etc.): 12 months

• Re-conductoring (Suralaya-Gandul Line; including research, designing, procurement, installation,

etc.): 17 months

• Remodeling of substations (3 substations of Suralaya, Balaraja and Gandul): 18 months

• Completion of construction: 18 months after conclusion of contract

The economic analysis will be made inclusive of the one-year guarantee.

7.1.2 Capital Costs and Assumptions

(1) Construction Cost

The construction cost to be used for economic and financial analysis includes the following costs in addition to

the total construction cost.

• Cost of re-conductoring Suralaya - Gandul Line and remodeling related substations: US$107.8 million

• Contingency cost: US$10.78 million (10% of the cost of re-conductoring)

• Engineering cost: US$5.39 million (5% of the cost of re-conductoring)

• Administration cost: US$10.78 million (10% of the cost of re-conductoring)

7-2

(2) Terms and conditions of quotation

It is presupposed that this project will be initiated on the Japanese Soft Loan, and the quotation is given under

the terms and conditions below.

① Construction process: As per [Figure 8-1]

② Tax matters: It is assumed that this project will be exempted from custom duties and service tax

(Indonesian equivalent of VAT).

③ Price escalation: Price escalation will not be considered for both domestic and foreign currencies.

④ Cost of land acquisition and compensation: Such cost will not be considered as it is not required for

reconductoring project.

⑤ Contingency fund: 10% is included.

⑥ Payment terms are as follows.

• Advance payment: 20%

• Payment at piece rate: 70%

• Payment at completion: 5%

• Final payment at handover (assumed to be 1 year after completion): 5%

Tables 7-1 and 7-2 shows the details of construction cost and the year-by-year breakdown, respectively with a

break-down of the total capital cost by components.

Table 7-1Details of Construction Cost of redoncuctoring

Category

Foreign

Currency

(Million US$)

Local

Currency

(Million US$)

Total

(Million US$)

A Project Cost

1 Suralaya - Gandul T/L incl. related

substations 81.80 26.00 107.80

Total of A. Project Cost 81.80 26.00 107.80

B Contingency

1 Price Escalation (0%) 0.00 0.00 0.00

2 Physical Contingency (10%) 8.18 2.60 10.78

Total of B. Contingency 8.18 2.60 10.78

C Consulting Services (5% of A) 4.09 1.30 5.39

D Total of the Eligible Portion (A+B+C) 94.07 29.90 123.97

E Administration cost (10% of A) 0.00 10.78 10.78

F Land Acquisition & Compensation 0.00 0.00 0.00

G Taxes (sales and custom duties) 0.00 0.00 0.00

H Grand Total (D + E +F + G) 94.07 40.68 134.75

7-3

Table 7-2 Yearly Breakdown of Construction Cost of reconductorin

The yearly breakdown was prepared on the basis of the terms and conditions of quotation mentioned in 7.1.2,

construction process in Figure. 8-1, and construction cost in Table 7-1, while the following was taken into

consideration.

• The re-conductoring of power transmission lines takes 18 months. Therefore, the construction cost

(including cost of remodeling the substations) of each year consists of the following :

for 2018, when the construction is to be launched, advance payment (20% of the total construction

cost) and 6 months of progress payment (6 months/18 months) for the period during which the

construction is performed were added;

for 2019, payment at completion (5% of the total construction cost) and 12 months of progress

payment (12 months/18 months) were added and

for 2020, final payment at handover (5% of the total construction cost) was entered.

• The consulting cost was assumed to be composed of progress payment only. As the consulting period

extends over 30 months, the progress payment of each year was 6 months (6 months/30 months) in 2017,

and 12 months (12 months/30 months) in 2018 - 2019, respectively.

• The administration cost was recorded each year in the same manner as the consulting cost was calculated.

(Unit: US$1000)

Items FC LC FC LC FC LC FC LC FC LC

A. Project Cost

1 Suralaya - Gandul T/L incl. related substations 0 0 35,447 11,267 42,263 13,433 4,090 1,300 81,800 26,000 107,800

0 0 35,447 11,267 42,263 13,433 4,090 1,300 81,800 26,000 107,800

0 0 2,727 867 5,453 1,733 0 0 8,180 2,600 10,780

818 260 1,636 520 1,636 520 0 0 4,090 1,300 5,390

818 260 39,810 12,654 49,352 15,686 4,090 1,300 94,070 29,900 123,970

0 2,156 0 4,312 0 4,312 0 0 0 10,780 10,780

0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0

818 2,416 39,810 16,966 49,352 19,998 4,090 1,300 94,070 40,680 134,750

G. Taxes (sales and custom duties)

Grand Total

Total of A. Project Cost

C. Consulting Services

B. Contingency

F. Land Acquisition & Compensation

D. Total Eligble Portion (A+B+C)

E. Administration Cost

YearGrand Total

Total2017 202020192018

7-4

7.2 Economic Analysis

7.2.1 General Approach and Methodology

The general approach to the economic analysis is conducted in the following procedures:

− Identification and calculation of the economic cost and economic benefit of the project

− Comparison between the economic cost and economic benefit

− Calculation and evaluation of Economic Internal Rate of Return

− Sensitivity analysis of the results of the above comparison and evaluation

To compare the economic cost and economic benefit for the entire period of the project life, a model based on a

cashflow analysis is developed where the future streams of economic costs and benefits are projected throughout

the life of the transmission project. In doing so, the Economic Internal Rate of Return (EIRR) can be calculated.

This is the return ratio that keeps the total amount of net present value of the economic cost (C) equal to the

economic benefit (B) that satisfies the formula B/C=1.

Conversely, we can also calculate the NPV of the economic costs and benefits based on a discount rate which is

representative of the opportunity cost of capital. Generally speaking, international financial institutions such as the

World Bank and Asian Development Bank set the discount rate (opportunity cost of capital) for developing

countries within the range between 8 and 12%. From the Previous Report, 10% was adopted as the criteria of

decision. In this analysis, the discount rate in Indonesia is assumed to be 10% according to the international

practices, and it will be compared with the EIRR to examine the cost-effectiveness of the

project. The project is economically viable when the economic benefits outweigh the economic cost (B/C >1).

In this economic analysis, the "With and Without Principle" is applied, and the case where the proposed project

(re-conductoring of transmission lines and substation remodelling) is implemented (With) and the case where an

alternative plan (new construction of transmission lines and substations) is implemented (Without) are compared.

The “Without” scenario presents the Avoided Cost of the project, or the benefit of the proposed project as a result

of avoiding the alternative plan. The economic costs and benefits are assessed based on the information from the

technical analysis of the project’s capital cost and expenditures during construction including physical contingency,

administration and consulting services as described above.

"With and Without" scenarios are defined as follows in this economic analysis:

− With (Economic Cost) : Re-conductoring of the existing transmission lines to lines carrying increased

voltages in addition to remodeling of substations

− Without (Economic Benefit) : Construction of new 500 kV transmission lines having transmission

capacity equivalent to the increase of capacity this project provides.

7-5

7.2.2 Economic Benefit

According to the “With and Without” Principle, the economic benefit of this project is represented by the

construction cost of the alternative project. The alternative project refers to the construction of new 500 kV

transmission lines having transmission capacity equivalent to the increase of capacity this project provides. This is

the only alternative as the transmission network can only be upgraded through new transmission lines or by

re-conductoring. The economic benefit thus consists of the construction cost of new 500 kV transmission lines

having transmission capacity equivalent to the increase of capacity achieved by the re-conductoring, and the

operation and maintenance cost. However, the Study Team considers that building a new transmission line could

be very challenging as acquiring new land for the transmission line would be difficult due to densely populated

areas along the route.

The details of such costs as estimated by the Study Team are as follows:

(1) Construction cost of new 500 kV transmission lines

Suralaya - Gandul Section

The size of the conductor is decided so that the same capacity as in the case of re-conductoring can be

approximately secured. The followings are the details of the specifications:

- Voltage, 500 kV; the number of transmission lines, 2 lines; and total route length, 222 km

- Size and number of conductors, double circuit ACSR Zebra conductors (total transmission capacity with new

transmission line, 4,070 MW). Based on the past data of PLN, the construction cost is estimated at US$116.3

million.

(2) Land acquisition costs and right-of-way compensation for new 500kV transmission lines

As the new transmission line will need to acquire additional land for transmission towers and right of way

compensation, it is necessary to include such costs when estimating project costs. Based on a similar project for a

new 500kV transmission line in Central and West Java, the land acquisition and right-of-way compensation was

US$8.26 million for a 343km transmission line.

- Land acquisition and right-of-way compensation for new 500kV transmission line: US$ 2.68million

(3) Remodeling of Substations

Similar to the previous report, it is necessary to remodel the related substations to increase the substation

facilities due to the additional transmission lines.

- Suralaya - Gandul Section (Suralaya, Gandul and Balaraja Substation): US$24.2 million

(4) Annual operation and maintenance cost

Following the construction of new transmission lines and the related substations, the annual operation and

maintenance cost will increase to the degree of related capital and operation and maintenance costs. The increased

cost is included in the economic benefit.

Based on the similar cases in the other countries, the unit costs of operation and maintenance costs of the

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transmission lines and the related substation facilities are estimated as follows (estimated by the

Study Team):

- 500 kV transmission lines: US$1,000/km/year

- 500 kV substations: US$340,000/substation/year

The operation and maintenance cost of the increased substation bays only is included in the economic benefit

(estimated to result in 20% increase).

