The document discusses Indonesia's natural gas market and LNG trade. It notes that while Indonesia has long exported LNG, domestic gas demand is rising significantly as oil-fired power plants are converted to run on gas. This is creating gas supply shortages within Indonesia. The government is working to address this issue through various strategies like developing new gas infrastructure including pipelines, LNG import terminals, and regulating domestic gas allocation. Japanese companies have traditionally played a major role in Indonesia's LNG industry through investment, technology, and offtake agreements. However, as domestic gas needs grow, Indonesia's gas market is undergoing a transition from primarily export-focused to aiming to also meet strong rising domestic demand.

1. Gas Trading Business
Supply solution for Indonesia Gas
Domestic Market
Natural gas is the most
competitive and friendly
energy. So if you can bring
gas with favorable terms, no
one will refuse it.
Hi domestic demand, plenty
of gas supply – no
coordination and
management to keep the flow
from source to users.

2. Cost Comparison – Various Energy Power Plant
True!

3. LNG Supply Chain
LNG projects are developed as an integrated chain of dedicated facilities and
activities involving (i) natural gas production and liquefaction in the exporting
country, (ii) marine transportation of LNG on LNG vessels, and (iii) regasification of
LNG and distribution and consumption of regasified LNG in the importing country.
The LNG supply chain must be integrated economically through the addition of
value at each component of the chain. An LNG export project will only be
developed where there is a secure long term commitment to purchase the LNG,
since the proceeds of the sale of LNG flow back up the supply chain to pay for the
costs of production, liquefaction, shipping and regasification, and to give
investors a return on their investment.

4. Pattern of LNG Transaction in 70s
On 6 March, 1967, the first Asian LNG sale and purchase agreement (LNG SPA) was signed for the sale of LNG
produced by Phillips and Marathon Oil in Alaska to Tokyo Electric (75%) and Tokyo Gas (25%). The first delivery
of Alaskan LNG to Tokyo Electric and Tokyo Gas occurred in November 1969. Although the sale price was set at
$0.52 per MMBtu until 1984, the following additional price review clause was agreed:
"If in the future another Liquefied Natural Gas project is placed into operation to supply Japan with natural gas
from foreign gas sources, such as Alaska, Canada, Australia, Brunei and the Middle East under similar
conditions such as volume, distance, liquefaction and ocean transportation techniques, contract term and so
forth, Sellers will hold a discussion with Buyers concerning the price as herein set forth, and shall endeavor to
find a solution satisfactory to all parties concerned."
In 1970, Tokyo Electric, Tokyo Gas and Osaka Gas signed LNG SPAs with Shell, Mitsubishi and the Brunei
government to underpin the development of the Brunei LNG project, the first LNG project in which Japanese
companies participated in both export (Mitsubishi has a 45% interest) and import. Again, negotiation leverage
on the side of the buyers resulted in the LNG SPA being governed by Japanese law, with arbitration under ICC
arbitration rules to be held in either Tokyo or Osaka. The project's first cargo was delivered on time to Osaka
Gas in December 1972.
In December 1973 Indonesia's Pertamina signed an LNG SPA for 8.18 MTPA with Chubu Electric, Kansai
Electric, Osaka Gas, Kyushu Electric and Nippon Steel. The ex-ship sales price was divided into an "LNG
Element" based on crude oil export prices and a "Transportation Element," with the LNG Element being a
minimum LNG price of $0.99 per MMBtu, escalating at an agreed rate, and the Transportation Element being
$0.30 per MMBtu, escalating based on changes in seller's actual cost of transportation payable to its
transporter. The first Indonesian cargo was delivered from the Bontang plant to Osaka on 19 August, 1977.

