The combination of a macroeconomic slowdown, the lack of a binding target on coal-to-gas switching, and less supportive weather continues to drag on Chinese natural gas demand growth, colouring gas market expectations. While demand is disappointing to the downside, domestic supply growth continues to overperform, limiting total growth in imports to just 0.13 Mt y/y. While LNG takes were up by 0.59 Mt (15%) y/y at 4.53 Mt, that was buoyed by the third consecutive month of reductions in pipeline flows (June was lower by 0.46 Mt y/y, -14%). Chinese Q3 19 LNG buying is likely to stay muted, as a quick resolution to the trade war looks unlikely and the next regas capacity additions are not expected until Q4 19. With LNG takes expected up by only 9.1 Mt y/y in 2019—reduced again, from 10 Mt y/y last month, on the narrowing call on gas imports—spare regas capacity is tightening. 2020 LNG import growth could drop again y/y.
Chinese LNG imports in June reached 4.53 Mt, inching up from 4.43 Mt in May and up y/y by 0.59 Mt (15%). Growth in total gas imports has continued to shrink through Q2 19, with demand disappointing to the downside on the combination of unsupportive weather, the slowdown in the macroeconomy, and the lack of a binding target for the coal-to-gas switch in the industrial sectors.
Indicative natural gas demand continues to soften; the latest data sets apparent May demand at 24.5 bcm, a 2.43 bcm (11% y/y) increase that compares against the average monthly growth rate of 20% y/y in summer 2018, meaning a slowing rather than a cessation of growth. With the prime reasons for that slowdown still featuring in Q3 19, we expect underlying Chinese gas demand to come in 7.4 bcm higher. Given this, we are forecasting that 2019 end user gas demand will clock growth of 30.9 bcm y/y, down from 2018’s high watermark growth of 36.6 bcm y/y.
Macroeconomic picture continues to slowdown
June macroeconomic data confirmed the ongoing slowdown in the Chinese economy, although a number of indicators highlighted strength in domestic consumption. Still, the economy is set to remain sluggish in the next few months as Beijing only gradually steps up its support measures. Q2 19 GDP growth came in at 6.2%, slowing from 6.4% in Q1 19 and its weakest pace since 1992.
The official PMI stood at 49.4 in June, unchanged from May—a second consecutive contraction. Most of the weakness in Q2 19 GDP came from exports, which contracted in June, and from declines in housing construction as growth in property investment dipped to 10.9% in H1 19, compared with 11.2% in the year-to-May. Yet retail sales perked up, increasing by 9.8% y/y in June from 8.6% y/y in May, while fixed asset investments for H1 19 ticked up by 5.8% y/y, rising from 5.6% y/y in the year-to-May. This came just as industrial production grew by 6.2% y/y in June, a step up from May’s 5% y/y rise.
There have been rumours that the US and China could resume in-person trade talks the week of 29 July. While both sides are interested, the path toward a resumption (let alone progress) is likely to be long. Even the June bump in credit should not be taken as a sign that Beijing is panicking and hitting the stimulus button. Aggregate financing was up by 10.9% y/y from 10.6% in May, the biggest print since June 2018, but new bank loan growth fell to 13.2% y/y from 13.4% in May, the lowest print so far this year, suggesting that bank lending continues to decelerate despite the government’s efforts. The jump in overall credit is therefore due to the slowing contraction in shadow banking, with trust loan growth down by 9.9% y/y in June compared to a 10.4% y/y fall in May. This could be a temporary reprieve; liquidity tends to tighten in June, when banks turn to short-term financing to pass regulatory inspections. The most definitive sign of a policy change, if the leadership opts for one, will come at the end of the summer, after the leadership’s annual summer retreat in Beidaihe and a Politburo meeting later this month.
Infrastructure a potential limit
The steady increase of LNG imports has started to strain some of the LNG infrastructure, so new regas capacity is important again. So far in 2019, just two facilities with a combined capacity of 1.7 Mtpa have been commissioned. For the remainder of 2019, we are only tracking another 3 Mtpa of capacity expansions, which we expect to be in place for the coming winter. Both are being developed by independents, with the 1 Mtpa Chaozhou (Sinoenergy) and the 2 Mtpa Jiangyin (Hanas) plants adding a combined 0.25 Mtpm of capacity.
For 2020, project delays mean that scheduled additions of Chinese regas have fallen from 25.4 Mtpa to 16.5 Mtpa. All of that capacity is only expected to be online for Q4 20. For the first three quarters of 2020, the Chinese market will be facing an annualised spare capacity in its regas facilities of 8–10 Mtpa for any growth. At the high end, that suggests a maximum of 7.5 Mt of incremental growth in LNG imports over the first three quarters would take China to its capacity constraints. Given the need for maintenance and the low likelihood of running all projects at maximum capacity, we only see China delivering 8.5 Mt of incremental LNG growth over all of 2020. For 2021, imports should be bolstered by the additional capacity added in 2020 and 9.5 Mtpa of new terminals expected to come online that year. However, given our expected import growth of 11.6 Mt y/y in 2021, that suggests further infrastructure limits to import growth in 2022 without new projects starting construction.
To make 2022 matters more complicated, Hoegh announced that its 6.0 Mtpa FSRU Esperanza, which China National Offshore Oil Corporation (CNOOC) has under a three-year charter at Tianjin, has been promised to the AGL import project in Victoria, Australia for the first half of 2022. CNOOC will need to find a replacement vessel, or its LNG imports into Tianjin will contract.
Weakness in pipelines – sustainable?
One of the notable features of the Chinese balance this year is that while LNG takes continue to grow, pipeline imports from the west have consistently dropped off. Total pipelines recorded their third consecutive y/y drop at 2.87 Mt (-0.46 Mt, -14%). While the low prevailing spread between the prices being paid at the respective borders for pipeline gas and LNG will have helped shift preferences, the replacement of pipeline imports with LNG has been a key development in maintaining the positive y/y run of LNG import levels.
Still, 1 December will see the long-awaited start of Russian gas flows to China through the 38 bcm/y Power of Siberia pipeline. With Gazprom committed to starting gas flows to China come 1 December, last month saw reports that Gazprom was beginning start-up operations, with filling to begin in September. On the Chinese side, China has completed the northern 728-km section of the 3,968-km China–Russia pipeline in the northeast province of Heilongjiang that connects with the Russian pipeline and will take it to demand centres in the Northeast.
Reports in early July said that CNPC has started to construct the 1,110-km middle section that runs from Changling, Jilin and ends at Yongqing, Hebei, taking gas to the high-demand Tianjin-Beijing area. While the pipeline’s middle section is only set for completion by October 2020, we think Chinese imports of Russian gas will be limited to 5 bcm in 2020 anyway given production constraints on the Russian side, with all of that gas staying in the northern region of Heilongjiang, adjacent to the Russian border. The more southern sections of the pipeline that will eventually run to Shanghai are only scheduled for completion around 2024.
Power seeing some late-summer heat
Gas-fired power generation over H1 19 did not see any material growth, as power generation grew by a modest 3.3% y/y and most of that growth was met by much stronger hydro generation, which was up by 11.8% y/y. Thermal generation could see some improvement over July, given a period of extreme heat in the week of 15 July, but overall July is still milder by around 9% y/y, and hydro should still be strong. We expect to see little incremental support to gas demand from the power sector this summer.