As a result, the annual total operation and maintenance costs are estimated as follows:

- Suralaya - Gandul Line: US$1,000/km/year/line×110km×2 lines = US$222,000/year

- Substations: US$340,000/substation/year×20%×3 substations = US$204,000/year

As the construction of new transmission lines requires acquisition of land and compensation, and a longer

procurement period, it is assumed that the operation will be launched in 2021, compared to the proposed upgrade

project assuming the year of operation as 2020. The construction cost of the new transmission line is shown in

Table 7-3.

Table 7-3 Economic benefit of construction of new transmission line (alternative option)

7.2.3 Economic Cost

The economic cost is represented by the construction cost of this project (more specifically, direct construction

cost consisting of labor cost including pay for both skilled and unskilled workers, fuel cost, construction

machinery cost, equipment cost, compensation cost, engineering cost, administration cost, contingency, etc.).

Local currency and foreign portion of the project is derived from cost estimates from a local EPC contractor.

Local currency primarily consists of labour costs and foreign currency portion is for foreign equipment. For the

purposes of calculating economic cost, value added tax and corporate income tax are excluded because they are

transferred to the government’s budget.

The total economic costs summarized in Table 7-4 are compiled by collecting construction

cost, escalation, contingency, consulting cost, administration cost and land acquisition cost on the basis of the

yearly breakdown shown in Table 7-2.

(Unit: US$1000)

Items FC LC FC LC FC LC FC LC FC LC

A. Project Cost

1 Suralaya - Gandul T/L incl. related substations 0 0 43,723 6,673 52,132 7,957 5,045 770 100,900 15,400 116,300

0 0 43,723 6,673 52,132 7,957 5,045 770 100,900 15,400 116,300

0 0 3,363 513 6,727 1,027 0 0 10,090 1,540 11,630

1,010 154 2,020 308 2,020 308 0 0 5,050 770 5,820

1,010 154 49,106 7,494 60,879 9,292 5,045 770 116,040 17,710 133,750

0 2,326 0 4,652 0 4,652 0 0 0 11,630 11,630

0 2,680 0 0 0 0 0 0 0 2,680 2,680

0 0 0 0 0 0 0 0 0 0 0

1,010 5,160 49,106 12,146 60,879 13,944 5,045 770 116,040 32,020 148,060

Year

G. Taxes (sales and custom duties)

Grand Total

Total of A. Project Cost

C. Consulting Services

B. Contingency

F. Land Acquisition & Compensation

D. Total Eligble Portion (A+B+C)

E. Administration Cost

Grand TotalTotal2018 202120202019

7-7

Table 7-4 Economic Cost of the Project

(Unit: 1,000US$)

Year 2017 2018 2019 2020 Total

Economic 3,234 56,776 69,350 5,390 134,750

In implementing the economic evaluation of the project, the operation and maintenance cost of transmission

lines and substations is usually included in the economic cost. However, as this project proposes re-conductoring

of the existing transmission lines and replacement of equipment in the substations, the operation and maintenance

cost will not change as the quantity of equipment remains the same after re-conductoring. In other words, it is

assumed that the operation and maintenance cost will be the same before and after the re-conductoring. Therefore,

it was not included in the economic cost.

7.2.4 Project Life and Operation Period

The economic cost and economic benefit are calculated over the entire period of the project life. The first year of

the project life refers to the year when the first portion of the cost for the project is paid27, and the last year refers

to the year when the operation and maintenance of the constructed project facilities are discontinued.

The operation period of the power transmission lines to be constructed in this project is assumed to be 30 years

after the total construction period of 4 years (from 2017 through 2020).

7.2.5 Result of economic evaluation

The evaluation of cost-benefit of the project is performed by using the cash flow analysis of the economic cost

and economic benefit identified above and shown in Table 7-5 below. The results of the calculation are shown in

Tables 7-5 and 7-6.

In the economic analysis, the benefit-cost ratio (B/C ratio) indicates the result of comparison between benefit

and cost converted into net present values, while the benefit-cost difference (B-C) shows the difference between

them as also represented in net present values.

Economic Costs Economic Benefits

Cost incurred in implementing this project

(including re-conductoring cost, remodeling cost

of related substations, construction-related

contingency, consultant cost, administration cost

and land acquisition cost) + operation and

maintenance cost

Avoided construction cost of new 500 kV

transmission lines as an alternative to this project

+ remodeling cost of related substations +

operation and maintenance cost

27 In this project, the first year is assumed to be the year when the consulting services are started.

7-8

The Economic Internal Rate of Return (EIRR) serves as an index to determine the economic feasibility of the

project. EIRR is obtained by the following formula:

�𝐶𝑡

(1 + 𝑅)𝑡=

𝑡=𝑇

𝑡=1

�𝐵𝑡

(1 + 𝑅)𝑡

𝑡=𝑇

𝑡=1

- T: The last year of the project life

- Ct: Cash flow of annual economic cost in the t-th year in the project life

- Bt: Annual benefit yielded from the alternative plan in the t-th year

- R: Economic internal rate of return

As shown in Table 7-5 and Table 7-6 below, EIRR of this project is calculated at 12.58% in the base case.

7-9

Table 7-5 Results of EIRR Calculation

Table 7-6 Results of Cost-Effectiveness Evaluation

Case EIRR (%) B/C Ratio B-C (1000 US$)

Base Case 12.58% 1.028 3,205

As mentioned above, international financial institutions such as the World Bank and Asian Development Bank

generally set the discount rate (opportunity cost of capital) for developing countries within the range between 8%

and 12%, and 10% was adopted as the criteria of decision.

As the EIRR of 12.58% obtained above exceeds 10%, the assumed discount rate (opportunity cost of capital) of

Indonesia, it can be concluded that this project is feasible from an economic standpoint.

Economic AnalysisEIRR= 12.58%

(Units : USD'000)

Capita l expenditure O&M Total (A) Capita l expenditure O&M Total (B)

2017 3,234 - 3,234 - - - (3,234) 2018 56,776 - 56,776 6,170 - 6,170 (50,606) 2019 69,350 - 69,350 61,252 - 61,252 (8,098)

1 2020 5,390 - 5,390 74,823 - 74,823 69,433 2 2021 - - - 5,815 426 6,241 6,241 3 2022 - - - - 426 426 426 4 2023 - - - - 426 426 426 5 2024 - - - - 426 426 426 6 2025 - - - - 426 426 426 7 2026 - - - - 426 426 426 8 2027 - - - - 426 426 426 9 2028 - - - - 426 426 426

10 2029 - - - - 426 426 426 11 2030 - - - - 426 426 426 12 2031 - - - - 426 426 426 13 2032 - - - - 426 426 426 14 2033 - - - - 426 426 426 15 2034 - - - - 426 426 426 16 2035 - - - - 426 426 426 17 2036 - - - - 426 426 426 18 2037 - - - - 426 426 426 19 2038 - - - - 426 426 426 20 2039 - - - - 426 426 426 21 2040 - - - - 426 426 426 22 2041 - - - - 426 426 426 23 2042 - - - - 426 426 426 24 2043 - - - - 426 426 426 25 2044 - - - - 426 426 426 26 2045 - - - - 426 426 426 27 2046 - - - - 426 426 426 28 2047 - - - - 426 426 426 29 2048 - - - - 426 426 426 30 2049 - - - - 426 426 426

Tota l : 134,750 - 134,750 148,060 12,354 160,414 25,664

Discount rate: 10%NPV ca lculations NPV of Cost: 116,212 NPV of Benefi t: 119,417

Benefi t and Cost Ratio (B/C): 1.028Benefi t and Cost Di fference (B-C): 3,205

O&M cost for a l ternative projectFor 500kV S/S: 204,000 US$/yearFor 500kV T/L: 222,000 US$/year

Operating years

YearNet Benefi t

(B) - (A)

Cost - Reconductoring Project Benefi t - New Transmiss ion Line

7-10

7.2.6 Sensitivity analysis of economic results

Since fluctuations in prices (prices of construction materials and machinery, electricity to purchase and sell, etc.)

are expected to be involved in this project due to the economic circumstances of Indonesia, sensitivity analysis

was performed on total of 8 cases where the economic cost increases by 5% or 10% and where the economic

benefit deceases by 5% or 10 %, in addition to the base case.

Table 7-7 shows the results of the sensitivity analysis.

Table 7-7Results of Sensitivity Analysis on EIRR

Benefit

Base Case -5% -10%

Base Case

+5%

+10%

12.58%

8.10%

4.52%

8.03%

4.35%

1.56%

4.17%

1.36 %

-0.75 %

As shown in the table above, if both the cost and benefit are in the base case, EIRR is 12.58% and this project is

considered feasible. If the benefit deceases or the cost increases by 5% from the base case, EIRR reduces to about

8%.

7-11

7.3 Financial Analysis

7.3.1 General Approach and Methodology

The financial analysis is performed to assess the extent of financial benefits that the project is expected to yield.

It evaluates the project from the standpoint of financial profitability on the part of the project proponent. It is used

to check whether the project proponent can manage the project in a financially independent manner.

