Page 7 - GLNG Week 50

GLNG COMMENTARY GLNG
Transportation costs
In a new analysis of the Chinese gas market this week, energy consultancy Wood Mackenzie argued that the cost of transporting Power of Siberia gas beyond China’s north-eastern mar- kets had removed its competitive edge.
Wood Mackenzie’s vice-chairman of Asia-Pacific energy, Gavin Thompson, wrote on December 17 that tariffs on Siberian gas supplies pumped to north-eastern cities such as Shenyang would amount to $1 per million British thermal units ($27.66 per 1,000 cubic metres). Transport tariffs on supplies to destinations as far afield as Shanghai would, however, rise to $3 per mmBtu ($82.98 per 1,000 cubic metres). Such a jump would drastically reduce the competitiveness of the Russian piped gas versus more flexible LNG.
Thompson said: “The world is awash with dirt cheap LNG right now. This will continue over the next couple of years as more projects come on stream. In addition, China is rapidly expanding regas capacity and pushing third-party access policies to encourage more participants.”
As such, the analyst anticipates that north- east China and the northern Beijing-Tianjin-He- bei (BTH) and Shandong markets will soak up as much as 30 bcm per year of Russian gas, leaving only 8-10 bcm to reach southern markets.
Indeed, China’s energy planners seem none too concerned about the rise in piped gas imports from Russia, given that new LNG import capacity for the BTH region is in the final planning stages.
The Asian Infrastructure Investment Bank (AIIB) has agreed to provide a long-term $500mn loan for a new LNG terminal in Tian- jin, the bank said on December 17. The loan has a 20-year maturity and a five-year grace period. The 5mn tonne per year (tpy) terminal, which is slated for launch in five years, has an estimated
price tag of $1.9bn, of which state-run developer Beijing Gas Group (BGG) will cover $834mn and Beijing’s municipal government will invest $572mn.
The AIIB has said the terminal will displace 11.9mn tpy of coal consumption in the region. The central government has long seen gas as a means of reducing consumption of coal, spear-heading coal to gas conversion campaigns and giving its blessing to a raft of publicly and privately funded LNG terminals. The problem for China, however, remains coal’s competitive edge.
What next
China has built 42,900 MW of new coal-fired power generation capacity since the start of 2018, and has another 121,000 MW in development.
Authorities also approved 40 new coal mines in the first three quarters of 2019, which will add nearly 200mn tpy of capacity. This is up from the 25mn tpy of capacity approved in the whole of last year. Reuters reported at the start of the month that even if state-owned utilities managed to follow through on plans to cut a third of their older, less-efficient coal-fired capacity, these cuts would just be offset by new capacity additions.
The problem for China is its ongoing slow- down, which is forcing the government to look for ways to stimulate the economy. The country’s GDP is on track to decelerate to 6.1% in 2019, which would be its third annual decline in a row. Worse still is the fact that growth is widely pro- jected to fall further still in 2020.
The central government has tended to favour economic growth over other domestic policies in the past and it seems likely that coal, which is a cheaper fuel source, will likely remain in hot demand as the country grapples with its new economic reality.™
New LNG import capacity for the BTH region is in the final planning stages.
China is rapidly expanding regas capacity and pushing third-party access policies to encourage more participants.
Week 50 19•December•2019 w w w . N E W S B A S E . c o m
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