5. Pattern of LNG Transaction in 80s & 90s
In the early 1980s, Japanese buyers supported the development of the MLNG Satu export project, Malaysia's
first LNG export project. JEXIM provided loans to Petronas and Mitsubishi, who were two of the project's four
sponsors.
In May 1985, five Japanese power companies and three Japanese gas companies signed LNG SPAs for the
Northwest Shelf project, the first Western Australia export project. Japan Australia LNG (MIMI) Pty Ltd, a
joint venture between Mitsubishi and Mitsui, was one of the six project sponsors. The project's first shipment
to Japan occurred in July of 1989.
Qatargas was able, with the assistance of Mitsui, to secure an LNG SPA with Chubu Electric in May 1992
(governed by New York law and providing for arbitration under ICC arbitration rules in Geneva). Japanese
financing supported the LNG plant; Japanese lender JEXIM supplied $1.6 billion via an intermediate financing
company that was guaranteed by the two Japanese sponsors.
since the borrower from JEXIM was a Japanese company, the funds were simultaneously lent on by the
borrower to Qatargas.(back to back - project financing). Although front-end engineering work had been
completed in Houston by US construction contractor, MW Kellogg, the final EPC was awarded in May 1993 to
Japanese contractor Chiyoda. During the 1980s and early 1990s, Japan also dominated the LNG vessel
building business. Between 1993 and 1994 Japanese companies constructed 10 of the 13 LNG vessels built
during this period. Japan has since been overtaken by both Korean and Chinese ship yards. Some Japanese
LNG buyers have acquired substantial LNG vessel fleets for their FOB LNG sales into Japan.

6. Pattern of LNG Transaction in 2000s to Present
A number of Japanese companies are involved in the Sakhalin 2 LNG project, which was developed from the
mid-2000s. Nine of the 12 LNG buyers from Sakhalin 2 are Japanese. Chiyoda Corporation and Toyo
Engineering Corporation were involved in the construction of the plant. Mitsui Sakhalin Holdings B.V. (a
subsidiary of Mitsui) and Diamond Gas Sakhalin (a subsidiary of Mitsubishi) have a 12.5% and 10% interest,
respectively, in the project company, Sakhalin Energy Invest Company.
In June 2008, Sakhalin Energy signed Russia's largest project finance deal, securing a loan of $5.3 billion from
the Japan Bank for International Cooperation (JBIC) and a consortium of international banks. JBIC provided
$3.7 billion of the funds. The first cargo of LNG was delivered from Sakhalin in March 2009.
Since September 2013, all of Japan's 48 viable nuclear reactors have been offline.
Japan is looking to exports from the US in the hope of securing long term LNG supply at lower prices. One of
the most significant factors driving Asian (including Japanese) demand for US LNG is price. Historically the price
of LNG under Japanese LNG SPAs has been linked to the price of crude oil using the Japan Crude Cocktail (JCC)
index. In contrast, in the US, LNG is priced according to the Henry Hub price index, which is determined by
supply and demand for natural gas in the US. The price differential between JCC and Henry Hub is significant,
although the export price increment is, in part, a product of the associated liquefaction, processing and
pipeline transportation costs. Some commentators believe that even if the price of US LNG is linked to Henry
Hub by the time high liquefaction and transportation costs are added the delivered price will be close to the
conventional JCC delivered price of LNG.
under construction a reality, particularly the new Australian projects. For example, on the West Coast of
Australia Inpex is leading the Ichthys LNG project, which has entered the construction phase. The Australian
subsidiaries of Tokyo Gas, Osaka Gas, Chubu Electric Power and Toho Gas are also project sponsors. Inpex's
wholly owned subsidiary, INPEX Shipping Co, will own one LNG vessel via a joint venture with Kawasaki Kisen
Kaisha, Ltd. JBIC is providing a loan of up to $5 billion to support the Ichthys project.

7. Japan involvement in LNG Project/Infrastructure
On the LNG export project development side, an increasing number of Japanese companies are taking an
equity stake in LNG projects. Today the following Japanese companies own interests in existing LNG export
projects:
Inpex: Australia Darwin (11%), Indonesia Tangguh (7.8%);
Itochu: Oman Train 1 (0.9%) and Train 2 (3%), Qatar Ras Laffan (R) 1: T1 & T2 (4%);
JX Nippon: Indonesia Tangguh (13.5%);
Kansai Electric: Australia Pluto (5%);
LNG Japan: Qatar Ras Laffan (R) 1: T1 & T2 (3%), Indonesia Tangguh (7.4%);
Marubeni: Equatorial Guinea (6.5%), Qatar Ras Laffan (Q) 1: T1 & T2 (7.5%) T3 (7.5%), Peru (10%);
Mitsubishi: Oman Train 1 (2.8%) and Train 2 (3%), Australia Withnell Bay Trains 1-4 (8%) and Train 5 (8%),
Brunei (25%), Indonesia Tangguh (9.9%), Indonesia Bintulu 1 (5%), 2 (15%) and 3 (5%), Sakhalin 2 (10%);
Mitsui: Equatorial Guinea (8.5%), Abu Dhabi (15%), Oman Train 1 (2.8%), Qatar Ras Laffan (Q) 1: T1 & T2 (7.5%)
T3 (7.5%), Ras Laffan (Q) 3: Train 1 (1.5%), Australia Withnell Bay Trains 1-4 (8%) and Train 5 (8%), Indonesia
Tangguh (2.3%), Sakhalin 2 (12.5%);
Osaka Gas: Oman (3%);
Tokyo Electric Power: Australia Darwin (6%); and
Tokyo Gas: Australia Darwin (3%), Australia Pluto (3%).
High influence of Japanese Tradition in LNG business.
From buyer, lender, project infrastructure and operatorship.