The investment in the project is evaluated in terms of the market price, and the invested capital is the "financial

cost". The revenue yielded from the project is evaluated also in terms of the market price, and this profit is the

"financial benefit".

The financial cost and financial benefit for the entire period of the project life are projected by analyzing the

cash flow of the project. The future stream of cash flows from the project is discounted to its present value and the

Financial Internal Rate of Return (FIRR) and Financial Net Present Value are calculated. The FIRR is compared

against the opportunity cost of capital in the market, which is assumed to be the prevailing domestic interest rate.

In the present analysis, the financial benefit and financial cost constitute the following:

− Financial benefit: Wheeling income derived from the project in connection with the transmission and

substation facilities constructed in this project

− Financial cost: Cost incurred in the construction and operations of this project

7.3.2 Financial Benefit

The financial benefit of this project is the wheeling income that is generated by the implementation of this

project. By implementing this project, increase in transmitting power flow enhances the profit from gained by

PLN as it can increase electricity supply and hence, revenue and profits. This benefit can be calculated from the

wheeling revenue generated by the transmission line. In this analysis, this increase in profit is assumed to be the

financial benefit.

(1) Annual transmitting power flow

The annual transmitting power flow of the transmission lines subject to this project is assumed to be the values

shown in Table 7-8 as calculated on the basis of the power flow, load factor and available factor.

Table 7-8Annual Transmitting Power Flow

Power Flow

(MW)

Load Factor28

(%)

Available

Factor29

(%)

Annual Transmitting

Power Flow

(MWh)

Suralaya - Gandul 4,120 70% 35% 8,842,300


28 Load factor represents the ratio of the average to the maximum electric power, and in this analysis, the average value of the power plants was used.

29 Available factor represents the actual operating ratio of the facilities, and typical value for main transmission lines, 35%, was used in this analysis, which is the same as the Previous Report.

7-12

(2) Purchase and sales price of electricity

In a de-regulated market with an independent transmission operator, the revenue of the power transmission

company corresponds to the transmission charges, which is usually the difference between the sales price to the

power distributing company and purchase price from the power producing company. In Indonesia, though the

power producing company is separated from PLN as subsidiaries, power transmission and

power distribution divisions functions are incorporated in the same company.

In discussions with PLN, PLN was not able to provide a unit wheeling charge. In this analysis, the financial

benefit to PLN was calculated on the basis of the difference between the cost of electricity production and the

revenue received from electricity sales.

In December, PLN recently awarded the Java-7 project to Shenhua Energy as the winning bidder. It is

understood that Shenhua Energy submitted a very competitive tariff rate of around 5 UScents/kWh. As PLN

would be purchasing electricity from the Java-7 project at this tariff, USD 50/MWh is taken as the purchase price

of electricity from PLN in this region.

According to the Public Service Obligation (PSO), PLN will receive a subsidy equivalent to a premium over its

total operating cost. This margin over the basic cost of electricity production is taken to be the unit revenue

(inclusive of subsidies) received in electricity sales. In 2014, this margin was 7%30. We have assumed that the

average margin that PLN will continue to earn total revenues at an assumed 5% margin over its costs of electricity

supply, which has been the historical basis for the PSO obligation.

The derivation of the Unit Wheeling income based on the above analysis is as follows:

Average cost of electricity production USD 50.00 /MWh

Assumed margin x 5%

Unit Wheeling income USD 2.50 /MWh

(3) Financial Benefit to PLN

The benefit to PLN is calculated by the following formula.

(Annual Financial Benefit) = (Annual transmitting power flow) x (unit wheeling price)

Table 7-9 shows the annual wheeling income. It is assumed that the wheeling charge will be incurred starting

from 2023, the year when the operation of the transmission lines subject to this project is launched.

30 According to PLN Annual Report in 2014, PLN receives electricity subsidies from the government. The electricity subsidy is

set based on the negative difference between the average sales price minus Basic Cost of Electricity for each tariff category. This also includes a margin above the cost of supplied electricity. Based on the 2014 Approval Letter of Budget Performance List, the electricity subsidy includes a 7% margin above the cost of supplied electricity.

7-13

Table 7-9 Annual Wheeling Income

Power

Flow

(MW)

Load

Factor

(%)

Available

Factor

(%)

Annual

Transmitting

Power Flow

(MWh)

Wheeling

Price

(US$/MWh)

Wheeling

Charge

(1,000US$)

Suralaya - Gandul 4,120 70% 35% 8,842,300 2.50 22,106


7.3.3 Financial Cost

The financial cost is represented by the construction cost of this project (more specifically, direct construction

cost consisting of labor cost including pay for both skilled and unskilled workers, fuel cost, construction

machinery cost, equipment cost, compensation cost, engineering cost, administration cost, contingency, etc.). It is

assumed in this analysis that interest during construction and price escalations are not taken into consideration.

Details of the financial cost are based on the technical analysis presented in the earlier sections of this report.

The financial cost corresponds to the total construction cost of this project as shown below.

(1) Construction cost (US$134.75 million)

The construction cost consists of direct construction cost including labor cost for both skilled and unskilled

workers, fuel cost, construction machinery cost, equipment cost, compensation cost, engineering cost,

administration cost, etc. and contingency related to technical aspects of the project.

(2) Value added tax and corporate income tax (US$0)

It is assumed in this analysis that this project is exempted from value added tax and corporate income tax.

(3) Interest during construction (US$0)

Interest during construction is not considered in the evaluation of this financial analysis. Table 7-10 shows the

financial cost calculated on the basis of the above.

Table 7-10 Financial Cost

(Unit: 1,000US$)

Year 2017 2018 2019 2020 Total

Financial 3,234 56,776 69,350 5,390 134,750

As in the case of the economic cost, annual operation and maintenance cost of the power transmission lines and

the related substations are considered in the analysis.

7-14

7.3.4 Project Life and Operation Period

As mentioned in the economic analysis section, the operation period is assumed to be 30 years after the total

construction period of 4 years (from 2017 through 2020).

7.3.5 Results of Financial Evaluation

The financial evaluation the project is performed by using the projected cash flows of the financial cost and

financial benefit examined above. The results of the calculation are shown in Tables 7-11 and 7-12.

In the financial analysis, the NPV of the project is calculated using a discount rate of 10% which is assumed to

be the cost of capital. The NPV is a measure of the net financial benefits to the proponent in terms of opportunity

costs of money. If the value is greater than zero indicates, it means that the project is financially viable. The

Financial Internal Rate of Return (FIRR) serves as a major index to determine the financial feasibility of the

project by comparing it against the cost of capital. FIRR is obtained by the following formula:

�𝐶𝑓𝑡

(1 + 𝑅𝑓)𝑡=

𝑡=𝑇

𝑡=1

�𝐵𝑓𝑡

(1 + 𝑅𝑓)𝑡

𝑡=𝑇

𝑡=1

- T: The last year of the project life

- C f t: Cash flow of annual financial cost in the t-th year of the project

- B f t: Cash flow of the annual benefit (increase in the sales of electricity) in the t-th year of the project

- R f: Financial internal rate of return

Table 7-11 Results of Financial Evaluation

Case FIRR (%) NPV (US$1000)

Base Case 14.31% 45,359

As a result of calculation, the Financial Internal Rate of Return (FIRR) of this project was calculated at 14.31%.

The Financial Internal Rate of Return (FIRR) of this project, 14.31% is slightly higher than the market interest

rate of ordinary commercial banks in the Indonesian financial market (12.0%), allowing us to conclude that this

project is financially feasible.

Our view is that the FIRR stated above exceeding the market interest in Indonesian market in this simulation

does not necessarily guarantee that there are profitable environment for private entities. The reasons is that it is

very common not only in Indonesia but also in other nations that stable supply of electricity by the timely

construction, reconductoring and regular operation and maintenance of transmission lines and related facilities is

indispensable for securing the healthy lives of people and stable operation of the companies in the regions. Also,

considering the nature of the transmission line business, in general, huge initial cost in construction or

reconductoring together with collection of the investment on wheeling fees as revenue for long periods put the

7-15

entities involved at big potential business risk, such as political, environmental, and financial risk.

Furthermore, the Indonesian government recently proposed the new policies in driving the investment by private

sectors into power generation segment and alternatively in reallocating national resources such as PLN on

transmission and distribution business. As their standpoint, we strongly recommend that the Indonesian

government needs to take a strong initiative in investing in the transmission line business as the national project

with the government's fund from the view of securing the sustainability of the social infrastructure and the stable

supply of energy.

