By: Rahul Koul
Last updated : November 30, 2021 9:35 pm
Asian LNG spot prices collapsed since March 2019 but generation costs continue to favor coal above gas
A recent report focused on the Asia-Pacific fuel scenario points out a range of factors contributing to supply constraints in the adoption of liquefied petroleum natural gas (LNG), a highly promising alternative to coal.
The IHS Markit report, “Fuel Competition: Coal versus Gas Generation Fuels in Post-COVID Asia-Pacific” highlights factors such as COVID-19 delayed maintenances; lack of capital investments to increase overall supply and replace ageing facilities; complicated production and logistics; lack of favorable term economics; and additional pulls on demand due to weather.
In a reference to inter-continental factors affecting Asian market, the report also highlights how the fundamentals in Europe caused volatility in Asian LNG prices this year. It talks about drought affected hydropower in South America, especially Brazil; and supply constraints in other fuels due to flooding affecting coal production in Indonesia, China, and India; and cold 2020/2021 winter depleted global gas inventories.
The imports into China, South Korea, and Taiwan are higher this year, due to economic recoveries after the worst of COVID-19 lockdowns last year and fuel switching to gas in a de-carbonization drive. Only Japan is seeing lower imports as its economy is still struggling to recover fully, having been hit by a global semiconductor shortage on top of the COVID-19 pandemic.
Achieving significant price fall could unlock more demand in Asia Pacific. Among factors to look out for Generation Fuels in Post-COVID Asia-Pacific are demand driven by economic recoveries, meeting climate goals including pledges made so far, such as COP26; harsh weather and winters; and demand destruction due to closure of large gas users, e.g. fertilizer plants, blackouts and brownouts supply.
In China, the local Guangdong province government has raised on-grid tariffs for gas-fired power plants, allowing them to charge RMB 0.05 more for each kwh of electricity. This will slightly improve profitability of gas-fired power plants. Rather more fuel supply: mainly in coal, pipeline gas, and increased domestic gas production.
South Korea has removed 2% import tariffs for LNG until April 30, 2021. In Taiwan, CPC Corp. would purchase another 60 spot cargoes through the remainder of 2020 in order to feed Taipower’s growing gas-fired consumption.
In terms of gas adoption, there are largely a combination of contractual and structural constraints in play in Japan. Coal-gas competition is minimal despite narrowing power spreads in the country that have significantly narrowed in the first half of 2021. These have blown out again in the second half.
As per IHS Markit report, LNG demand in power generation is strongly influenced by nuclear restarts. In 2019, LNG generation was 17% lower than in 2014 (before the nuclear reactor restarts), gas burn fell further in 2020 because of the pandemic. Before the pandemic, coal generation was expected to increase in 2020 on reduced availability of baseload nuclear supply, and followed this trend for the first 4 months of the year. Weaker power demand then led to reduced coal consumption during the summer, while cheap gas prices allowed for some coal-to-gas switching later in the. Overall, coal generation fell by 2.1% in 2020, compared with 2019 levels, but grew its share in generation from 30% to 31%.
Owing to the lagged impact of lower oil prices earlier in the year, Japan’s average LNG import price fell to US $5.25/MMBtu in September 2020 - the lowest level in over a decade.
Japan’s lack of alternative power capacity means that during peak demand periods for power, both coal and gas are forced to run hard, eliminating the scope for any coal-to-gas switching during this time. The biggest threat to coal-fired generation is the return of nuclear power, although the share of renewables in generation has also rapidly increased in recent years.
In South Korea, the cost of importing coal to the country is still significantly cheaper than the cost of importing LNG, meaning that coal-to-gas switching is still far from being economic for most of the market. The biggest constraint to coal-to-gas switching in South Korea is the structure of the gas market.
As per the IHS Markit report, most of South Korea’s gas-fired generators (about 80%) are still tied to long-term oil-linked contracts with state-owned monopoly gas supplier, KOGAS. They typically procure their gas at a significant premium to the spot price, although at present, record high gas prices and stable/low oil prices means that contract gas prices are typically favourable to spot LNG prices.
In recent years, there has been a growing number of utilities—six in total—that have been able to bypass KOGAS and import LNG directly from the spot market thanks to their access to private LNG terminals. In 2020, imports by these companies accounted for 22% of South Korea’s total LNG imports, compared with about 10% in 2015. This has led to increased occurrences of coal-to-gas switching in more recent years.
A revision to South Korea’s coal tax, effective April 2019, has increased the burden on consuming coal. This will likely have some influence on coal-to-gas switching when fuel prices are close. Most of South Korea’s existing long-term LNG supply contracts will begin unwinding from 2024. KOGAS has already begun signing new contracts to supply gas-fired power generators from 2022 based on a new pricing scheme providing bespoke terms and conditions rather than a set formula.
Korea’s state-owned generators are currently considering whether to buy new supply directly from the international market or to purchase from KOGAS under the individual tariff scheme, particularly for their new gas-fired power plants due to come online over the next decade. These new contracts are expected to offer more competitive rates that could lead to more coal-to-gas switching in the future.