8. Long-term vs Short-term LNG Trade
More room for short term trade in the market

9. Baseline
• Indonesia has been gas exporter country since 40 years ago, where Japan as gas
user bring all the required technology infrastructure, vessels/transport, funding, to
the gas export site and keep the cargo flows to Japan for long term supply. It fuels-
up the gas production field, LNG Plant, storage and terminals, LNG carrier, etc.
Mitsui and Mitsubishi Tradition. All of this investment is covered by GSPA, FEED,
Bank facilities, and credit worthiness.
• In the last couple of years, Indonesia demand for gas has been increasing-and
continue to grow in the coming years. The emerging Indonesia gas domestic
market needs the same facilities to supply gas users such as gas fired power plant,
smelter, city gas, etc. Nevertheless, there are some anomalies in the market,
where need to be addressed with strong market structure.
• The growth of domestic gas demand in Indonesia, needs heavy capital expense
and make plenty room for gas trader and EPC to establish continue gas supply for
power plant, city gas, smelter, industries, etc.

10. Mission Statement for Domestic Gas Trade
• Gas trading means deliver the gas to customer premises. Therefore trader needs to
identify nearest gas source to customer premises, fill in the gap, bring the best
solution, continue supply in timely manner.
• The strongest engineering concept, will come up with best solution and reliable
numbers.
• Need funds to cover capital expenditure of the facilities, need EPC to bring all the
infrastructure on time, need operator to maintain the gas flow.
• Trading Company is the coordinator to wrap up the terms and conditions relation
among the parties in contract package.

11. Scope of Mission
Gas User Gas Trader
Banks
EPCOperators
GSPA
Contract Package
Existing Entities New Entities
Gas Producers LNG Plant
Pipe, Storage & Regasification
Asset Growth
Prima Causa

12. Gas Transport
Basically there are only 2 options in terms of gas supply for domestic demand on gas,
gas supply through gas pipe and LNG. Users connected to gas pipe can tap the gas in
their flanges, where users who are not connected-then they only chance is through
LNG. LNG is not a perfect solution for short to mid distance cargo supply. Moreover,
LNG technology requires liquefaction process and re-gasification process in two ends,
which cost the whole process.
In fact, PT. PLN is now running operation test for CNG solution, which is going to be
the first commercial operation in the world. CNG is suitable solution to carry natural
gas for small to medium cargo with distance up to 2,000 Nautical miles.

13. High Gas for Domestic Market

14. Indonesia Gas Plan
• Based on Ministerial Energy and Mineral decree No. 21 year 2013- acceleration of
development of power plant and transmission project with target of additional 35,000 MW in
the year 2019. Every year shall deliver 7,000 MW, with distribution as follows Zona Jawa Bali
20.91 GW, Sumatera 8.75 GW, Sulawesi 2.70 GW, Kalimantan 1.87 GW, Nusa Tenggara 0.70
GW, Maluku 0.28 GW dan Papua 0.34 GW.
• Currently, 52% of energy resources are supplied by fuel, 28% natural gas, 15% coal, 3% hydro
stream and 2% geothermal. Due to depletion of oil reserve, automatically natural gas
becomes the most suitable alternative. Based on Road Map released by Ministerial Energy
and Mineral, domestic consumption of natural gas and coal will be increased to replace fuel
oil upto 53%, where fuel will be reduced to 20%.
• In general, utilization of the gas is as follows:
– 1. Gas for Energy/Power Plant.
– 2. LNG for export
– 3. Gas for raw material of petrochemical industries (including fertilizer, methanol, plastic, etc)

