The document summarizes a presentation on Indonesia's domestic gas market and pricing. It discusses forecasts for power sector gas demand, which is projected to double from 2011 to 2020. Coal is expected to increase its share of electricity generation fuel from half to two-thirds by 2020. Gas capacity is primarily mid-merit and peaking, with capacity factors around 50%. Power sector gas demand is forecast to increase 570 million standard cubic feet per day by 2020.

1. Gas Development Master Plan
Domestic Gas Market and Pricing
Consensus Building Workshop
Presented by:
William Derbyshire - Director
Economic Consulting Associates, UK
Shangri-La Hotel, Jakarta
21 June 2012

2. Overview
• Domestic gas market
1. Current market structure
2. Power sector demand forecast
3. Industrial demand forecast
4. Indonesia Gas Balance
5. Comparison of forecasts
6. Other factors
• Domestic gas pricing and regulation
1. End-user pricing
2. Transmission and distribution pricing
3. Network planning and expansion
2

3. Domestic Gas Market
3

4. 2010 gas supply and demand
mmscfd
737 PLN (7.9%)
788 PGN (8.4%)
Domestic
4509 1436 Other (15.4%)
(48.3%)
Own use
PSCs 1042 (11.2%)
8290
(88.8%) Supply
507 Losses (5.4%)
9336
3912 LNG (41.9%)
Export
4827 (51.7%)
Pertamina
(11.2%)
1046
915 Pipeline (9.8%)
Source: MIGAS (5th International Indonesia Gas Conference, January 2011) 4

5. 2010 domestic sales by user
Commercial
and
households
0%
Power 35%
Other
industrial 41%
Fertiliser 21%
Petrochem 3%
Sources: Calculated using data from MIGAS (non-PGN, non-power sales), PLN (gas sales to PLN)
and PGN (other sales). There are inconsistencies between data sources and these figures should be
seen as indicative only.
5

6. 2010 contracted industrial demand by type
Other
Glassware 4%
industries
9%
Ceramics 4%
Fertiliser -
feedstock 42%
Metal 12%
Pulp and paper
13%
Petrochem - Petrochem -
energy 6% feedstock 10%
Source: FIPGB. This figure shows contracted demand rather than actual sales and is, therefore, not
directly comparable with the preceding figures.
6

7. Summary of 2010 sales
mmscfd %
Exports 4,827 51.7%
Own use and losses 1,548 16.6%
PLN 776 8.3%
Fertiliser (direct) 619 6.6%
Petrochemical (direct) 92 1.0%
Refining 78 0.8%
Based on contracted
demand, the most
LPG 57 0.6%
significant Other Industrial
users are Pulp and Paper
Krakatau Steel 55 0.6% and Iron and Steel (Metal)
Other Industrial 1,266 13.6%
Commercial and Household 18 0.2%
7

8. Electricity generation by fuel (2011-2020)
GWh • Coal is the dominant
400,000 fuel, increasing its
Hydro, biomass, wind and solar
350,000 Geothermal
share of the fuel mix
HSD + MFO
from one-half to
300,000
Gas (inc. LNG) two-thirds
250,000 Coal
• The share of gas in
200,000 total generation
remains fairly
150,000
constant at ~20%
100,000
• Total gas-fuelled
50,000 generation is
0
forecast to double
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 over the period, in
line with the growth
Source: RUPTL 2011-20
in total output
8

9. Capacity and capacity factors (2011-2020)
Installed capacity Average capacity factors
MW
90,000 100%
Hydro, biomass, wind and solar Coal Gas (inc. LNG)
80,000 90%
Geothermal
HSD + MFO 80%
70,000
Gas (inc. LNG) 70%
60,000
Coal
60%
50,000
50%
40,000
40%
30,000
30%
20,000
20%
10,000 10%
0 0%
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
• Gas-fuelled capacity is primarily running as mid-merit and peaking plant,
with capacity factors ~50%
• Average thermal efficiency of gas-fuelled capacity is forecast to rise from
33% in 2011 to ~43% from 2012 onwards, with commissioning of new large
combined cycle gas turbines (CCGTs / PLTGUs)
Source: RUPTL 2011-20 and consultant calculations
9

