We have witnessed a sharp spike in LNG prices in all markets since late last year. This has been particularly acute in the Asia Pacific region. As of September 30, 2021, spot LNG prices on the Japan-Korea Marker (JKM Index) have risen from $2.56 per mmbtu on July 31, 2020 to $30 per mmbtu on September 29, 2021. This escalation has shocked Asia Pacific governments and industry and has important implications for energy diversification and low carbon policies.
The price spike comes at a time when Asia Pacific countries are looking to reduce the role of coal in their energy and power sector mixes even as energy and electricity demand is recovering from the lows of the pandemic recession. This situation is increasing the importance of natural gas and renewables as a substitute for coal, especially in light of China’s President Xi announcement at the September UN General Assembly meeting that China would stop building coal plants overseas, following the previous, similar Japanese and S. Korean decisions.
Although natural gas prices are expected to moderate after the winter, it is unclear by how much given strong demand and the lower investment in both gas production and new LNG liquefaction export capacity investment as well as short-term limitations on expanding LNG exports from the Australia, Qatar, and the United States.
As we have indicated in the September 14 blog, the Asia Pacific is the largest coal consuming region of the world, accounting for 80% of global coal use in 2020. Coal supplied 27% of the Asia Pacific’s primary energy and 57% of its electricity in 2020. Although gas provided about a quarter of primary energy, its role in the electricity mix was much smaller at 11%.
Yet natural gas, especially imported LNG, is being pursued as a substitute for higher carbon-emitting coal. Vietnam will start importing LNG in 2022 and plans to increase its LNG purchases to 15 mtpa by 2035 to lower carbon emissions. The Philippines is also looking to begin importing LNG in 2022 as the domestic production from its offshore Malampaya natural gas field falls off and as the government implements a moratorium on new coal power plants. Thailand has considerable domestic natural gas production that accounts for 70% of its gas consumption. But with expected declines in existing gas fields, Thailand expects a six-fold increase in imports with LNG imports accounting for 70% in 2037 compared with 16% at present. Both Pakistan and Bangladesh have increased LNG imports over the past several years to 10.6 bcm and 8.97 bcm respectively in 2020 and plan to increase LNG import capacity and limit new coal plants.
Although Australia, Indonesia, Malaysia and Papua New Guinea exported 177.3 bcm of LNG in 2020, the Asia Pacific is a net gas importing region, with LNG imports in 2020 of 345 bcm against total gas consumption of 861 bcm. The three leading LNG importers were Japan, China, and South Korea. The LNG import market has grown substantially over the past decade from 208 bcm in 2011 to the current 345 bcm, almost entirely in the non-OECD Asia markets, especially China and India. China is surpassing Japan as the leading importer in 2021, although Japanese LNG imports have increased this year compared with the 3.6% drop in 2020. India has become the fourth leading global importer of LNG, with imports of 35 bcm in 2020, and is looking for imports to reach 47.5 mtpa as new FSRU capacity comes on stream. Prime Minister Modi has announced a target of increasing gas to 15% of India’s energy mix in 2030 from the current 6%. Gas use in the power sector is however low in both China and India at 3.1% and 4.5% respectively in 2030 and increased gas use in power will be critical to their efforts to reduce emissions from their dominant coal power sub-sectors.
Japan was the largest LNG importer in 2020 but its future market is quite uncertain. Japan generates about 35% of its electricity from natural gas but the recent draft Sixth Strategic Energy Plan foresees a reduction of natural gas use to 20% of electricity generation in 2030 compared with the previous target of 27%. But this lowering of expected gas in the mix is widely questioned since targets of 21% for nuclear and 37% for renewables by 2030 are seen as difficult to achieve.
The future of gas in Asia and the Pacific is also influenced by the debate over whether gas is truly a bridge to a carbon-free energy system. Although the benefits of substitution of gas for coal and as well as for system flexibility, are widely acknowledged, others are concerned about building an expensive gas infrastructure that will not be sustainable and will perpetuate CO2 emissions. The higher LNG import prices make renewables even more cost effective and are therefore increasing the imperative for more rapid renewable energy development for economic and as well as energy security reasons.
A key medium and long-term factor in considering this issue is the innovation and commercialization plans for hydrogen development. Japan, China, South Korea, India, Australia and other Asia countries have developed strategies to both import/convert LNG to hydrogen and produce “green hydrogen” from domestic renewables. Nuclear power can also be well-suited to producing hydrogen given its base-load characteristics. While currently expensive, hydrogen can be blended in gas pipeline infrastructures and power combustion technologies as well as substitute for coal and gas in industry and fuel vehicles. It can also help solve the storage problem of electricity systems with high level of intermittent renewables. For power generation, GE, Mitsubishi, and Siemens currently have global projects that are using a mix of hydrogen up to 50% and are developing turbines and injection systems that will allow 100% hydrogen use by 2025-2027. In March, S. Korea’s SK industry conglomerate announced it would spend $16 billion over the next five years to develop a domestic hydrogen complex, including a facility in the Incheon petrochemical center by 2023 and a large hydrogen base near the LNG terminal at Boryeong that would produce 250,000 tons of hydrogen from imported LNG and use carbon capture and storage technology. China is currently the world largest hydrogen producer and they have included hydrogen as one of their “future industries” in their 2021-2025 14th Five Year Plan. According to Reuters, Sinopec, which currently produces “grey hydrogen from its refineries, has committed to be carbon neutral by 2050 and plans major investments in both “blue” and “green” hydrogen production. Natural Gas World reports that Australia, with its enormous renewable energy potential, is also looking to become a leader in green hydrogen development with many companies, e.g., Fortescue Future Industries (FFI), BP, BHP and Woodside, planning major hydrogen production investments and demonstration projects. There are many challenges and risks in hydrogen development but the costs of electrolyzers and other technologies are expected to decline with growing innovation and global development efforts. Thus, although the extremely high natural gas prices may sour some countries and investors on LNG development, the vision of converting and developing gas networks and power plants to hydrogen, as well as the benefits of near-term substitution for higher emitting coal, is a potentially compelling pathway to net zero 2050 goals. The IEA’s Net Zero Roadmap sees hydrogen production in its NZE scenario increasing from about 90 M tons in 2020 to 200 M tons in 2030, ramping up to 539 M tons by 2050, with low carbon hydrogen accounting for about 70% of the total in 2030 with half from electrolyzers and the rest from natural gas and coal with CCUS.
Future blogs will examine the energy transition decisions that individual Asia and Pacific countries are making and their reactions to the higher LNG import prices.
Much of the data for this blog is from the BP, Statistical Review of World Energy 2021.