15. Followed Up
• Indonesia is planning to allocate a minimum 46 million mt of LNG over 2013-2025
to its planned floating storage and regasification units, which is expected to curb
the country's LNG exports. (approximately 25-30 cargoes per annum).
• The government has allocated 27 LNG cargoes/year to Pertamina and PGN's West
Java FSRU over 2013-2025 -- the country's first which came online in 2012 -- while
Pertamina's Arun LNG plant which is being converted into a 400,000 Mcf/d gas
receiving and regasification terminal has been allocated eight LNG cargoes in 2015
and 16 cargoes/year over 2016-2025.
• Pertamina's planned FSRU in central Java will receive eight LNG cargoes in 2015, 16
cargoes/year over 2016-2018, 22 cargoes over 2019-2022, 16 cargoes in 2023 and
eight cargoes over 2024-2025. Meanwhile, PGN's 3 million mt/year FSRU project in
Lampung will receive 10 cargoes/year over 2015-2025.

16. National Gas Issues
• Head of Performance Monitoring Unit, Ministry of Energy and Minerals ,Widyawan Prawiraatmaja , stated
that in addition to the industry utilization, electricity will need gas in massive quantity, since 11,000-
12,000 MW of the additional 35,000 MW –using gas as source of energy. In the year 2014, national gas
supply allocation is 2,064 mmscfd where the demand reaches 2,871 mmscfd,. This deficit of 807 mmscfd ,
will be supplied by imported gas. (gas importer since 2014?)
• Vice President Jusuf Kalla, stated that to accelerate the supply of energy, the government is planning to
deliver receiving gas terminal in several location in Indonesia-where it is expected that the utilization of
gas can replace fuel oil.
• Domestic gas demand will increase about 3,9% up to 7,2 bcfd in 2025 that is primarily resulting from the
need for gas-fire power plant and industrial sector in Java and Sumatera. For this, Pertamina will have to
start redefining its gas business orientation (LNG) to fulfill domestic gas demand while maintaining export
volume contract.
• PT Pertamina (Persero) and Cheniere Energy, Inc, signed a LNG Sales and Purchase Agreement (LNG SPA)
on December 4 2013 for LNG supply of about 0,8 million tons per year for a term of 20 years. The supply
will start in 2018 from LNG plant currently developed near Corpus Christi, Texas, USA. In July 2014,
Pertamina has agreed to purchase 0.76 million tonnes of the super-cooled gas per year for 20 years,
beginning in 2019.Indonesia faces a decline in LNG production while domestic demand for gas in the
country is rising steadily by at least 10 percent annually.
• In October 2014, Perusahaan Listrik Negara (PLN) of Indonesia signed a 19-year deal with BP to buy LNG
from the Tangguh plant in West Papua. The BP Tangguh-PLN deal will supply Indonesia with an estimated
400 cargoes of LNG over the contract duration.

17. Gas Supply
and Logistic
Gas “Converted”
Power Plant
PLTG
PLTGU
PLTD
PLN
Indonesia Power
IPP
New Infrastructure
Smelter ANTAM
Others
Industrial Zone
Near Port (KEK)
Sei Mangkei,T Lesung
Kuala Tanjung, etc
Current Gas Market
All oil based Power Plant will be converted and fully
using gas in 2016.
Gas Power Plant PLN
Indonesia Power
IPP
Gas Target Production in 2014 is 7900 MMSCFD, where
4000 MMSCFD is allocated for export and the rest 3900
MMSCFD is dedicated for domestic market, 60% for
electricity, 20% for fertilizer and 20% for industry (PT.
PGN and PT. Pertagas).
11,000-12,000 MW to
2018 – 2350 MMSCFD
2,064MMSCFD 2014
640 MMSCFD
2 thousand allocated national gas supply and 4 thousand gas demand

18. Gas for Smelter
• In the next 5 years, there are at least 30 investors who interested to develop smelters with
total investment of US$ 55 billion.
• In 2014, there are 17 investors committed to develop smelters, although not all of them are
going to use gas for the energy, such as investor in Morowali is more interested using coal.
• In 2015 there are 16 iron and nickel smelters. Each smelter requires 30-40 MMSCFD to
produce electricity 250 MW. With 250 MW of electricity, the smelter can produce 300,000 –
500,000 tons ferronickel.http://www.kemenperin.go.id/artikel/9425/Tiap-smelter-konsumsi-
gas-30-40-MMSCFD
• Coordinating Minister for Maritime, Indroyono Soesilo, stated at his office in March 2015,
that there 7 new smelters in operation this year, i.e. 1 alumunium smelter and 6 nickel
smelters. http://ekonomi.metrotvnews.com/read/2015/03/18/373323/pemerintah-siapkan-
7-smelter-baru-tahun-ini
• Gas demand for 4 smelters in 2030 is 2,525.40 MMSCFD, i.e., PT. ANTAM 1625 MMSCFD, PT.
Ang & Fang 41.64 MMSCFD, PT. Smelter Gresik 202.98 MMSCFD, and PT. Macika Mineral
Industri 655.76 MMSCFD. http://www.kemenperin.go.id/artikel/9425/Tiap-smelter-
konsumsi-gas-30-40-MMSCFD