10. Power sector gas demand (2005-2020)
mmscfd • Demand for gas
1,600 increases by 75%
LNG
1,400
over 2010 levels or
Gas
by 570 mmscfd (6%
1,200
2010 PLN gas of 2010 gas
1,000
consumption
production)
800 • Demand grows by
less than output, due
600
to increasing average
400 power plant
200 efficiency
0
• LNG is expected to
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
meet 50% of gas
demand by 2020
Source: PT PLN (Persero) RUPTL. 2005 to 2010 values are for PLN only
10

11. FIPGB industrial demand (2011-2025)
mmscfd • Industrial demand is
4,000
Other industries projected to grow by
3,500
Flat Glass
Ceramics
around one-third to
Metal
Pulp and paper
2025 or by ~1,000
3,000 Petrochem - energy mmscfd (11% of
Petrochem - feedstock
2,500 Fertiliser - feedstock 2010 gas production)
2,000 • The majority of this
growth comes from
1,500
the use of gas as a
1,000 feedstock rather
500 than for energy
0
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Source: FIPGB. The figure shows contracted or planned demand. Not all industrial gas users are
members of FIPGB and these forecasts, therefore, will understate expected industrial demand
11

12. Indonesia Gas Balance by use (2011-2025)
mmscfd • Only domestic
12,000 demand is shown (ie,
Industry
gas for export is not
Fertiliser
10,000 included)
Electricity
• The forecast shows
8,000
the sum of
6,000
contracted,
committed and
4,000 potential demand
• This assumes no
2,000
constraints on
0
natural gas supplies
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Source: Indonesia Gas Balance, 2010
12

13. Indonesia Gas Balance by status (2011-2025)
mmscfd • The robustness of
12,000 supply projections
Potential
fall over time
Committed
10,000
• We need to better
Contracted
understand how the
8,000
gas balance is
6,000
prepared
• In particular, we
4,000 need to better
understand how the
2,000
forecasts relate to
the RUPTL
0
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Source: Indonesia Gas Balance, 2010
13

14. RUPTL, FIPGB and Gas Balance compared
mmscfd Gas Balance
• Demand forecasts in
12,000
contracted +
committed +
the Indonesia gas
potential balance are ~3x
10,000 higher than those
Gas Balance
derived from
8,000 contracted+
committed
summing the RUPTL
and FIPGB forecasts
6,000
RUPTL + FIPGB
• The difference may
4,000 be due in part to the
Gas Balance different
contracted
2,000 assumptions on
supply constraints
0
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 and in part to recent
changes in PLN’s
RUPTL
14

15. Historic forecasts compared
mmscfd
• Historic forecasts
12,000 Gas Balance (2010)
- All Potential
appear to have
consistently
10,000 overstated actual gas
ADB (2003) -
Low case
demand
8,000
• The much lower
6,000
growth forecasts
Nexant (2006) -
Median case obtained from the
Actual
4,000 RUPTL and FIPGB are
in line with actual
RUPTL+FIPGB
2,000 (2010/2012) growth in demand
• Supply constraints
0
2000 2004 2008 2012 2016 2020 2024 may mean there is
suppressed (unmet)
demand
15

16. Historic demand and forecasts by use
Electricity demand Other domestic demand
mmscfd mmscfd
Gas Balance (2010)
- All Potential
6,000 6,000
Gas Balance (2010)
- All Potential ADB (2003) -
5,000 5,000 Low case
4,000 ADB (2003) - 4,000
Low case
3,000 3,000 Actual
Nexant (2006) -
Median case
2,000 Actual 2,000 Nexant (2006) -
Median case
1,000 1,000 FIPGB (2012)
RUPTL (2010)
0 0
2000 2004 2008 2012 2016 2020 2024 2000 2004 2008 2012 2016 2020 2024
• The divergence between actual and forecast demand appears to be largely
due to much lower use of gas in electricity generation than was forecast
• This may be due to gas supply shortages limiting PLN’s use of gas, and/or
to a shift to increased use of coal by PLN
16

