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Psc william derbyshire (formatted)

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  • 1. Gas Development Master PlanDomestic Gas Market and PricingConsensus Building WorkshopPresented by:William Derbyshire - DirectorEconomic Consulting Associates, UKShangri-La Hotel, Jakarta21 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 demandmmscfd 737 PLN (7.9%) 788 PGN (8.4%) Domestic 4509 1436 Other (15.4%) (48.3%) Own usePSCs 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 beseen 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, notdirectly 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 mostLPG 57 0.6% significant Other Industrial users are Pulp and PaperKrakatau 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 dominant400,000 fuel, increasing its Hydro, biomass, wind and solar350,000 Geothermal share of the fuel mix HSD + MFO from one-half to300,000 Gas (inc. LNG) two-thirds250,000 Coal • The share of gas in200,000 total generation remains fairly150,000 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 growthSource: 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 gas1,600 increases by 75% LNG1,400 over 2010 levels or Gas by 570 mmscfd (6%1,200 2010 PLN gas of 2010 gas1,000 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 2020Source: 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 2025Source: FIPGB. The figure shows contracted or planned demand. Not all industrial gas users aremembers of FIPGB and these forecasts, therefore, will understate expected industrial demand 11
  • 12. Indonesia Gas Balance by use (2011-2025)mmscfd • Only domestic12,000 demand is shown (ie, Industry gas for export is not Fertiliser10,000 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 2025Source: Indonesia Gas Balance, 2010 12
  • 13. Indonesia Gas Balance by status (2011-2025)mmscfd • The robustness of12,000 supply projections Potential fall over time Committed10,000 • 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 2025Source: Indonesia Gas Balance, 2010 13
  • 14. RUPTL, FIPGB and Gas Balance comparedmmscfd Gas Balance • Demand forecasts in12,000 contracted + committed + the Indonesia gas potential balance are ~3x10,000 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 comparedmmscfd • Historic forecasts12,000 Gas Balance (2010) - All Potential appear to have consistently10,000 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 3463Domestic 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 5429Domestic 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 14.35PGN 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 $/mmbtu 2012Source: PGN. Prices as at 1 May 2012. Exchange rateof US$ 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 anddistribution• 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