Presented by:

William Derbyshire - Director Economic Consulting Associates, UK

Shangri-La Hotel, Jakarta

21 June 2012

Gas Development Master Plan Domestic Gas Market and Pricing Consensus Building Workshop

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

3

Domestic Gas Market

4

2010 gas supply and demand

737 PLN (7.9%)

788 PGN (8.4%)

1436 Other (15.4%)

1042 Own use

(11.2%)

507 Losses (5.4%)

3912 LNG (41.9%)

915 Pipeline (9.8%)

4827 Export

(51.7%)

4509 Domestic

(48.3%)

8290 PSCs

(88.8%)

1046 Pertamina

(11.2%)

Supply

9336

mmscfd

Source: MIGAS (5th International Indonesia Gas Conference, January 2011)

5

2010 domestic sales by user

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.

Power 35%

Fertiliser 21%

Petrochem 3%

Other industrial 41%

Commercial and

households 0%

6

2010 contracted industrial demand by type

Source: FIPGB. This figure shows contracted demand rather than actual sales and is, therefore, not

directly comparable with the preceding figures.

Fertiliser -feedstock 42%

Petrochem -feedstock 10%

Petrochem -energy 6%

Pulp and paper 13%

Metal 12%

Ceramics 4%

Glassware 4%Other

industries 9%

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%

LPG 57 0.6%

Krakatau Steel 55 0.6%

Other Industrial 1,266 13.6%

Commercial and Household 18 0.2%

Based on contracted demand, the most

significant Other Industrial users are Pulp and Paper

and Iron and Steel (Metal)

8

Electricity generation by fuel (2011-2020)

• Coal is the dominant fuel, increasing its share of the fuel mix from one-half to two-thirds

• The share of gas in total generation remains fairly constant at ~20%

• Total gas-fuelled generation is forecast to double over the period, in line with the growth in total output

Source: RUPTL 2011-20

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

GWh

Hydro, biomass, wind and solar

Geothermal

HSD + MFO

Gas (inc. LNG)

Coal

9

Capacity and capacity factors (2011-2020)

• 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

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

MW

Hydro, biomass, wind and solar

Geothermal

HSD + MFO

Gas (inc. LNG)

Coal

Installed capacity Average capacity factors

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Coal Gas (inc. LNG)

10

Power sector gas demand (2005-2020)

• Demand for gas increases by 75% over 2010 levels or by 570 mmscfd (6% of 2010 gas production)

• Demand grows by less than output, due to increasing average power plant efficiency

• LNG is expected to meet 50% of gas demand by 2020

Source: PT PLN (Persero) RUPTL. 2005 to 2010 values are for PLN only

0

200

400

600

800

1,000

1,200

1,400

1,600

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

mmscfd

LNG

Gas

2010 PLN gas consumption

11

FIPGB industrial demand (2011-2025)

• Industrial demand is projected to grow by around one-third to 2025 or by ~1,000 mmscfd (11% of 2010 gas production)

• The majority of this growth comes from the use of gas as a feedstock rather than for energy

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

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

mmscfd

Other industries

Flat Glass

Ceramics

Metal

Pulp and paper

Petrochem - energy

Petrochem - feedstock

Fertiliser - feedstock

12

Indonesia Gas Balance by use (2011-2025)

• Only domestic demand is shown (ie, gas for export is not included)

• The forecast shows the sum of contracted, committed and potential demand

• This assumes no constraints on natural gas supplies

0

2,000

4,000

6,000

8,000

10,000

12,000

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

mmscfd

Industry

Fertiliser

Electricity

Source: Indonesia Gas Balance, 2010

13

Indonesia Gas Balance by status (2011-2025)

• The robustness of supply projections fall over time

• We need to better understand how the gas balance is prepared

• In particular, we need to better understand how the forecasts relate to the RUPTL