17. Potential for gas in transport
NGV penetration in SE Asia
• There is much interest in NGV penetration
replacing subsidised fuels (vehicles)
2.5%
with Natural Gas Vehicles 2.23%
(NGVs) 2.0%
• Achieving the same 1.5%
penetration rate in 1.0% 0.89%
Indonesia as in Thailand 0.61%
would imply 685,000 NGVs 0.5%
0.27% 0.32%
0.001% 0.001% 0.003%
0.0%
• The resulting gas demand
would be ~32mmscfd (0.3%
of domestic production) Source: NGV Global
• This would be equivalent to displacing 360 Ml of Premium fuel (1.6% of
current Premium use)
17

18. Environmental considerations
• We understand there are no specific targets to reduce
greenhouse gas emissions from the power sector
• Perpres 61/2011 (National Action Plan for Greenhouse
Gas Emissions Reduction) has some provisions on
increasing gas utilisation to reduce emissions
• by 2014, 29 mmscfd(?) used by public transport in Palembang,
Surabaya and Denpasar
• by 2020, 629 mmscfd(?) used by public transport in Medan,
Jabodetabek, Cliegon, Cirebon, Balikpapan and Sengkang
• by 2014, increasing natural gas distribution to 94,500 households
• monitoring of implementation of flare gas reduction policy
18

19. Regional domestic demand and available supply
(2011) – Indonesia Gas Balance
Available supply ( existing + projected production - exports)
Domestic demand( contracted + committed + potential domestic demand
Values in mmscfd
1631 1349
733
2563
1400
588
3463
Domestic demand and available supply in regions not shown is <250 mmscfd
19

20. Regional domestic demand and available supply
(2020) – Indonesia Gas Balance
Available supply ( existing + projected production - exports)
Domestic demand( contracted + committed + potential domestic demand
Values in mmscfd
826 1271
1106
370
2385
236 600
5429
Domestic demand and available supply in regions not shown is <250 mmscfd
20

21. Comments on domestic gas market
• Current projections of gas demand appear to be far in
excess of actual levels and the most recent information
on gas requirements for electricity generation (PLN’s
RUPTL) and industry (FIPGB forecasts)
• Reasons for this difference include
• suppressed (unmet) demand due to insufficient supplies
• low historic gas prices and no penalties for overly-optimistic
demand forecasts leading to excessive requests for supply from
industry in particular
• PLN increasingly turning to coal rather than gas for future
electricity generation
21

22. Implications for the GDMP
• Existing demand forecasts are unlikely to be reliable as a
basis for the Gas Development Master Plan (GDMP)
• the existing forecasts do not appear to recognise supply
constraints
• rising wellhead gas prices may restrict demand growth,
particularly from industry
• new industrial demand forecasts are needed for the GDMP
• household, commercial and transport demand is likely to remain
relatively insignificant
22

23. Domestic gas pricing and
Regulation
23

24. Gas pricing regulation in Indonesia
• Minister of Energy and Mineral Resources Regulation
19/2009
• prices for general users determined by supplier (cost-based
approach appears to be followed by PGN)
• prices for special users determined by Minister of Energy
• prices for residential users regulated by BPH MIGAS
• Minister of Energy and Mineral Resources Decree 3/2010
• priorities for domestic gas utilisation: (1) oil and gas production;
(2) fertiliser; (3) electricity generation; (4) industries
24

25. Regulated tariffs (BPH MIGAS Regulation 3)
• Four regulated categories
Residential 1 (RT-1):
• Basic housing - 0-50 m3/month / Basic price applied
Residential 2 (RT-2):
• Middle-class and luxury housing 0-50 m3/month / RT-1 price +
20%
Commercial 1 (PK-1):
• Government and social – 0-1,000 m3/month / Basic price
applied
• Commercial 2 (PK-2)
• Private – 0-1,000 m3/month / RT-1 price + 15%
• The tariff is indexed to the Indonesian Consumer Price
Index (CPI). However, it is unclear how prices are set for
new areas with no existing gas price or following changes
in upstream prices
25

