Natural Demand Potential and Infrastructure in the EAS Region Prof. Hidetoshi Nishimura 2 Nov 2017 Bangkok 1
Large Demand Potential in ASEAN + India 3 Scenarios as to the share of natural gas in the additional thermal power plants (15%, 30%, 60%) Natural gas demand for ASEAN + India in 2030 may expand by 2.3 to 2.5 times compared with 2015 By sector, the power generation sector has the largest potential, followed by the industrial sector. Additional Thermal Scenario 1 Scenario 2 Scenario 3 15% 30% 60% 600 500 Natural gas demand potential by sector (2030) (Mtoe) 2.3 2.3 2.5 times times times Exports, etc Non-energy use 400 Res./Com., etc Exsisting thermal Age 40 Age < 40 Age 40 Age < 40 Age 40 Mine mouth & Age < 40 Hydro RE Oil Hydro RE Oil 2013 2030 actual estimation 300 200 100 0 2013 2015 BAU Scenario Scenario Scenario 1 2 3 Domestic marine International marine CNG Industry Power generation 2
Key Assumptions for Non Power Sectors in ASEAN + India Share of Natural gas at BAU Target share Country Share >=33% Share at BAU + 5% Indonesia, Malaysia Industry Sector Reference share of Natural gas in Industry sector: 33% 10%< Share <33% Share <=10% 1.5 times of Share at BAU (Max. 33%) 2 times of Share at BAU Myanmar, Singapore, Thailand, Viet Nam Brunei, India, Philippines, Road Transport (CNG) International Marine Annual growth rate of CNG consumption in the country is assumed as twice of BAU scenario Three quarter of high sulphur bunker fuel is expected to be substituted with other fuel in 2020. Half of the low sulfur fuel to meet IMO standard is assumed to be LNG Country 2013/2000 2030 BAU/2013 Potential Brunei - - 1% of Oil demand India 28% 8% 16% Indonesia 2% 7% 14% Malaysia - 1% 2% Myanmar 41% 3% 6% Philippines - 21% 42% Singapore - 2% 4% Thailand 73% 2% 4% Viet Nam - - 1% of Oil demand 25% High Sulphur Bunker Fuel Residential, Commercial and Others A quarter of oil demand in BAU scenario will be replaced with natural gas, except for Laos and Cambodia 100% (41Mtoe) High Sulphur Bunker Fuel 75% oil LNG Current 2030 50% 50%
Economic/Environment Benefit of Natural. Power generation Fuel import cost Case LNG: USD 11.9/MMBtu LNG: USD 9/MMBtu LNG: USD 6/Mbtu Construction cost CO 2 emission (Billion USD) (Billion USD) (Billion USD) (Billion USD) (Million tons-co2) * * Scenario 1 +0.7 +0.5 +0.4 +0.1 +6.4 (+0%) Scenario 2 +7.5 +4.9 +2.2-0.5-55.8 (-2%) Scenario 3 +20.7 +13.3 +5.6-1.7-176.5 (-6% ) Other sectors total Fuel import cost LNG: USD 11.9/Mbtu LNG: USD 9/Mbtu LNG: USD 6/Mbtu CO 2 emission (Billion USD) (Billion USD) (Billion USD) (Million tons-co2) -23.2-33.7-44.6-0.047 (-2%) 4
Investment Need for LNG Supply Chain by 2030 More primary LNG terminals necessary by 2030 Estimated LNG Primary investment Terminal for Location additional LNG supply chain by 2030 is 81 billion USD altogether. Utilization (existing, planned of existing and infrastructure additional) like national railway system and ports. Primary LNG terminal in ASEAN could cover other countries area. Additional Planned Existing 6
Investment in Supply Chain Options Scope of LNG supply chain infrastructure and allocation methodology Scope of LNG supply chain infrastructure Three level hierarchy system is assumed Depending on the demand type, the transport methods are decided Pipeline, Land transport (Truck and Railway) and Sea transport are assumed. Primary level (over 1.0 MTPA) Secondary level (between 0.2-1.0 MTPA) Tertiary level LNG terminal Distribute pipeline ISO container by rail or truck City use Industrial use Small scale thermal power plant LNG terminal ISO container by rail or truck Satellite facility Industrial use Small scale power plant LNG terminal pipeline Large scale thermal power plant pipeline Large scale thermal power plant Allocation methodology Compared to ISO containers, the pipeline transport is prioritized in case of the distance from port to thermal power plans are close as within 32.5 km because transshipment works need time and efforts. In case that both neighbor ports and thermal power plants have rail connectivity and distance between them is over 32.5 km, the railway transport is assumed to be applied. In case of impossibility to use pipeline and railway, the conditions to use truck transport can be satisfied, the truck will be used for the transport. Other cases but the above mentioned case are discussed as case by case. Transport mode from neighbor ports Transmission pipeline Rules According to the case in Japan (Tokyo Elec. Corp.: distance from Futtsu LNG terminal to Chiba gas thermal power plant is 32.5 km), so that the transmission pipeline is assumed as transport mode with 32.5 km from port to thermal power plant. Rail At port If the distance between railway and port is within 15km, it is judged as connectivity and railway transport can be used At demand points (e.g. thermal power plant) If the distance between railway and thermal power plant is within 15km, it is judged as connectivity and railway transport can be used trucks Distance Normally, port has road connectivity, so that if the demand points are within 700km from ports, it is judged as transportable. Frequency Upper limit is set as 24 times/day of 40ft ISO container (13.5 ton eq.) 6
Sustainable Development of Natural Market in East Asia Japan s Fuel Import Prices per Unit of Heat Content JPY/1000kcal 12 Crude oil 10 LNG Thermal coal 8 6 4 2 0 2010/01 2011/01 2012/01 2013/01 2014/01 2015/01 2016/01 Share of Natural in Total Primary Energy Supply World avg. EAS avg. Cambodia China India Philippines Myanmar Viet Nam Korea Indonesia New Zealand Japan Australia Thailand Singapore Malaysia Brunei Others Year=2015 0% 20% 40% 60% 80% 100% Mechanism to Squeeze out Natural from the Power Generation Market Weak power demand Lower wholesale power price Natural gas loses competitiveness RE inflow w/o market mechanism Lower carbon price
Policies and Actions to Strengthen the Competitiveness of Natural in the Region The expanded use of LNG in Asia will depend (i) LNG s competitiveness against other energy sources, & (ii) sufficient investment in every part of the value chain. Natural Industry Government Producing country Adopting effective cost reduction measures Removing or relaxing destination clause Creating a reliable natural gas price benchmark Jointly developing well functioning market Optimizing upstream supply infrastructure Jointly developing well functioning market Improving investment environment Optimizing upstream supply infrastructure Supporting investment through public finance Consuming country Adopting effective cost reduction measures Removing or relaxing destination clause and optimizing logistics Creating a reliable natural gas price benchmark Jointly developing well functioning market Optimizing downstream supply infrastructure Investing upstream by downstream players Creating a reliable natural gas price benchmark Liberalizing the domestic market Providing a low carbon policy Jointly developing well functioning market Encouraging natural gas use through public policies Optimizing downstream supply infrastructure Supporting investment through public finance
Conclusions Comprehensive and intensive policies as well as actions from both producer and consumer side of stakeholders in the following regards are recommended, in order to support the development of the regional natural gas market in the following four aspects. Security of Supply Sufficient Infrastructure Investment Flexibility Affordability and Price Formation Mechanism