Every year in January, due to the Lunar New Year, Chinese official data releases are limited to import and export figures issued by customs. As such, January data for domestic production and power generation has yet to be released. The National Bureau of Statistics (NBS) typically publishes combined January-February data in March.
China’s gas imports hit a fresh record of 9.8 Mt in January, higher y/y by 2.1 Mt (27%). LNG imports leapt to 6.58 Mt (+1.43 Mt y/y, 28%), another record high, and pipeline flows rose to 3.23 Mt (+0.64 Mt y/y, 24%). While underlying demand growth remains strong, a milder-than-normal winter and record supplies have led PetroChina and CNOOC to resell LNG cargoes recently, which will limit February import levels. With stock levels expected to end the winter at high levels given the mild weather, Chinese spot buying of LNG is likely to ease off in the coming months. But while supply was in focus in 2018 and infrastructure constraints will increasingly be an issue, 2019 demand growth cannot be taken for granted as industrial gas consumption could soften due to a slowing economy and the government’s environmental agenda. Still, any downside to demand growth should be limited by regional authorities issuing their own fuel-switching and cost-cutting targets.
A strong import push ahead of the Lunar New Year
LNG imports hit 6.58 Mt in January, another record high, up m/m by 0.29 Mt and y/y by a huge 1.43 Mt (28%) off an already high base. Chinese importers' heavy LNG buying in Q3 18—aimed at avoiding a supply shortfall during the winter—continued to be reflected in the January import numbers, with another strong import push ahead of the week-long Lunar New Year holiday (which was in early February this year). In addition, January deliveries were supported by the start of CNOOC’s 0.60 Mtpa Fangchenggang transfer terminal in Guangxi province on 10 January 2019. The Fangchenggang facility will not import LNG directly, but it will allow CNOOC’s 3 Mtpa Hainan terminal to take more volumes and boost sendout to local markets.
Pipe flows in January rose m/m by 0.29 Mt to hit 3.23 Mt, higher y/y by 0.64 Mt (24%). Despite a short and unexplained disruption in Turkmen supplies, imports from the country reached 2.25 Mt, their highest since April 2018 (+0.45 Mt y/y), while flows from Uzbekistan rose by 0.16 Mt y/y.
While the Turkmen cut caused speculative price rises in early January, the overall uptick in pipeline flows through the month, combined with still-strong LNG imports, allowed domestic prices to ease down to around 12 $/mmbtu from 14 $/mmbtu on average in December. Going forward, we expect Turkmen pipeline flows to grow as a new field, operated by CNPC’s Amu Darya unit in Turkmenistan, came online on 10 January and added 4.6 mcm/d in capacity from the East Bagtyyarlyk B block. Back in China, PetroChina reopened a few wells in the Tarim basin in January, allowing it to inject an additional 3.2 mcm/d of gas into China’s West-East pipeline system. Across 2018, output from the Tarim basin was up by 5% y/y at 26.6 bcm.
In terms of LNG, Australian supplies rose by a strong 0.53 Mt y/y to 2.33 Mt, while flows from Malaysia (+0.33 Mt y/y to 0.83 Mt), Indonesia (+0.14 Mt y/y to 0.48 Mt), and Qatar (+0.21 Mt y/y to 1.4 Mt) also increased. Supplies from Equatorial Guinea and Nigeria surged, although from a very low base, to 0.14 Mt (+0.14 Mt y/y) and 0.39 Mt (+0.20 Mt y/y) respectively, more than offsetting lower arrivals from Angola (-0.13 Mt y/y), PNG (-0.16 Mt y/y); Trinidad (-0.12 Mt y/y).
A question of demand
While underlying demand growth has remained strong, balances have been helped by a milder-than-normal winter, with January HDDs coming in 8% below normal and 12% lower y/y. Muted res-com demand suggests that LNG imports have exceeded demand, keeping LNG stocks high. Kpler cargo-tracking data show that CNOOC’s Neo Energy tanker discharged in Japan on 23 January, having acted as emergency floating storage for China since November 2018. Meanwhile, PetroChina has been reselling LNG cargoes from Yamal on the European market, with meek Asian heating demand this winter keeping Russian volumes in Europe.
