We expect Chinese LNG imports to again test the limits of the country’s regasification infrastructure this winter, capping y/y import gains. LNG imports have climbed substantially so far this year and were up by 0.7 Mt (18%) y/y in July, although growth eased from 1.0 Mt (32%) a year earlier. LNG import growth this winter will continue to be driven by aggregate demand growth exceeding domestic production increases, even though Chinese producers have boosted output substantially in 2019. New pipeline imports from the Power of Siberia project starting from December and higher storage withdrawals facilitated by Wen 23 may only offset some of the need for additional LNG.
Q4 19 imports to hit infrastructure buffers
We see Chinese LNG imports increasing to 18.7 Mt in Q4 19, a 1.9 Mt (11%) y/y rise. This would involve LNG imports testing maximum regasification capacity in November-December, which is a constraining factor on imports across this winter. The new forecast is a downward revision on our previous forecast of y/y growth of 2.1 Mt, with the change due to our expectation of delays to some of the new regasification capacity we previously expected to be online in Q4 19.
Our estimate of regasification capacity for China at the start of this winter is 74.0 Mtpa from 21 terminals, which is up from 71.5 Mtpa available at the start of October 2018. This includes the addition of 1.7 Mtpa of capacity through two projects in H1 19—at Fangchenggang and Fujian—and Shenzhen Gas starting imports through its own 0.8 Mtpa terminal earlier this month. The estimate does not include the new capacity expected at Chaozhou and Jiangyin, which have a combined capacity of 3 Mtpa and were previously targeted for start-up in Q4 19 but which will likely be pushed into 2020. The expectations of delays are due to financial difficulties at Chinese firm Sinoenergy, one of the main investors in both terminals.
Our forecasts for November and December suggest LNG imports will be above aggregate nameplate regasification capacity, a phenomenon we have seen over the last two winters. Adding storage tank capacity, LNG truck loadings, and other debottlenecking measures may boost offtake from China’s receiving terminals. Over winter 2018-19, this allowed for terminals in China’s high-demand northeast to operate on average around 30% over nameplate capacity during the peak months. Potential for further debottlenecking this year provides some upside to our LNG import estimates.
Gas demand still posting strong y/y gains
Aggregate Chinese gas demand should continue posting y/y gains over the rest of the year, at around 12% y/y. NDRC demand numbers have not yet been published for July, although aggregate supply is up by around 12% over the first seven months of the year. This year’s demand growth is down from 21% y/y over the same period in 2018. A continuation of that strong-but-more-moderate demand number for the remainder of the year would result in apparent demand in Q4 19—not counting storage movements—rising around 10 bcm, to 89.4 bcm. The current apparent growth comes despite the headwinds from the US-China trade war, which is curbing demand for Chinese exports and potentially softening industrial gas demand growth. US president Donald Trump last week proposed increasing sanctions on Chinese imports to 30% on 1 October, from 25% previously. While China is still targeting GDP growth of 6.0-6.5% this year, down from 6.6% a year earlier, the export-facing manufacturing sectors are the ones being hardest hit by the sanctions. The relative strength in end-user gas demand growth is testament to the still-strong expansion in the number of gas customers in the country.
China’s National Energy Administration (NEA) this month has urged provincial authorities to exercise caution in the pace of coal-to-gas boiler switching this year to reduce the risk of winter gas shortages, but we are still likely to see y/y demand gains from this programme. Authorities in Henan province earlier this month announced a target to switch 2 million households to gas from coal in 2019, which is up from 1.1 million in 2018. Private sector company ENN also reported significant increases in gas connections across all end-user sectors in H1 19, both from coal-to-gas switching and from new industrial consumers (see E-mail alert: ENN results reflect slowdown in Chinese end-user gas demand, but connections growth still strong, 23 August 2019).
Non-LNG sources insufficient to offset demand growth
Gains in production in China have been quicker so far this year than in recent years, and these increases have helped lower import growth. Production rises have averaged 10% y/y per month in January-July, with coalbed methane output providing consistent growth over that period. Similar gains in winter 2019-20 would result in Q4 19 production of 49 bcm, up by 5.1 bcm y/y, only partly offsetting increases in aggregate demand and leaving an import gap of some 4.9 bcm.
How the import gap is filled in Q4 19 will be coloured by the LNG regas constraints, which we expect will limit LNG import growth to 2.5 bcm y/y. This points to a need to increase the net call on storage over the quarter and to curb the slowdown in deliveries through the West-East pipelines that have been seen since April. Total pipeline imports were again lower y/y, by 0.3 bcm at 4.15 bcm in July, with imports from Turkmenistan and Uzbekistan both being particularly low in recent months, which has helped to support LNG imports over the last two quarters. Pipeline imports may need to increase by 2.3 bcm y/y to balance the market in Q4 19.
Some of the increase in pipeline imports will likely come from Gazprom’s 38 bcm/y Power of Siberia project, which is set to start from 1 December. We expect the pipeline to deliver 0.4 bcm in December, based on the 5 bcm that we expect Gazprom to send through the line in 2020. The export project appears on schedule, with the 1.2 trillion cubic metre Chayandinskoye field in Russia’s Yakutia province being connected to the pipeline earlier this month. The field itself is only scheduled to reach its production plateau of 25 bcm/y in 2024 and Gazprom does not expect Power of Siberia exports to hit 38 bcm/y until 2025.
We expect storage withdrawals to continue offering little capacity to curb winter import demand. Withdrawals in any event are likely to be concentrated in the peak demand periods in January-February. Sinopec’s Wen 23 storage site, which started full operations earlier this month, is only set to provide 0.7 bcm of additional supply this winter and this is likely to be concentrated in Q1 20. Insufficient cushion gas injections in recent years have left most of China’s storage sites operating well below nameplate capacity.
|China balance forecasts, bcm|
Note: Q1’ 18 to Q2’ 19 figures are actuals. A positive implied storage number indicates injections into storage.