19. Case of PT. Aneka Tambang
• Antam plans to expand its FerroNickel smelter capacity in Buli, East Halmahera.
• 8 units PLTD @ 17 MW, dual fuel.
• Based on the above plan, since 2016 PT. Antam will receive 75 MMSCFD in Buli-
East Halmahera and 25 MMSCFD in Pomalaa, South East Sulawesi from LNG Plant
in Tangguh and Bontang.
 Proyek Chemical Grade Alumina (CGA) Tayan:
Lokasi: Tayan, Kalimantan Barat.
Perkiraan biaya proyek sebesar US$490 juta dengan rencana kapasitas produksi 300.000
ton Chemical Grade Alumina per tahun.
Konsorsium unincorporated PT Wijaya Karya (Persero) Tbk, Tsukishima Kikai Co. Ltd.
dan PT Nusantara Energi Abadi (Nusea) terpilih sebagai kontraktor EPC.
Dukungan pendanaan oleh JBIC dan konsorsium perbankan Jepang.
Status saat ini: Konstruksi.
Estimasi commissioning pada bulan Oktober 2013.
 Proyek FeNi Halmahera Timur:
Lokasi: Buli, Halmahera Timur, Maluku Utara.
Perkiraan biaya proyek sebesar US$1,6 miliar (termasuk pembangkit listrik) dengan
kapasitas produksi 27.000 ton Ni per tahun.
Status saat ini: Konstruksi.
Estimasi commissioning pada tahun 2015.
 Proyek Perluasan Pabrik Feronikel Pomalaa (P3FP):
Lokasi: Pomalaa, Sulawesi Tenggara
Bertujuan untuk meningkatkan efisiensi pabrik feronikel Pomalaa, termasuk
pembangunan PLTU berkekuatan 2x30MW
Estimasi nilai proyek antara US$450-500 juta
Status saat ini: Konstruksi
Estimasi penyelesaian di tahun 2014.
 Proyek Smelter Grade Alumina (SGA) Mempawah:
Lokasi: Kalimantan Barat.
Perkiraan biaya proyek masih dalam kajian dengan kapasitas produksi 1,2 juta metric ton
SGA per tahun.
 Proyek Chemical Grade Alumina (CGA) Tayan:
Lokasi: Tayan, Kalimantan Barat.
Perkiraan biaya proyek sebesar US$490 juta dengan rencana kapasitas produksi 300.000
ton Chemical Grade Alumina per tahun.
Konsorsium unincorporated PT Wijaya Karya (Persero) Tbk, Tsukishima Kikai Co. Ltd.
dan PT Nusantara Energi Abadi (Nusea) terpilih sebagai kontraktor EPC.
Dukungan pendanaan oleh JBIC dan konsorsium perbankan Jepang.
Status saat ini: Konstruksi.
Estimasi commissioning pada bulan Oktober 2013.
 Proyek FeNi Halmahera Timur:
Lokasi: Buli, Halmahera Timur, Maluku Utara.
Perkiraan biaya proyek sebesar US$1,6 miliar (termasuk pembangkit listrik) dengan
kapasitas produksi 27.000 ton Ni per tahun.
Status saat ini: Konstruksi.
Estimasi commissioning pada tahun 2015.
 Proyek Perluasan Pabrik Feronikel Pomalaa (P3FP):
Lokasi: Pomalaa, Sulawesi Tenggara
Bertujuan untuk meningkatkan efisiensi pabrik feronikel Pomalaa, termasuk
pembangunan PLTU berkekuatan 2x30MW
Estimasi nilai proyek antara US$450-500 juta
Status saat ini: Konstruksi
Estimasi penyelesaian di tahun 2014.
 Proyek Smelter Grade Alumina (SGA) Mempawah:
Lokasi: Kalimantan Barat.
Perkiraan biaya proyek masih dalam kajian dengan kapasitas produksi 1,2 juta metric ton
SGA per tahun.
Status saat ini: Kajian internal terhadap hasil studi kelayakan.
Estimasi commissioning pada tahun 2017.
 Mandiodo Nickel Pig Iron (NPI) Project:
Lokasi: Konawe Utara, Sulawesi Tenggara.
Perkiraan biaya proyek masih dalam kajian dengan kapasitas produksi 24.000 TNi per
tahun.
Status saat ini: Kajian internal terhadap hasil studi kelayakan.
Estimasi commissioning pada tahun 2018.