In addition, Chinese buyers have likely seen gas demand soften in February given that industrial users are typically offline for the week-long festivities around the Lunar New Year. Forecast HDDs for the second half of February are some 9% lower than normal and 2% lower y/y, which should continue to help keep res-com demand in check. As a result, the disruption to industrial users that was so prevalent last year has not been seen this year. With gas stock levels likely staying high and the prospect of slowing industrial gas demand, LNG import growth is likely to ease as fewer spot LNG purchases are made in the coming months. Kpler data place February LNG imports at 4.3 Mt, a m/m decline of 2.5 Mt but still a y/y increase of 0.6 Mt.
How much will the slowing economy weigh on gas demand growth?
While 2018 was dominated by supply concerns, demand is the key question in 2019. China’s economic slowdown could start weighing on industrial consumption, thereby softening gas demand growth. Moreover, the government has yet to issue its 2019 coal-to-gas switching target as economic concerns could lead the government to ease the pace of fuel switching this year.
We have reduced our outlook for 2019 gas demand growth from 37 bcm y/y (in line with 2018 growth) to 32 bcm. This is due to our expectations that industrial demand growth will soften, as the coal-to-gas switch is likely to slow, and res-com demand growth will be more muted following a mild start to the year. Still, 32 bcm y/y growth is still substantial and reflects Beijing’s introduction of support measures for industry—including tax breaks and larger credit facilities—in order to cushion the impact of the US-China trade spat. Recent news from ongoing US-China talks has been positive, but whether a deal would delay additional tariffs or remove them is unclear. A final deal would include higher imports of US commodities, including LNG, but details are scant.
China’s import infrastructure put to the test in 2019
Even with Chinese demand growth revised down to 32 bcm, the ability of supplies to meet this number is questionable. We expect domestic supply to rise by 10–12 bcm y/y. China’s Shanxi province plans to increase the production of coal bed methane (CBM) by 0.9 bcm y/y in 2019 (from a total of 5.7 bcm in 2018). The province has authorised 10 major CBM projects this year, which will add 2 bcm/y to the annual output capacity when all the projects come online.
We also note that the Chinese majors are still focussing on gas production. CNOOC announced that it has made a significant 100 bcm natural gas discovery in the Bohai Gulf basin, reportedly the largest in the basin for 50 years. While this could support plateau production of 5–7 bcm/y depending on production plans, we do not expect that gas to show up in balances until 2021.
We also expect pipeline imports growth to be capped at 6–8 bcm y/y on capacity constraints, leaving 12–16 bcm of incremental demand to be filled with LNG. Despite Gazprom’s recent announcement that its Power of Siberia gas pipeline is set to start delivering gas to China early, this will still not be until 1 December 2019. As such, material gas flow through this pipeline is only likely to be seen from 2020, with flows ranging from 5–10 bcm that year.
China has only 5 Mtpa of new regas terminals planned to come online in 2019, so it will find it hard to take 15 bcm (11 Mt) more LNG without pushing utilisation rates (at least at some terminals) consistently above nameplate capacity.
Provinces are doin’ it for themselves
Meanwhile, Chinese provinces remain committed to boosting gas consumption locally. In late December, Guangdong province (which consumed an estimated 20 bcm of gas in 2018) laid out six policy priorities to encourage gas use including encouraging private companies to invest in regas terminals and storage, improving third-party access to the local midstream, and reducing local pipeline transportation costs. From 1 July 2018, Guangdong cut pipeline costs by 0.15 yuan/m3 for gas-fired power plants and by 0.20 yuan/m3 for industrial users (with transport costs on the West-East pipe estimated at 2.1 yuan/m3) and has pledged further midstream cost cuts.
Further policies include capping city-gas companies’ profits on all pipeline gas sales to 1 yuan/m3, supporting the construction of new pipeline and interconnection projects and allowing all companies to use local midstream infrastructure, mandating storage levels (natural gas suppliers will be required to store 10% of their annual sales volumes, while cities will be required to store three days’ natural gas consumption), and supporting the coal-to-gas switch in large cities and in major industries.
While the guidelines remain vague, additional details will be published over time and may vary within the province, but the goal remains to increase gas use and cut pipeline costs. Guangdong authorities have long been trying to negotiate pipeline tariff reductions with CNPC, given that Guangdong has some of the highest city-gate prices in the country, and while these talks seem to have failed, the province is seeking alternative ways to keep costs down for end-users.
The moves dovetail with a renewed push by the central government to form an independent pipeline company by hiving out the pipeline networks of the majors (mostly CNPC). While this has been in the works for years, our sources in Beijing suggest that the majors and the government are in advanced stages of preparations and looking to announce a new midstream entity in the coming months.