Table 7-12 Results of FIRR Calculation

Financial AnalysisFIRR= 14.31%

(Units : USD'000)

Capita l expenditure O&M Total (A) Wheel ing Energy (MWh)Wheel ing Income

(USD/MWh)Tota l (B)

2017 3,234 - 3,234 - - - (3,234) 2018 56,776 - 56,776 - - - (56,776) 2019 69,350 - 69,350 - - - (69,350)

1 2020 5,390 1,242 6,632 - - 22,106 15,474 2 2021 - 1,242 1,242 - - 22,106 20,864 3 2022 - 1,242 1,242 8,842,344 2.50 22,106 20,864 4 2023 - 1,242 1,242 8,842,344 2.50 22,106 20,864 5 2024 - 1,242 1,242 8,842,344 2.50 22,106 20,864 6 2025 - 1,242 1,242 8,842,344 2.50 22,106 20,864 7 2026 - 1,242 1,242 8,842,344 2.50 22,106 20,864 8 2027 - 1,242 1,242 8,842,344 2.50 22,106 20,864 9 2028 - 1,242 1,242 8,842,344 2.50 22,106 20,864

10 2029 - 1,242 1,242 8,842,344 2.50 22,106 20,864 11 2030 - 1,242 1,242 8,842,344 2.50 22,106 20,864 12 2031 - 1,242 1,242 8,842,344 2.50 22,106 20,864 13 2032 - 1,242 1,242 8,842,344 2.50 22,106 20,864 14 2033 - 1,242 1,242 8,842,344 2.50 22,106 20,864 15 2034 - 1,242 1,242 8,842,344 2.50 22,106 20,864 16 2035 - 1,242 1,242 8,842,344 2.50 22,106 20,864 17 2036 - 1,242 1,242 8,842,344 2.50 22,106 20,864 18 2037 - 1,242 1,242 8,842,344 2.50 22,106 20,864 19 2038 - 1,242 1,242 8,842,344 2.50 22,106 20,864 20 2039 - 1,242 1,242 8,842,344 2.50 22,106 20,864 21 2040 - 1,242 1,242 8,842,344 2.50 22,106 20,864 22 2041 - 1,242 1,242 8,842,344 2.50 22,106 20,864 23 2042 - 1,242 1,242 8,842,344 2.50 22,106 20,864 24 2043 - 1,242 1,242 8,842,344 2.50 22,106 20,864 25 2044 - 1,242 1,242 8,842,344 2.50 22,106 20,864 26 2045 - 1,242 1,242 8,842,344 2.50 22,106 20,864 27 2046 - 1,242 1,242 8,842,344 2.50 22,106 20,864 28 2047 - 1,242 1,242 8,842,344 2.50 22,106 20,864 29 2048 - 1,242 1,242 8,842,344 2.50 22,106 20,864 30 2049 - 1,242 1,242 8,842,344 2.50 22,106 20,864

Tota l : 172,010 663,176 491,166

Discount rate: 10%NPV ca lculations NPV of Cost: 125,888 NPV of Benefi t: 172,223

Benefi t and Cost Ratio (B/C): 1.368Benefi t and Cost Di fference (B-C): 46,335

Wheel ing Energy (MWh): 8,842,344 MWhWheel ing uni t price (US$/MWh): 2.50 US$/MWh

O&M costFor 500kV S/S: 340,000 US$/substation/yearFor 500kV T/L: 1,000 US$/km/yearT/L length: 220 km

Operating years

Cost RevenueNet Cashflow

(B) - (A)Year

7-16

7.3.6 Sensitivity Analysis from a Financial Standpoint

Fluctuations in prices of construction materials and machinery are expected to be involved in this project due to

the economic circumstances of Indonesia, and the financial benefit is also considered to be affected by such

instability. Considering this situation, sensitivity analysis was performed on total of 8 cases where the financial

benefit deceases by 5% or 10 % and where the financial cost increases by 5% or 10%, in addition to the base case.

The results of the sensitivity analysis are as follows.

Table 7-13Results of Sensitivity Analysis on FIRR

Cost

Benefit

Base Case -5% -10%

Base Case

+5%

+10%

14.31%

13.57%

12.90%

13.54%

12.83%

12.18%

12.75%

12.07%

11.44%

As shown in Table 7-13, FIRR values exceed the market interest rate of Indonesia if the prices fluctuate within

the range of around 5%, and it can be concluded that the project is feasible from a financial standpoint.

7.4 Conclusion of Financial and Economic Analysis

7.4.1 Economic Analysis

From the economic analysis, EIRR=12.58% and B/C=1.028 were obtained. It can be concluded that the project

is highly feasible from an economic standpoint.

7.4.2 Financial Analysis

From the financial analysis, FIRR=14.31% were obtained. This project is also considered feasible from a

financial standpoint.

7.4.3 Comparison between reconductoring and new transmission line

Between the proposed reconductoring and the alternative project for a new transmission line, the reconductoring

project is more attractive for various reasons. The proposed reconductoring project does not require land

acquisition or right-of-way access as existing transmission towers are used. This reduces the social and

environmental impact and allows the project to be completed in a shorter timeline (2020 compared to 2021 for

new construction).

Furthermore, reconductoring does not lead to an increase in O&M costs as the number of equipment and circuits

remain the same. For a new transmission line, additional O&M costs will be incurred due to an increase in the

number of circuits and more substation equipment is required. Compared between the two options, reconductoring

7-17

project enables the use of higher quality and more advanced conductor technology, utilizing XTACIR instead of

ACSR conductors. The proposed reconductoring project also requires lower capital investments of USD134.75mil

instead of USD148.06mil. Table 7-14 shows a summary of the comparison between the reconductoring and new

transmission line.

Table 7-14Summary of reconductoring and new transmission line

(Proposed) Reconductoring project (Alternative) New Transmission Line

Does not require land acquisition or

right-of-way

Does not lead to increase in O&M costs

Utilizes more advanced XTACIR

conductor technology

Lower total project costs

Land acquisition and right-of-way access

will be difficult, especially in densely

populated regions along the route

New transmission line requires higher

O&M costs

Conventional ACSR conductors can be

utilized

More expensive total project cost

8-1

Chapter8. Project Implementation Schedule

8.1 Entire Schedule

The implementation period in case this project is performed as a yen credit business, from the agreement

between governments of two countries to selection of international consultants and the preparation of EPC

(Engineering, Procurement, and Construction) will require 18 months. For re-conductoring work of Suralaya –

Gandul line and replacement of substation facilities, 18 months. Total implementation period is thus assumed to

be 36 months.

Figure 8-1 shows the project implementation schedule from the agreement of the government of two countries

to the completion of the project in the form of a bar chart. This implementation schedule will be revised as

necessary due to changes in related conditions.

8.2 The schedule to the EPC agreement

After loan agreement is reached between the two countries, the primary work to be completed before the EPC

full turnkey contracts are concluded and the expected time required are as follows.

Selection of Consultant and Conclusion of Consultant Contract 6 months

Preparation of EPC Tender Documents 6 months

Preparation of Bids 3.5 months

Evaluation of Bids, Selection of EPC Contactors, Conclusion of contracts 8 months

Total (including duplication) 18 months

8.3 Construction schedule

The implementation schedule for re-conductoring of transmission lines and replacement of substation facilities

are as follows.

Re-conductoring of Suralaya － Gandul line 17 months

Replacement of substation facilities 18 months

Total (including duplication) 18 months

8-2

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ths

0.5

mon

th

1 m

onth

1.5

mon

ths

3536

2930

3132

3334

2324

2526

2728

1718

1920

2122

1112

1314

1516

56

78

910

No.

Scop

e / E

vent

sD

urat

ion

2017

2018

2019

12

34

Figure 8-1 Project Implementation Schedule

9-1

Chapter9. Advantages of Japanese Enterprises in Technologies and

Financing Options for the Project

9.1 Comprehensive Advantage of Japanese Enterprises in Technologies

9.1.1 International Competition and Possibility to obtain this Contract by Japanese

Entities

Invar type of conductor, XTACIR/AC, was invented and developed in Japan, and three Japanese manufacturers

have produced the conductor. The extra thermal-resistant aluminum alloy wire (so-called “XTAL”) requires

manufacturing know-how, which cannot be easily imitated. At present, there seem to be no manufacturers of the

wire in countries other than Japan, and therefore the Japanese manufactures have high possibilities to win the

order.

As for the hardware to fix the up-rating conductor, there are several manufacturers in Asian countries who can

produce the suitable materials with a certain quality level. Those materials can be applied to XTACIR/AC, and the

Japanese manufacturers have no superiority.

The replacement works, Cradle Block Method, was developed in Japan, where the conductor erection works

have been frequently conducted in densely populated areas. Therefore Japanese contractors have extensive

experiences and international competitiveness in the method.

9.1.2 Possible Materials Supplied from Japan and their Relevant Cost

The up-rating conductor may be supplied from Japan, whose assumed cost for Suralaya - Gandul line is listed in

Table 9-1.

Table9-1 Possible materials supplied from Japan and the relevant cost

Material Quantity Assumed cost (Million USD)

XTACIR/AC

230mm2 2,800 km 60


9.1.3 Necessary Countermeasure to Promote securing of the Contract by Japanese

Entities

As aforementioned, there seem to be no manufacturers of the wire, XTAL, in countries other than Japan.

However manufacturers with little supply experiences may supply the low-quality conductors. Accordingly, from

the viewpoints of ensuring the quality, it is important to require all manufacturers to have their supply experiences

more than, for example, 15 years, and this condition will guide the secure promotion of the Japanese products.

9-2

9.2 Financing Options for the Project

9.2.1 Overview of Transmission Line Financing in other countries

In many developed economies with a well-established electricity market, the transmission network owner and

operator is separated from the electricity generation and retail business, such as in the United Kingdom, United

States and Australia31. The electricity transmission business remains financially sustainable through effective

regulation to provide a balance between incentivising new transmission network investments and ensuring

affordable transmission costs. In the UK, the transmission networks are regulated by Ofgem (Office of gas and

electricity markets) and in Australia, the Australian Energy Regulator (AER) determines cost recovery

mechanisms for operating and investing in the electricity transmission network32.