20. Gas for Electricity
• There are new 32 new Gas Power Plants, with total capacity of 2,531 MW, 10 units (450 MW)
in Nusa Tenggara, 14 units (1520 MW) in Sulawesi, and 8 units (561 MW) in Kalimantan.
Those plants need 230 MMSCFD and will be in operation in 2018.
• PLN invites LNG traders to submit proposal of LNG supply for Power Plant using gas turbine
or diesel engine (dual fuel/conversion), located in Nusa Ten.ggara, Kalimantan and Sulawesi
for total capacity of 2800 MW.
• Based on Power Plant Development Plan (RUPTL 2015-2024), the additional 35000 MW
power plant will consist of 20,000 coal fired power plant, 13,000 MW gas power plant
(approximately requires 2,350 MMSCFD) and the rest using other energy including plants
using renewable energy solution.
• Currently, existing power plants need 1.250 BPTUD, where 25% derived from LNG. The use
of LNG in 2019 will be 60%, where the rest will be using natural gas from pipe. It indicates
that PLN policy for non pipe connected power plant merely have one solution for gas supply,
i.e. LNG.

21. Updates on Gas Supply
The Indonesian government stated that PT.PLN can save Rp. 5 trillion this year (2015), since Sumatera Utara
Power Plant can generate gas supply from Arun re-gasification facility in Nanggroe Aceh Darussalam. By having
the facility in operation, LNG bought from Tangguh Papua can be used to replace fuel for Belawan Power Plant.
In addition, PLN is going to utilize the gas to generate electricity for new power plant located near Arun Belawan
pipe. Since gas is more competitive than fuel cost, the operation of power plant become more efficient.
PT. PLN gets gas supply from PC Madura/Santos Madura Offshore Pty.Ltd of 25 BBTUD or 35 TBTU for 4 years to
generate power plant in Gresik. Price of gas from Peluang Field is US$ 6.49 per MMBTU. The gas is supplied
through Pertagas pipe to PLN Power Plant in Gresik, starting April 2014.
PT. Medco E&P Malaka enter the year 2015 by signing 198 TBTU Gas Sales Agreement with PT. Pertamina for gas
supply from A Block, Aceh . PT. Medco is expecting another contract signing with PT. PLN for 5-15 BBTUD gas
supply. The gas is going to supply fertilizer and local industry. Gas supply will commence in 2017 for 13 years,
with total supply of 198 TBTU or 58 BBTU per day. Gas price is US$ 9.45 per MMBTU at the tie-in point of Arun
Belawan Gas Pipe.
Plan of gas price increase from US$ 5.8/mmbtu to US$ 8/mmbtu, has the potential of increase subsidy for
electricity of Rp. 8 trillion per annum. For estimation, average gas price is US$ 8.53 per mmbtu. Based on that
price, gas cost of PLN is Rp. 32.42 trillion. If well-head gas price is US$ 8 per mmbtu, then the average gas price
including LNG is US$ 10.58 per mmbtu, and cost of gas pipe will increase to Rp. 40.28 trillion or additional cost
of Rp. 7.86 trillion. In that case, production cost of electricity of gas fired power plant, increase from Rp. 1210.35
per kWh to Rp. 1455.1 per kWh.

22. Case as an example of poor coordination in
project management

23. No Power Generator Number of Units Capacity (MW)
1 PLTU 4 260
2 PLTG 5 626,3
3 PLTGU 2 270
TOTAL 1,156.3
Belawan Power Plant
PLN Belawan Sector is the largest power plant in northern Sumatra, which consists
of four units of the power plant , four power plant units and 2 Blocks Power Plant with
a total capacity of 1156.3 MW .
The whole Gas Fired Power Plants capacity 896.3 MW. PLN Belawan Sector located in
the northern city of Medan , ± 24 KM from city center of Medan . Located in Sicanang
Island with area of ± 47 hectares , surrounded by two river that meets the sea in the
waterway.

