Chinese LNG receipts in March fell once more m/m, to 3.25 Mt, but were still 1.26 Mt (63%) higher y/y. In Q1 18, LNG takes totalled 12.4 Mt, the highest on record and up by a hefty 4.6 Mt (61%) y/y. Imports of pipeline gas also grew, to 2.7 Mt, a y/y increase of 0.4 Mt (18%). This was driven by strong demand as well as a small 0.06 bcm (0.4%) y/y fall in domestic output to 13.52 bcm. Over Q1 18, domestic production was up by 1 bcm (3%) y/y, which is a much lower rate of growth in than that over the last two years, when production came in 8-9% higher y/y.
The gas output slowdown was also steep compared to producer guidance, which has pointed to production growth rates of around 6% y/y in 2018. PetroChina may have accounted for some of the weakness as it is starting to divert gas from fields into storage. CNOOC, however, has reported a 0.23 bcm (14%) y/y increase in domestic production in Q1 18, to 2.01 bcm.
LNG takes largely came from regular suppliers, with flows from Qatar increasing the most y/y, by 0.69 Mt (333%) to 0.90 Mt, despite a high realised price of 9.75 $/mmbtu. Australian-sourced LNG stood at 1.22 Mt, a 0.08 Mt y/y hike at an average price of 7.91 $/mmbtu. China resumed deliveries from Indonesia, taking 0.21 Mt in March, having taken no cargoes in March last year. The Indonesian LNG helped replace imports from Papua New Guinea, which provided no gas given the unplanned outage at PNG LNG following an earthquake. China also sourced other higher-priced spot cargoes from less conventional sources, with Nigeria and Angola both providing 0.13 Mt (vs zero in March 2017), pricing at 9.21 $/mmbtu and 10.91 $/mmbtu respectively.
Pipeline gas imports were led by Kazakhstan (+0.13 Mt y/y at 0.17 Mt) and Uzbekistan (+0.14 Mt y/y at 0.14 Mt). Turkmen supplies were 0.08 Mt higher y/y at 2.11 Mt, while imports from Myanmar expanded by 0.05 Mt to 0.28 Mt.
With China’s peak winter demand over, thoughts are turning to the summer. April temperatures have been well above normal and are forecast to stay that way through to early May. While this should support higher power demand, the big additions of wind power capacity last year (some 15 GW) have been making their presence felt, with renewables generation rising more than thermal generation to meet higher demand. Also, while hydro generation was lower in March, hydro reservoir levels as of 16 April stood 1% lower m/m but 11.3% higher y/y, which should support hydro generation in the peak summer months.
Even if a warm summer does not drive much additional gas demand, underlying gas demand growth will remain strong and the majors’ plans to fill storage between March and June will support buying. On 6 April, PetroChina reportedly began gas injections into its Xiangguosi facility in Chongqing municipality. The company plans to inject 1.72 bcm of gas from local gas fields into the facility, aiming to supply 1.65 bcm of gas from the site next winter. Meanwhile, despite guiding toward lower domestic production growth, the majors are focussing on ways to limit winter shortages. PetroChina is planning to add 1.2 bcm of supply capacity at its Kelasu field in northwest Xinjiang and start operations at 12 new wells at the field, feeding into the west-east pipeline network.
Overall this year, demand growth is set to remain supported as the Chinese government extended its coal-to-gas switching programme through 2018. The plan is to phase out coal-fired residential heating systems and small coal-fired industrial boilers in 4 million households and industrial plants this year, slightly up on the 3.94 million users converted in 2017.
LNG imports will therefore remain strong and peak winter demand in North East China will still require additional regas infrastructure. This year’s additions are expected to be as high as 10 Mtpa (excluding Tianjin, which has already started commercial operations). ENN’s 3 Mtpa Zhoushan terminal is expected to start receiving cargoes in June, Guanghui Energy is expanding its 1 Mtpa Qidong terminal, while CNOOC’s 4 Mtpa Shenzhen Diefu terminal is still expected to start this year. If any of these projects are delayed, then some of the peak demand growth we expect could be curtailed.
With underlying demand and import infrastructure both expanding, we expect Chinese gas demand growth to remain strong in 2018. We forecast that LNG imports will be higher y/y by 1.9 Mt in Q2 18 and 2.0 Mt higher y/y in Q3 18. Over all of 2018, we expect Chinese LNG imports to grow by 11.2 Mt y/y, unchanged on our previous forecast. But, if domestic production remains as weak as in Q1 18—which is not our base case—the gap will need to be filled with LNG. Overall, we still think the risk of acute winter shortages remains high this year, even if Sinopec expects the market to be better managed. A strong coal-to-gas switching programme suggests that the peak winter market in North East China is again going to be tight. LNG imports could be curtailed by limitations on regas capacity in the North—a gap that companies are eager to plug. While this year’s new terminals are coming online in the Shanghai area and further south, there is capacity to transport it by trucks to end-users, so we expect high utilisation from these new terminals as well. We expect a further 8.9 Mt in incremental LNG imports in 2019.