With certainty of returns, there can be more investment by the private sector. Therefore, it is common for

transmission network operators to raise financing on commercial terms and to include private sector involvement

in these markets. For example, in the UK, National Grid raises corporate bonds and bank loans to finance its

projects. In addition, on January 2016, the California Independent System Operator managed to successfully

tender out a transmission project to LS Power. LS Power will build, own and operate a 97km 500kV transmission

line in Nevada. LS Power will fund the USD133million project through a 50:50 debt-to-equity structure.

However, in many less developed economies within South-East Asia where transmission business is still

integrated within state-owned electricity utilities, there is still reliance on state funding and development

assistance. In 2014, state-owned Electricity Generating Authority of Thailand was dependent on government

funding of US$515million to fund new power plants and transmission lines. In 2013, National Power

Transmission Corporation of state-owned Électricité du Vietnam (EVN) received a concessional loan of €75

million from Agence Francaise Developpement (AFD) to fund the electricity transmission sector.

While private sector involvement is possible, the timeline for completion can be lengthy. For a transmission line

between Cambodia and Thailand, the project managed to be developed on a public-private partnership (PPP) basis.

Although the power purchase agreement (PPA) was signed in 2002, the concession agreement was only awarded

in 2005 and loan agreements for the transmission line were finally signed in 2008. So far, this has been the only

PPP project for transmission line in the region.

9.2.2 Overview of Financing in the Indonesian Power Sector

In the transmission sector, PLN raises financing for transmission lines through various means such as

government loans, domestically syndicated commercial loans and bond issues. In the 2010 FTP1 (Crash program

1) to build 10,000MW of power plants and related transmission lines, PLN obtained 85% of funding requirement

from bank loans fully guaranteed by the government and 15% from PLN internal funds. PLN managed to raise

bank loans of USD116million in foreign currency and USD4.8million in local currency to develop the electricity

transmission network in 2010. The foreign currency loans were raised from a consortium of local state banks

Bank Mandiri, Bank Rakyat Indonesia, Bank Negara Indonesia and private lender Bank Centra Asia, with a 100%

government guarantee. Besides bank loans, PLN funds transmission projects through state budget, internal funds,

31 For example, in the UK, National Grid owns and operates the electricity transmission network and does not generate or sell electricity.

32 See AER Final Decision on Trans Grid transmission determination for the 2015-2018 period.

9-3

foreign two-step loans, bank loans and corporate bond issues. Multilateral development banks are also heavily

involved in the transmission sector given the nature of transmission infrastructure as a public facility to ensure

stable power supply and a key infrastructure to supporting Indonesia’s electricity demand growth. Banks such as

World Bank and the Asian Development Bank have been actively investing in the transmission sector in the past

few years, providing both technical assistance and financing.

More recently, Germany’s development bank, Kreditanstalt für Wiederaufbau (KfW) has also committed to offer

loans of up to US$2.5 billion to Indonesia to develop renewable energy and transmission projects in Indonesia33.

As the 8th largest shareholder in the China-led Asian Infrastructure Investment Bank (AIIB) with an investment of

US$672.1 million, Indonesia is reported also to expect the AIIB to play a larger role in the power sector for both

power plants and transmission infrastructure whereas actual operation of AIIB needs to be monitored34. A list of

recent transmission projects funded by multilateral banks is shown in Table 9-2. In its 2014 annual report,

two-step loan comprised 28% of total outstanding long-term loans and bonds.

33 The Study Team interviewed the representative of KfW Jakarta on November 19th 2015. It also interviewed with the reprensetative of ADB Jakarta on November 12th 2015.

34 Finance Minister Bambang Brodjonegoro cited that the AIIB would need to shorten decision making process as long project approvals process for ADB (half a year) and World Bank (one year) has held up projects. South China Morning Post, 30 June 2015, Indonesia to push for AIIB to finance power projects

9-4

Table 9-2: Transmission projects by development banks

Year Project Name Agency Description Loan

Amount

(million

USD)

Interest

Rate

Repayment

Period

(year)

Grace

Period

(year)

2015 Electricity

Grid

Strengthening

Sumatra

Program

Asian

Development

Bank (ADB)

Improve

existing

transmission

and

distribution in

Sumatra

600 - - -

2013 220km

Java-Bali

Transmission

Line

Asian

Development

Bank (ADB)

Interconnection

between Java

and Bali

islands

224 LIBOR +

0.60%

20 5

2013 West

Kalimantan

Power Grid

Strengthening

Project

ADB Cross border

high voltage

transmission

line between

West

Kalimantan

and Sarawak

49.5 LIBOR +

0.60%

20 3

Agence

Française de

Développement

(AFD)

49.5 EURIBOR

+ 0.30%

15 5

2013 Indonesia

Second

Power

Transmission

Development

Project

World Bank Rehabilitation

and upgrade of

existing and

construction of

new

substations in

Indonesia

325 LIBOR

based

IBRD

Variable

Spread

Loan

21 7.5

2010 Indonesia

Power

Transmission

Development

Project

World Bank Expansion and

upgrade of

existing and

construction of

new

substations

225 LIBOR

based

IBRD

Variable

Spread

Loan

24.5 9

(Source: World Bank, ADB, IJGlobal)

http://www.afd.fr/lang/en/home




9-5

Figure 9-1 Share of PLN’s outstanding long-term loans and bonds

(Source: PLN Annual Report 2014)

As part of the Government’s effort to resolve key issues hampering the acceleration of infrastructure

development. Committee for the Acceleration of Priority Infrastructure Development (Komite Percepatan

Penyediaan Infrastruktur Prioritas / KPPIP) was established under Presidential Regulation Number 75 of 2014,

dated 17 July 2014, regarding the acceleration of priority infrastructure development. The KPPIP is led by the

coordinating economic minister and the members of the Committee are the Minister of Finance, the Minister for

National Development Planning / Head of National Development Planning Agency (Bappenas), and the Head of

the National Land Agency (BPN). KPPIP is mandated to create a pipeline of projects to be developed under the

PPP scheme to improve quality of project preparation, bankability, develop optimal funding structures and to

establish incentives and disincentives. In accordance with the Coordinating Ministry for Economic Affairs Law

No. 12/2015, regarding the list of Priority Infrastructure for 2015 – 2019, there are 30 priority infrastructure

development projects that fall under KPPIP’s jurisdiction including the 500kV Sumatra Transmission Grid project,

500kV Central-West Java Transmission Line and the HVDC project.

While significant developments have been made by Indonesia to develop infrastructure projects through private

sector participations, the progress of PPP projects in Indonesia’s power sector to-date has remained slow. For

example, the 2,000MW Central Java PPP project are still facing delays due to land acquisition. At the same time,

the Sumsel 9 and Sumsel 10 PPP coal-fired projects have been delayed multiple times. Since it was first

announced in 2013, the RFP deadline has been continually extended and as of 13 January 2016, the RFP deadline

has been postponed again.

More generally in power generation plant construction projects in Indonesia, the use of large scale commercial

project finance is common and there is a good track record of commercial lending supported by ECAs.

Traditionally, the Indonesian government has also provided guarantees to backstop PLN’s obligations to the

project in order to address PPA and meet lenders’ requirement for credit enhancement but this is changing as new

precedents develop. The 660MW Banten coal fired plant was the first power plant without a government

guarantee that successfully reached financial close in 2013. Moving forward, the Java-1 is tendered to select

developers and suppliers. For Java-7 power generation project, PLN has appointed Shenhua as preferred bidder in

28.2%

8.2%

63.6%

77.5%

Long-term loans and bonds

Two-step loans Government loans Bank loans Bonds

9-6

December 2015. These two projects also come without a government guarantee. Table 9-3 provides an overview

of recent power transactions in Indonesia.

Table 9-3: Recent power generation plants procured

Project Sarulla Geothermal Plant Banten Coal Fired Plant Sumsel 5 Coal Fired Plant

Capacity 330MW 660MW 600MW

Sponsors Itochu Corp, Medco Energy,

Kyushu Electric, Ormat

Technologies

Genting Berhad, Hero Inti

Pratama

Sinar Mas

Project Cost USD 1,540.5 million USD 998 million USD 480 million

D/E ratio 75:25 73:27 66:34

Debt USD 1,170 million USD 730 million USD 318 million

Tenor 20 years 12 years 10 years

Lenders ADB, JBIC

ING, BTMU, Mizuho,

SMBC, Societe Generale,

National Australia Bank

EXIM Bank of Malaysia

Citigroup, Maybank, CIMB,

RHB Bank

China Development Bank

Financial Close May 2014 July 2013 April 2012

Remarks JBIC political risk guarantee

for commercial loan

No government guarantees

(Source: IJGlobal, Bloomberg)

9-7

9.2.3 Overview of Financing at PLN

In the financing landscape in Indonesia, the current annual interest rate of IDR from an Indonesian commercial

bank for PLN is the three months weighted average time deposit35 + 3% per annum, based on PLN’s recent

corporate loans. For US dollar financing in recent years, the rate has been 5-7% based on PLN’s recent US dollar

bond issues in 2012 and 2009. Typical USD interest rates for project financed power projects would be around 3M

LIBOR + 4-5%.