24. Medan Case : domestic gas supply too expensive?
• 900 MW Medan Power Plants gas supplies-from FSRU to Arun-Bel Pipe-hi cost
transport. Cost of domestic gas becomes too expensive. While FSRU is moved to
Lampung.
• Cahaya Group plans to develop Gas Fired Power Plant, with FSRU solution and
imported gas (from Iran). As alternative to domestic gas supply, they are more
interested to use imported gas. PT. Pertamina has the same pattern by having gas
contract supply from US.
• Qatar Gas plans to invest and develop power plants in North Sumatera. Qatar as
foreign gas producer brings their gas and investment and sell it as power electricity
to Indonesia.

25. PLN Fired Power Plant

26. Additional 35,000 MW Power Capacity
Gas Fired Power Plant
15 Locations
Total Capacity 4430 MW
Gas Fired Power Plant
33 Locations
Total Capacity 3930 MW
Gas Fired Power Plant
48 Locations
Total Capacity 8360 MW

27. 1
3

28. 4
1
2
4

30. 1

31. 3
14
8
2

32. NGL

33. Badak NGL
• This year Badak NGL produces 9.7 million tons, 1 million ton lower than last year of 10.7
million tons.
• Salis S. Aprilian, President Director of PT. Badak NGL, PT. Pertamina may take 100% ownership
of this refinery in the year 2017.
• At the same time the refinery may receive new gas supply from ENI Jangkrik Gas Field and
Chevron IDD. Gas from the Jangkrik and Jangkrik Northeast fields in the Makassar Strait will
result in 14 LNG cargoes going to the domestic market in 2016; 18 cargoes/year over 2017-
2022, seven cargoes in 2023 and four LNG cargoes over 2024-2025. Gas from the fields will
be processed at the Bontang LNG plant. Indonesia's SKK Migas had approved Italian Eni's
development plan of the Jangkrik North East offshore gas field in the Muara Bakau block,
which is scheduled to come online by 2015. About 40% of production from the field will be
dedicated for domestic buyers at a price at $9/MMBtu. Pertamina has signed gas purchase
agreement of 1.4 million tons per year for domestic market.
• Meanwhile US' Chevron's Indonesian Deepwater Development in the Makassar Straits is
expected to supply 50 LNG cargoes/year over 2017-2019, 30 cargoes over 2020-2021, 16
cargoes in 2022 and 10 cargoes in 2023. The gas from the project will be processed at the
Bontang LNG plant. The project involves five gas fields (namely Bangka, Gehem, Gendalo,
Maha and Gandang) and four production sharing contracts (PSCs) for Ganal, Rapak, the
Makassar Strait and Muara Bakau. Their cumulated reserves are estimated at 2,300 bcf (65
bcm).
• Bontang's long-term customers include Kogas, Japan's Chubu Electric, Kansai Electric, Kyushi
Electric, Osaka Gas, Toho Gas, Hiroshima Gas, Nippon Gas and Nippon Steel, and Taiwan's
state-controlled CPC.

34. Indonesia Gas Industry
KKS/Gas Field LNG Plant
Badak NGL
Donggi Senoro
On Shore
Gas Users
Power Plant
Tangguh
CNG
Piping
Carrier Terminal Storage
Off Shore-FSRU Smelters
Industry (chemicals)
Gas Trading Co
Badak NGL is the biggest capacity train-backed with coming new gas field, including CBM.
Scope merely covers transport ,terminal re-gasification and last mile piping.

37. Gas Field Near Bontang Area

38. CBM PSC and gas pipeline to Badak NGL

39. Vessel CBM Tanks Temp. IMO Bar Built/Acquired
Norgas Unikum 12 000 2 -163 5.2 2011
Bahrain Vision 12 000 2 -163 5.2 2011
Norgas Innovation 2 10 000 2 -163 5.2 2010
Norgas Creation 2 10 000 2 -163 5.2 2010
Norgas Invention 2 10 000 2 -163 5.2 2011
Norgas Conception 2) 10 000 2 -163 5.2 2011 Norgas Unikum
Norgas Innovation 2
Plant 40 MW
6.15 MMSCFD
6,154 mmbtud
119 Ton/day
294.0 CBM LNG/D
Vessel Capacity 10000 CBM LNG
Usage 34 Days
Max Distance 3,458 Nm
Vessel Capacity 12,000 CBM LNG
Usage 41 Days
Max Distance 4,241 Nm
Gas Consumption
Sample Case
Bontang – Sabang 1,777 Nm
Bontang – Merauke 1648 Nm

