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