As compared with these examples, the Japanese ODA Loan of the Government of Japan offered through the

JICA provides several advantages such as lower interest, up to 10-year grace period, and 30-year period of

redemption (for general terms loan). Because of this, there are favourable attitudes towards the use of the Japanese

ODA Loan. The current rates for variable rate 30-year loans is JPY LIBOR + 0.15%36, which is very attractive

compared to commercial loans as well.

Accordingly, the Government of Indonesia and PLN continue to take a positive approach toward the favorable

financing conditions (low interest and longer period of redemption) for a Japanese Yen ODA Loan from JICA. In

fact, PLN is already processing a loan arrangement with JICA (co-financed by KfW) for the Central and West

Java project through direct lending to PLN, according to a new presidential regulation. The Presidential Decree 82

of 2015 on Central Government Guarantee for Infrastructure Financing through Direct Loans issued on 15 July

2015 allows international development finance institutions to lend directly to state-owned enterprise without

going through state budget process and parliament approval. Central government provides guarantee to bilateral

and multilateral organisations. The direct lending will be applicable for projects that are approved by the

Committee of Acceleration of Procurement for Priority Infrastructure (KPPIP), approved by ministries or in line

with the Mid-Term National Development Plan37. The Government of Indonesia’s intention to release this

regulation was to shorten the time for state-owned institutions to receive financing from international financial

institutions for critical infrastructure projects.

9.2.4 Use of Japanese ODA Loan Requirements in the Proposed Project

There has been frequent exchange of visits by the Government leaders and policy meetings between Japan and

Indonesia. In a summit meeting held between Mr Shinzo Abe, Prime Minister of Japan and Mr Joko Widodo,

President of the Republic of Indonesia on 23 March 2015 in Japan, both leaders expressed strong commitment to

expand bilateral trade and investment cooperation. In the meeting, both leaders also concurred in launching

“PROMOSI: Japan-Indonesia Investment and Export Promotion Initiative”.

One component of the initiative is the promotion of a business and investment friendly environment in

Indonesia. This aims to enhance investment promotion measures, develop high quality infrastructure, and to

facilitate important projects such as mass rapid transit and electricity. In particular, the importance to enhance

cooperation in developing high quality infrastructure under the 35GW program was also confirmed. This initiative

was further affirmed during Prime Minister Abe’s visit to Indonesia on 22 April 2015.

The Japan government also announced the Partnership for Quality Infrastructure (PQI) in May 2015 to provide

35 As of December 15, this is 7.99% from Bank Indonesia 36 JICA lending rates effective from 1 April 2015 37 The Mid-Term National Development Plan (RPJMN) is a 5 year-plan issued by the Government of Indonesia to develop its society

and economy. The most recent issue is the RPJMN 2015-2019

9-8

USD 110billion of quality infrastructure in Asia over the next 5 years with the ADB. The PQI aims to promote

necessary infrastructure investment required in the region. Under the PQI, Japan will streamline the ODA loan

procedures from around 3 years to 1.5 years and also to allow ODA loans to be extended to sub-sovereign entities,

such as PLN. Together with the PQI, the Enevolution initiatve also helps to provide emerging economies with

know-how on energy related policy by deepening sector understanding through training programs and seminars to

develop institutional capacity.

The proposed project is concerned with the transmission line reinforcement project for the most important basic

transmission line from the Suralaya area as a source of supplying electric power to Jakarta, the capital and the

economic center of Indonesia. In view of the difficulties and cost efficiency in acquiring the land for the

construction of the power transmission line in practice, the importance of this re-conductoring project is

sufficiently understood on the part of the Indonesia. Furthermore, given that the transmission facilities from

Gandul and Suralaya are also in PLN’s plan (RUPTL 2015-2024) for transmission upgrade, there is considerable

interest by PLN to ensure that this project is developed in time to support the growth of new power plants in West

Java.

At present, there is no official request for the Japanese ODA Loan in this project. However, together with the

preceding Central West Java transmission line project, which PLN and JICA have been developing and appraising,

it is expected to put in the process as PLN is positively considering to take up this project which further

strengthens power transmission capacity. Application for Japanese ODA Loan will be filed according to the

subsequent process of the request for the Japanese ODA Loan by the Government of Indonesia.

9.2.5 Implementation Capability of Relevant Agencies of Indonesia

The implementation agency in Indonesia as project proponent and owner is PT. PLN. This company is 100 %

owned and managed as a wholly-owned subsidiary by the Ministry of State Owned Enterprises (BUMN).

PLN is regulated and managed by a complex system which is placed under the regulation and supervision of the

Ministry of Energy, Mineral and Resources (MEMR), and is subjected to the budgetary approval by the Ministry

of Finance. At the same time, MEMR is a coordinated ministry within the Coordinating Ministry for Maritime

Affairs. Coordination and formulation of national energy policies are conducted through the National Energy

Council (DEN), established in accordance with Presidential Decree No. 26 of 2008.38The organization of these

and related authorities are shown in Figure 9-2, Relevant Agencies of Indonesia.

38 Besides energy policies, DEN is entrusted with developing a National Energy Plan and to oversee implementation of policies in energy issues which cuts across different sectors. The DEN is chaired by the President and Vice-President and includes Ministers from other ministries.

9-9

Figure 9-2: Power Transmission Relevant Parties of Indonesia

(Source: The Study Team, PLN)

Ministry of Energy, Mineral and Resources (MEMR)

Ministry of State Owned Enterprise

(BUMN)

Ministry of Finance (MoF)

PT PLN

National Energy Coordinating

Agency (BAKOREN)

President Vice President Minister of Finance State Minister of

National Development Planning

Minister of Transportation

Minister of Industry Minister of Agriculture State Minister of

Research and Technology

State Minister of Environment

Regulation

National energy policy planning and coordination Regulation

Budget and financing

PT Indonesia Power (generation)

PT Pembangkitan Jawa Bali (PT PJB) (generation and O&M)

PT Pelayanan istrik Nasional Batam (PT PLN Batam) (special

regions)

Subsid of PLN on generation, transmission and distribution

IPP

Sale and Purchase of power

Coordinating Ministry for Maritime Affairs

Pusat Pengaturan dan Penyaluran Beban (P3B) (transmission and

distribution)

9-10

Under the leadership of Mr. Sofyan Basir, appointed as president director of this company since December 23,

2014, the following persons in Figure 9-3 are appointed as Directors to take charge of the following Divisions.

PLN’s organization structure has been changed on October 2015 with an additional of 3 Directors. Regional

Directors was added into the organization in order for faster decision-making and addressing challenges timely

unique to each regions. The organizational structure under PLN is shown in Figure 9-3 and 9-4.

Figure 9-3 Directors in PLN

S/

N

Title Name

1 President Director: Mr. Sofyan Basir

2 Director (Human Capital): Mr. Muhamad Ali

3 Director (Procurement): Mr. Supangkat Iwan Santoso

4 Director (Corporate Planning): Ms. Nicke Widyawati

5 Director (Finance): Mr. Sarwono Sudarto

6 Director (Regional Business – Sumatera): Mr. Amir Rosidin

7 Director (Regional Business – West Java & Lampung): Mr. Murtaqi Syamsuddin

8 Director (Regional Business – Central Java): Mr. Nasri Sebayang

9 Director (Regional Business – East Java & Bali): Mr. Amin Subekti

10 Director (Regional Business – Kalimantan)* Mr. Djoko Rahardjo

Ab 11 Director (Regional Business – Sulawesi & Nusa

Tenggara)*

Mr. Machnizon

12 Director (Regional Business – Maluku & Papua)* Mr. Haryanto W. S.

*effective as of October 2015

(Source: PLN Website)

9-11

Figure 9-4 Organisational structure of PLN and key divisions and persons in relation to the project39

9.2.6 Evaluation of Implementation Capability of the Relevant Agencies of Indonesia

In 2006, PLN was mandated to build 10,000MW of coal-fired plants in order to reduce reliance on fuel oil and

to meet rising domestic demand. Also known as the first Fast Track Program, PLN has since managed to complete

around 90% of the projects as of 2015. Furthermore, with the second Fast Track Program in 2009 to expand more

than 10,000MW of new power projects, PLN has gained experience in developing power projects and through

utilizing ODA loans.

With the 35GW Program, PLN will focus more on developing transmission networks while working on power

generation expansion. MEMR has shared that PLN developed projects could be reduced from 10GW to 5GW.

This allows greater IPP opportunities and at the same time focuses PLN’s capabilities in developing transmission

infrastructure. Table 9-4 shows the power transmission projects of Indonesia supported by the Government of

Japan since 1971.