41. Domestic Gas Trading Fri Jun 26, 2015
http://uk.reuters.com/article/indonesia-lng-idUKL3N0ZC2BY20150626
•One side-domestic need gas, the other side – many excess cargo.
•Two reasons, why there are excess cargo, first - increase in gas production,
secondly more competitive producers such as Qatar, USA and Australia. Further
PLN is not ready with high gas price. The government has decided to sell on US$
10 per MMBTU, while most buyers are ready with US$ 7,5 per MMBTU (or less).

42. LNG Market Update
• Most, but not all, LNG is sold on a price that is linked to, or in reference to, the price of oil. The buyer and
seller agree a floor, a ceiling and a slope. The floor is the minimum gas price accepted by the seller,
without which an LNG project can’t secure financing or the seller cannot make a minimal return. The floor
these days might be between $40-$60. The ceiling is the maximum gas price accepted by the buyer,
beyond which they would be better off to burn oil or coal (say $100-$120). The slope is the ratio of the
price of LNG relative to the price of oil between the floor and the ceiling. Common slopes are between 14
and 16%, so that a $10 oil price rise translates into a $1.40-$1.60 price rise in LNG. Contracts are
confidential, and information about them is hard to obtain.
• There are other variables to consider. Spot LNG might not be subject to the same pricing formula. Floors,
ceilings and slopes don’t matter. Some of the more recent LNG contracts originating in the US are priced in
a hybrid model, with some indexing with reference to oil and some with reference to the US continential
price (aka, Henry Hub). Therefore, it would be a mistake to assume that all LNG will be equally impacted
by oil price changes.
• This situation points out the biggest challenge to the LNG market. While there has been no change at all in
the fundamentals that determine the supply or demand for gas, its price is now down 20%. It could just as
easily go up 20%. It’s really hard to plan the business, set taxes or confirm budgets when the price can vary
so much in such a short time.
• Spot prices have been in a steady decline for months with key buyers Japan, Korea and Brazil out of the
market. At a minimum, those with contracted gas are paying the lower prices as per the slope, and will
have to decide if they are going to pass on price reductions to their customers. Some buyers may now be
tempted to lock in some longer supply contracts with a reset to the floor, ceiling or slope to reflect what
some will enthusiastically argue is a new fundamental market reality. The more price sensitive buyers of
LNG (India and China) might now enter the market.

43. US - Natural Gas Price up to Nov 2015
https://www.oilcrudeprice.com/natural-gas-price/

44. World LNG Estimated October 2015 Landed Prices

45. Japan Liquefied Natural Gas Import Price up to Nov 30
Data for this Date Range
Nov. 30, 2015 9.00
Oct. 31, 2015 9.25
Sept. 30, 2015 9.64
Aug. 31, 2015 9.18
July 31, 2015 8.87
June 30, 2015 8.59
May 31, 2015 8.72
April 30, 2015 10.22
March 31, 2015 14.28
Feb. 28, 2015 13.37
Jan. 31, 2015 15.12
Dec. 31, 2014 15.62
Nov. 30, 2014 15.59
Oct. 31, 2014 15.89
Sept. 30, 2014 15.16
Aug. 31, 2014 15.74
July 31, 2014 15.21
June 30, 2014 16.13
May 31, 2014 16.32
April 30, 2014 16.79
March 31, 2014 16.55
Feb. 28, 2014 16.76
Jan. 31, 2014 16.67
Dec. 31, 2013 16.38
Nov. 30, 2013 15.40
https://ycharts.com/indicators/japan_liquefied_natural_gas_import_price

46. Next Target?
• Marketing prospect of gas flow from Masela, Jangkrik, IDD and Blok A.
• GSPA PLN – Tanjung Priok after 2022
• Kontrak pembelian LNG dari AS pada 2018 dengan kapasitas 800 ribu ton per tahun
sampai 10 tahun. Butuh 1-2 LNG Tanker dengan kapasitas 140,000 – 170,000 CBM.
• Feasibility Study on LNG Marine Terminal for small vessels – for acquisition purpose.

47. LNG Infrastructure