Source: Indonesia Gas Balance, 2010

0

2,000

4,000

6,000

8,000

10,000

12,000

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

mmscfd

Potential

Committed

Contracted

14

RUPTL, FIPGB and Gas Balance compared

• Demand forecasts in the Indonesia gas balance are ~3x higher than those derived from summing the RUPTL and FIPGB forecasts

• The difference may be due in part to the different assumptions on supply constraints and in part to recent changes in PLN’s RUPTL

0

2,000

4,000

6,000

8,000

10,000

12,000

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

mmscfd

Gas Balancecontracted

Gas Balancecontracted+ committed

Gas Balancecontracted + committed +

potential

RUPTL + FIPGB

15

Historic forecasts compared

• Historic forecasts appear to have consistently overstated actual gas demand

• The much lower growth forecasts obtained from the RUPTL and FIPGB are in line with actual growth in demand

• Supply constraints may mean there is suppressed (unmet) demand

0

2,000

4,000

6,000

8,000

10,000

12,000

2000 2004 2008 2012 2016 2020 2024

mmscfd

Actual

ADB (2003) -Low case

Nexant (2006) -Median case

RUPTL+FIPGB (2010/2012)

Gas Balance (2010) - All Potential

16

Historic demand and forecasts by use

• 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

Electricity demand Other domestic demand

0

1,000

2,000

3,000

4,000

5,000

6,000

2000 2004 2008 2012 2016 2020 2024

mmscfd

Actual

ADB (2003) -Low case

Nexant (2006) -Median case

RUPTL (2010)

Gas Balance (2010) - All Potential

0

1,000

2,000

3,000

4,000

5,000

6,000

2000 2004 2008 2012 2016 2020 2024

mmscfd

Actual

ADB (2003) -Low case

Nexant (2006) -Median case

FIPGB (2012)

Gas Balance (2010) - All Potential

17

Potential for gas in transport

• This would be equivalent to displacing 360 Ml of Premium fuel (1.6% of current Premium use)

• There is much interest in replacing subsidised fuels with Natural Gas Vehicles (NGVs)

• Achieving the same penetration rate in Indonesia as in Thailand would imply 685,000 NGVs

• The resulting gas demand would be ~32mmscfd (0.3% of domestic production)

0.001% 0.001% 0.003%

0.27%0.32%

0.61%

0.89%

2.23%

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

NGV penetration (vehicles)

Source: NGV Global

NGV penetration in SE Asia

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

19

Regional domestic demand and available supply (2011) – Indonesia Gas Balance

3463

2563

733

Domestic demand and available supply in regions not shown is <250 mmscfd

1349 1631

Available supply ( existing + projected production - exports)

Domestic demand( contracted + committed + potential domestic demand

Values in mmscfd

1400

588

20

Regional domestic demand and available supply (2020) – Indonesia Gas Balance

5429

2385

1106

Domestic demand and available supply in regions not shown is <250 mmscfd

1271

Available supply ( existing + projected production - exports)

Domestic demand( contracted + committed + potential domestic demand

Values in mmscfd

236

370

826

600

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

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

23

Domestic gas pricing and Regulation

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

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

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

27

PGN’s selling prices

• Average sales price in 2011 was $6.95/mmbtu

• Prices for West Java industrial customers (67% of PGN’s sales) are reported to have risen from $6.8/mmbtu to $10.13/mmbtu following the conclusion of upstream price renegotiations in May 2012

• This still remains competitive with alternative fuels

Source: PGN. Prices as at 1 May 2012. Exchange rate

of US$ 1 : IDR 9.000

6.95

10.05

10.13

14.35

18.11

18.29

24.28

29.07

30.76

31.01

33.00

0 5 10 15 20 25 30 35

PGN Average Sales Price

LPG 3kg Subsidised

PGN West Java Price (May 2012)

LPG 12kg Unsubsidised

LPG 50kg Unsubsidised

LPG Bulk

MFO

MDF/IDO (Diesel)

HSD

Kerosene

Premium

$/mmbtu

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?

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

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

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

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