39 This is an extract of transmission related departments relevant to this project and other departments are not shown

5. Finance Director

4. Corporate Planning Director

3. Procurement Director

2. Human Capital Director Regional Business

Directors

6. Sumatera

1. President Director

7. West Java

8. Central Java

9. East Java & Bali

10. Kalimantan

11. Sulawesi & Nusa Tenggara

12. Maluku & Papua

Power Systems Planning

(Mr M Ikbal Nur) Division

Transmission and

Dispatch Control (P3B)

P3B Jawa-Bali Grid

(Mr Evy Haryadi)

Foreign Loan and Grant

(Ms Ika Dewi)

9-12

Table 9-4 Power Transmission Projects of Indonesia supported by ODA from the Government of Japan N

o

Year Project Amount

(million JPY)

1 18/12/201

5 Java-Sumatra Interconnection Transmission Line Project (II) 62,914

2 30/4/2010 Java-Sumatra Interconnection Transmission Line Project (1) 36,994

3 31/3/2009 Engineering Services for Java - Sumatra Interconnection Transmission Line Project 3,886

4 29/3/2007 North-West Sumatra Inter-connector Transmission Line Construction Project 16,119

5 28/1/1998 Transmission Line Construction Project In Java-Bali (III) 10,918

6 4/12/1996 Transmission Line Construction Project In Java-Bali (II) 2,840

7 1/12/1995 Transmission Line Construction Project In Java-Bali 17,037

8 8/10/1992 Java-Bali Power Transmission Line And Substation Project (East Java) (II) 6,862

9 25/9/1991 Java-Bali Power Transmission Line And Substation Project (East Java) 7,671

10 15/2/1985 East Java Electric Power Transmission And Distribution Network Project (IV) 14,000

11 26/12/198

0 North Sumatra Transmission Line Project 5,800

12 4/10/1979 The Equipment Supply For Power Distribution Voltage Change Phase II 1,100

13 31/3/1978 The East Java Electric Power Transmission And Distribution Network Project 4,900

14 31/3/1978 The East Java Electric Power Transmission And Distribution Network Project 10,512

15 23/2/1978 The Equipment Supply For Distribution Network 2,240

16 27/12/197

7 The Equipment Supply For Power Distribution Voltage Change 1,680

17 14/7/1976 Consulting Services For East Java Electric Power Transmission And Distribution

Network Project 950

18 23/4/1975 Palembang Electric Power System Project 2,609

19 28/2/1975 East Java Electric Power Transmission And Distribution Network 456

20 28/2/1975 East Java Electric Power Transmission And Distribution Network 4,049

21 12/8/1974 Consulting Services For East Java Electric Power Transmission And Distribution

Network Project 288

22 21/11/197

2 Palembang Electric Power System Project 90

23 24/7/1972 East Java Transmission And Distribution Network Project 2,506

24 31/5/1972 Riam Kanan Distribution Network Project 424

25 15/4/1971 Engineering Services Of East Java Transmission And Distribution Network Project 407

(Source: JICA)

9-13

As shown in Table 9-4, PLN of Indonesia has utilized Japanese ODA Loan for approximately 217.252 million

Yen in 25 power transmission line projects during 44 years period (1971 – 2015). PLN has developed a deep

understanding of the projects using the Japanese ODA Loan of the power-related sectors of Indonesia, and to

exhibit an advanced level of capability in the implementation of the projects. Japan involvement to transmission

development also shown from technical assistance to PLN for various transmission projects such as the Java-Bali

and Java-Sumatra Transmission Projects. Gradually, PLN has shown capability improvement to execute the

transmission project based on successfully concluded transmission projects. During our interactions with PLN

during the feasibility study, PLN has shown considerable financial technical knowledge and familiarity with

Japanese development financing procedure and is expected to have good experience to develop the transmission

project, which can be seen from PLN 5 years achievement report that shown 5,185.73 kms additional transmission

has been constructed (from 35,146 kms in 2010 to 40,331.73 kms in 2014) and show significant improvement in

2015 with 3,941 kms of additional transmission line. Thus, PLN was able to demonstrate sound understanding of

financing considerations as well as technical expertise in transmission lines.

9.2.7 PLN’s Financial Conditions

PLN is a state-owned entity owned by the government of Indonesia (BB+ country credit rating by Standard and

Poors) and is operated on commercial principles. However, due to the nature of Government’s policy of keeping

electricity tariffs low (below the cost of production), PLN has received electricitysubsidy by the government in

order to support its financial liabilities and operating costs. Based on the approved budget performance list, PLN

was allowed a 7% margin above the cost of supplied electricity. In 2014, PLN received subsidies from the

government of Rp 99,303,250 million (34% of revenues) and in 2013 subsidies were Rp 101,207,859 million

(39% of revenues). PLN’s profit increased from a net loss of Rp 26,235615 million in 2013 to a net profit of Rp

11,741,610 million. Losses in 2013 were primarily due to realization of foreign exchange losses. Table 9-5 is the

statement of income for PLN in years 2014 and 2013.

9-14

Table 9-5 Statement of Income for PLN in 2014 and 2013

Units: million Rp

2014 2013

Revenue

Sale of electricity 186,634,484 153,485,606

Government's electricity subsidy 99,303,250 101,207,859

Customer connection fees 5,623,913 6,027,799

Others 1,159,544 1,125,778

Total Revenues 292,721,191 261,847,042

Total Operating Expenses 246,909,970 220,911,147

OPERATING INCOME 45,811,221 40,935,895

Gain (loss) on foreign exchange - net 1,319,299 (48,096,810)

Others income (charges) - net 4,157,018 1,792,124

Financial income 584,061

736,378

Financial cost (35,971,211) (30,146,545)

Tax Benefit (expense) (4,158,778) 8,543,343

INCOME (LOSS) FOR THE YEAR 11,741,610 (26,235,615)

(Source: PLN Annual Report 2014)

A stronger indicator of PLN’s financial condition will be its liquidity rather that profitability. From 2011 to 2014,

PLN’s current ratio, equal to current liabilities over current assets, has increased steadily from 0.96 to 1.02 as a

result of its increasing leverage ratio (debt to equity ratio). However, PLN has remained cashflow positive from

2011 to 2014, where its cash position has increased from Rp 22,088,093 million in 2011 to Rp 27,111,528 million

in 2014. This is due to stronger cashflow from operating activities and a decrease in investing activities.

Furthermore, PLN’s debt service coverage ratio (DSCR) has been at healthy levels of at least 1.25x.

Table 9-6 summaries the key financial metrics from 2011 to 2014.

9-15

Table 9-6: PLN’s key financial ratios

2014 2013 2012 2011

Current ratio (current assets/ current

liabilities) 1.02 1.05 0.98 0.96

Leverage ratio (Debt/equity) 2.67 2.93 2.17 1.89

DSCR (operating income/financial cost) 1.27 1.36 1.38 1.29 (Source: PLN Annual Report 2014, 2013, 2012, KPMG analysis)

Given that PLN has sufficient liquidity, healthy DSCR and net cash position, taking on a new loan is not

expected to have adverse impact on its financial position or its ability to finance the loan. Furthermore, further

subsidy reform in the Indonesian power sector is expected. In 2015, Indonesia removed electricity subsidies for

users with connections of 1,300VA and 2,200VA. The subsidy removal was further extended to smaller users with

connections of 450VA and 900VA on 1 Jan 2016. However, the government intends to provide direct subsidies to

the poorest of its population of about 24.7million subscribers. PLN expects to achieve cost savings of about IDR

20-30 trillion (USD1.5 billion) per year with this direct subsidy scheme.

At the same time, the government has approved, on 28 January 2016, capital injection of about IDR 10 trillion

to support PLN in achieving its 35GW program. With less dependence on government subsidies and capital

injection from the government, PLN’ financial sustainability is expected to improve in the long term.

9.2.8 Current Situation for the Japanese ODA Loan

As explained in this Chapter, under the new Presidential Decree 82 of 2015, State Owned Entities are now able

to enter into direct loans with foreign institutions, including multilateral development banks such as JICA, ADB

and World Bank. This will drastically reduce the funding approval process within the government as the funds will

not be approved at the national budget level. Instead, PLN will be the direct borrowing agency.

Under the direct lending scheme, the proposed projects need not be listed in the Blue Book (DRPPLN), which is

coordinated through BAPPENAS. With the new direct lending scheme, PLN proposes a project and recommends

to the Ministry of State Owned Enterprise (BUMN) and the Ministry of Finance (MoF) for financing using a

direct loan with an international financial institution. Only upon MoF’s in-principle approval, the loan negotiation

process begins. Thus, the implementation process for Japanese yen loan through direct lending can be shortened

compared to the previous process of utilising two-step loans. Figure 9-5 shows an outline of the agencies and

process involved in obtaining the Japanese ODA loan.

9-16

Figure 9-5 Process and agencies involved in obtaining Japanese ODA loan

Indonesian Agencies Japanese Agencies

PLN reviews project feasibility and

conducts further studies and approval

Exchange of Notes

Dispatch of JICA Fact Finding Mission

Submission of Japanese ODA loan request for the project to

Government of Indonesia for evaluation

Submit a request for Japanese ODA loan to the Government of

Japan through Japanese Embassy

Dispatch of JICA appraisal mission

Decision by Government of Japan on

ODA loan

Prior notification to Government of Indonesia

Negotiations and formal approvals

Ministry of Finance (MoF) Ministry of State-Owned Enterprises (BUMN)

9-17

9.2.9 Implementation Plan for Japanese ODA Loan

Since 1966, Japan has provided Indonesia with almost USD 3.9 billion in ODA loans. With the current on-going

Java-Sumatra HVDC transmission project, PLN is expected to have gained experience and knowledge in

transmission projects, from procurement to project execution. Furthermore, PLN has also been aided by other

development agencies such as Asian Development Bank (ADB) and World Bank for similar transmission projects.