26. Upstream price renegotiation
• BP MIGAS has stated its intent to raise upstream gas
prices for the domestic market to $5-6/mmbtu from
PGN’s previous average cost of $2.9/mmbtu
• East Java - Santos contract for 100 mmscfd raised from
$2.14/mmbtu to $5/mmbtu with 3% escalation per annum
(November 2011)
• West Java - Conoco-Phillips contract for 400 mmscfd raised from
$1.85/mmbtu to $5.6/mmbtu (staged increase) and Pertamina
contract for 250 mmscfd raised from $2.2/mmbtu to $5.5/mmbtu
(May 2012)
• Increases agreed on business to business basis and
accompanied by commitments to meet contracted
supply volumes
• PGN appears to have been able to pass increases through
to end-users, maintaining its margins
26

27. PGN’s selling prices
• Average sales price in
Premium 33.00
2011 was $6.95/mmbtu
Kerosene 31.01
HSD 30.76 • Prices for West Java
MDF/IDO (Diesel) 29.07 industrial customers (67%
MFO 24.28 of PGN’s sales) are
LPG Bulk 18.29
reported to have risen
LPG 50kg Unsubsidised 18.11
from $6.8/mmbtu to
LPG 12kg Unsubsidised 14.35
PGN West Java Price (May 2012) 10.13
$10.13/mmbtu following
LPG 3kg Subsidised 10.05
the conclusion of
PGN Average Sales Price 6.95 upstream price
0 5 10 15 20 25 30 35 renegotiations in May
$/mmbtu
2012
Source: PGN. Prices as at 1 May 2012. Exchange rate
of US$ 1 : IDR 9.000 • This still remains
competitive with
alternative fuels
27

28. Future cost and price pressures
• Shift to LNG supplies delivered through floating storage
and regasification vessel (FSRUs) with landed prices
estimated at ~$10/mmbtu
• Continuing pressure to increase upstream prices towards
export parity levels ($8.12-13.23/mmbtu)
• Increasing cost of supply from new fields
• Will these upward pressures be offset by the impacts of
unconventional gas supplies on the Asia-Pacific market?
• Will the domestic market obligation (DMO) offset the
pressures to increase prices to export parity?
28

29. Regulation of gas transmission and
distribution
• Operation of gas transmission lines and distribution
networks requires a Special Right issued by BPH MIGAS
• For new lines and networks, Special Rights are issued for
up to 20 years through a tendering process. The holder of
a Special Right must pay a toll to BPH MIGAS
• Holders of Special Rights are required to allow third party
access (TPA) to their facilities. The terms and conditions
are negotiated between the Rights holder and the third
party
• Cost-based pipeline tariffs are determined by BPH MIGAS
on the basis of a proposal by the operator. Tariffs may be
postage-stamp or distance-based
29

30. Experience with pipeline tendering
• Six transmission pipeline tenders launched in 2006
• In principle, pipelines awarded on basis of commercial,
technical and financial evaluation
• However, no requirements to provide signed
engineering, procurement and construction (EPC)
contracts or evidence of financing
• Construction has not started to date
• A major contributing factor is a lack of firm gas supplies
for the individual pipelines
30

31. Regulatory issues in gas network planning
• Mandatory Transmission and Distribution Master Plan sets out
interconnected system, but has various weaknesses
– does not describe priorities
– new unsolicited projects can only be included in annual updates
– unclear whether all projects are least-cost or how decisions are
made whether these are open access or dedicated facilities
– some transmission pipeline routes and distribution pipelines
areas appear to be sub-optimal
• Current infrastructure planning process appears neither market-
driven nor centrally-coordinated
– example of Minister BUMN’s decision to relocate PGN’s Medan
LNG regasification terminal to Lampung and also to terminate
development of Pertamina’s planned LNG regasification terminal
at Semarang
31

32. Issues in domestic gas pricing and regulation
• Integration of upstream development and pipeline
infrastructure planning is a priority
• The master plan is mandatory but not necessarily least-
cost
• Need for consistency in objectives across upstream
pricing and end-user tariffs
32