At the same time, it is JICA’s goal to increase power generation capacity by 1,595MW and transmission line

(500kV & 275kV) by 1,540km in Indonesia by 2019.

This project has been proposed as a Japanese ODA Loan project for Indonesia. It is essential to get support from

PLN, as the project implementation agency, and support from MoF as the finance ministry of the Government of

Indonesia.

As of December 2015, PLN was processing a loan arrangement with JICA for the Central and West Java

transmission project. They have discussed the possibility of implementing an “Umbrella Agreement” to bundle

projects of similar nature together under a sector loan. This “Umbrella Agreement” could cover transmission

projects such as the Central and West Java transmission project and the re-conductoring of the Suralaya-Gandul

line. The loan agreement with Central and West Java transmission project with JICA is expected to be executed in

April 2016.

The following shows the major milestones during the period from completion of the feasibility study on this

project to the signing of the Japanese ODA Loan agreement and Exchange of Notes:

9-18

Table 9-7: schedule of Loan Agreement and Exchange Note

No. Activity Period

1 Completion of feasibility study Feb 2016

2 Distribution of feasibility study to related agencies and study of the report by

these agencies

Mar 2016

3 Study of the project by the PLN as a project implementation agency, preparation

of Project Implementation Plan, and authorization of the project, including further

environmental or technical review

Apr – Jun 2016

4 Recommendation by PLN to Ministry of Finance and Ministry of State Owned

Enterprise for Japanese ODA Loan loan for the project

Jun 2016

5 Study of project and Japanese ODA Loan Request by Government of Indonesia

and relevant agencies and dispatch of JICA fact-finding mission

Jul – Aug 2016

8 Submission of the request for Japanese ODA Loan by the

Government of Indonesia to the Government of Japan (through the

Indonesia-based Ambassador of Japan)

Sep 2016

9 Dispatch of JICA Appraisal Mission, and consultation with the related agencies of

Indonesia

Oct – Nov 2016

11 Final review, study, consultation and determination of the Japanese ODA Loan

project by the related agencies of Japan

Dec – Jan 2017

12 Declaration of intention to implement the Japanese ODA Loan proposal to

Government of Indonesia (prior notification) and procedure for consent to the

OECD Consensus

Feb 2017

13 Japanese ODA Loan procedure, Exchange of Note (E/N) and signing of the

Japanese ODA Loan Agreement (L/A) under the “Umbrella Agreement”

Mar 2017

Fin.

9-19

(Appendix) Workshop

1. Objective

Prior to finalize the report of our feasibility study, we held the workshop in Jakarta to have an opportunity to

share the overview of the study and also to exchange the views among the participants including the members of

Ministries and related entities of two nations, Indonesia and Japan, together with another Japanese study team

which mainly involved in proposing the effective approach for the reform of subsidy system and in introducing

the efficient power system development in Indonesian power sector.

2. Outline

The outline of the workshop is shown below.

Date：Wednesday 10th February , 2016

Venue：Gran Melia Hotel Jakarta

Participants： Shown below

Indonesia

Ministry of Finance (“MOF”)

Ministry of Energy and Mineral Resources (“MEMR”)

Coordinating Ministry for Economic Affairs

BAPPENAS

PLN

Japan

Ministry of Economy, Trade and Industry (“METI”)

JICA

Japanese private companies

Programme：Shown the figure below

Time Topic Presenter

9:00－9:10 Opening and welcome

remarks

METI and MEMR

Finance

9:10－9:40 Securing Financial robustness

for long-term Power

Development – International

cases on subsidies reform and

government support-

Ernst & Young Shinnihon

LLC (“E&Y”)

9:40－9:55 Finance Strategies for Power

Sector Development

MOF

9:55－10:10 PLN Strategies to Finance the PLN（Finance）

9-20

35GW Power Development

Program

10:10－10:30

Q&A/Discussion MOF, PLN(Finance), and

E&Y

Technical Solutions

10:30－10:50 Measures for Efficient Power

System Development

Tokyo Electric Power

Company Inc.(“TEPCO”)

10:50－11:10 Feasibility Study of

Transmission Lines Upgrading

in North West of Java Island,

Indonesia

KPMG, Tokyo Electric

Power Service Co.,

Ltd.(“TEPSCO”)

11:10－11:30 Panel discussion PLN, KPMG, TEPCO, and

TEPSCO 11:30－11:45 Q&A/Discussion

3. Result

(1) Comments from PLN for the study

According to the power system planning division of PLN, PLN prefers constructing new transmission lines over

the reconductoring as an augmentation of capacity of transmission lines from Suralaya (Lama) power plant to

Gandul substation. On the other side, PLN understands that new construction would be difficult particularly in

densely populated areas in the region, for example around Jakarta, since it is easily expected to cost amount of

time and investment for the procedure of land acquisition etc.

(2) Q&A

There was one question to PLN from a participant in relation to (1) above. The participant was wondering why

PLN prioritized construction of new transmission lines although the presentation of the study team addressed that

reconductoring is more profitable project than new construction. PLN commented that reconductoring is a better

approach in a short and mid-term period (e.g. 10 years) but constructing new lines is more beneficial in a longer

period (e.g. 50 years) with the insight of Indonesian’s future economic growth.

And there was one question to the study team from a participant. The participant asked what happens in power

flows of this transmission lines in this region once power interruption is expected to occur before the start of

operation during the period when reconductoring work is being performed. The study team commented that they

could not answer the question based on the evidence as they did not perform the system analysis for the period of

reconductoring work, and they viewed that the power flow is possibly going to reduce suppressing power of

electricity generated from new power plants in West Java area RUPTL 2015 mentioned to be started their

operations from 2019 to 2020.

In consequence, the study team believe that the workshop was a great opportunity for the participants to

understand at certain level why the project is feasible.

Fin.

9-21

（Format2） A list of non-approved secondary use

Title of Report: Feasibility Study of power supply upgrading in North West of Java Island

Title of project: Study on Economic Partnership Projects in Developing Countries in FY2015

Prepared by KPMG AZSA LLC Tokyo Electric Power Services Co., Ltd.

Page No. title

4-1 Table 4-1 Generation expansion plan which affect the loading condition of the transmission line between Suralaya(Lama) power plant and Gandul substation

4-2 Figure 4-1 Generation expansion plan in the north western region of Jawa-Bali grid 4-3 Table 4-2 Transmission line projects in the Special Capital Region of Jakarta 4-3 Table 4-3 Transmission line projects in Banten province 4-4 Figure 4-2 Latest generation expansion and transmission augmentation plans during 2016-2018 4-5 Figure 4-3 Latest generation expansion and transmission augmentation plans in 2019 4-6 Figure 4-4 Latest generation expansion and transmission augmentation plans in 2020 4-9 Table 4-4 Supply–demand balance in Jawa-Bali power system for system analyses 4-10 Figure 4-7 Result of power flow analysis under N-0 condition 4-11 Table 4-5 Results of N-1 contingency analyses

4-12 Table 4-6 Results of N-1 contingency analyses with grid splitting between Kembangan and Gandul

4-12 Figure 4-8 Result of power flow analysis under the one circuit outage of Lengkong – Gandul section

4-14 Figure 4-9 Result of the fault current analysis in 2020 4-15 Figure 4-10 Result of the fault current analysis in 2016 4-16 Table 4-7 Substations and Power plants where the fault current exceeds 50 kA 4-21 Figure 4-15 Image of bus split at Gandul substation 4-22 Figure 4-16 Image of bus fault current flow under bus split configuration at Gandul substation

4-23 Figure 4-17 Grid configuration change from the loop to the radial by opening Kembangan-Gandul transmission line

4-24 Figure 4-18 Busbar split operation at Balaraja substation 4-29 Figure 4-21 Fault locations for stability analyses 4-30 Table 4-10 Results of system analyses 4-31 Figure 4-22 Suralaya(Lama)-Balaraja transmission line #1 trip after a fault at Suralaya end 4-31 Figure 4-23 Suralaya(Lama)-Cilegon transmission line #1 trip after a fault at Suralaya end 4-32 Figure 4-24 Cilegon-BogorX transmission line #1 trip after a fault at Cilegon end

4-32 Figure 4-25 Suralaya (Lama)-Suralaya Baru transmission line #1 trip after a fault at Suralaya (Lama)

4-33 Figure 4-26 Suralaya Baru-Banten transmission line #1 trip after a fault at Suralaya Baru end 4-33 Figure 4-27 Banten-Bojonegara transmission line #1 trip after a fault at Banten end 4-34 Figure 4-28 Bojonegara-Balaraja transmission line #1 trip after a fault at Bojonegara end 4-34 Figure 4-29 Tanara-Balaraja transmission line #1 trip after a fault at Tanara end 5-26 Table 5-15 Existing Facilities at Gandul SS 5-27 Figure 5-15 Single Line Diagram (Gandul S/S) 5-29 Table 5-16 Existing Facilities at Balaraja SS 5-30 Figure 5-17 Single Line Diagram (Balaraja S/S) 5-32 Table 5-17 Existing Facilities at Suralaya SS 5-33 Figure 5-19 Single Line Diagram (Suralaya S/S) 5-34 Table 5-18 Rating of Existing and Newly Installed Circuit Breakers 5-35 Table 5-19 Quantities of Substation Equipment to be Replaced and Rated Currents