The year is ending with the JKM prices slipping despite NE Asian temperatures falling from a mild November and early December to a more normal winter level. A little further out, the TTF has seen support from forecasts suggesting a cold end to the winter, allowing the JKM-TTF spread to dip below 1.0 $/mmbtu for the front-month contract (Feb-19) for the first time since May. As a result, more LNG y/y should remain in the Atlantic basin, with NE US being a surprising, albeit small, source of LNG demand. The most unusual development has been Cove Point both exporting and importing LNG—the latter a sign that there are quite a few spare cargoes around. Despite the recent market softening, three long-term supply deals were announced this week, all involving US-sourced LNG.
Colder weather but lower prices
Northeast Asia has seen a bout of colder-than-normal weather over the last week or so, while the 14-day forecasts are for much more normal winter weather. But despite this, the JKM Feb-19 contract closed yesterday (20 December) down by 20 cents w/w at 9.1 $/mmbtu. This softness has been driven by the lack of any real appetite for spot cargoes among NE Asian buyers and deepened by the weakness in oil markets, with M+1 Brent closing at $54 yesterday, down by $7 per barrel w/w. The JKM did not follow oil all the way down, however, with the hub’s dip somewhat limited by a TTF finding support from strong carbon and forecasts that European weather could have a very cold end over February–March. As a result, the prompt JKM-TTF spread fell below 1 $/mmbtu for the first time since May. With only a couple of weeks of Feb-19 buying left, there has been little sign of the winter squeeze that the JKM curve priced in over the summer.
Still, as we had expected, there were signs of tension in the Chinese market at the first sign of cold weather. During the cold spell that blew in from 10 December onwards, Shanghai’s natural gas consumption was reported at a record, with daily highs coming in at 40 mcm/d. CNOOC Gas & Power announced that it had supplied a record 205 mcm/d of gas nationally on the coldest day, up from its peak-day high of 173 mcm/d last year. Domestic delivered LNG prices (ex-factory gate) quoted on the Shanghai exchange posted a 26% increase from 6–20 December. While the bitter cold episode was short-lived, we still think the Chinese gas market is going to be tight in the coming months, even assuming that prevailing weather is no colder than normal. However, we do not expect that tightness to spill over into the global LNG market, as we think China has already bought every cargo it can physically import for the peak winter months.
US Northeast: LNG supply or demand?
The Cove Point facility has been busy, taking 0.75 bcf/d in feedgas (100% capacity) every day since 1 November. But it remains to be seen how flows to Cove Point will react to a true cold-weather event, given that during January’s ‘snow bomb’ local prices surged above $125/mmbtu. Both GAIL and the facility’s other offtaker, Sumitomo, have firm purchase agreements with Appalachian producers for near 0.3 bcf/d each. As such, both have supply that can be liquified or sold into the Transco Zone 5 (TZ5) hub when global arbs close. With TZ5 cash prices having the potential to peak significantly over the rest of winter, netbacks could be higher selling gas into TZ5 than exporting gas as LNG. So far this heating season, TZ5 has hit a high of just above $6.00/mmbtu, on 4 December—not enough to entice either offtaker to push gas to TZ5 given around $3.5/mmbtu liquefaction and shipping costs to Asia. Delivered LNG prices in India and Japan stayed above $10.00/mmbtu for peak winter contracts through November and remain above $9/mmbtu for Feb-19. LNG exports could ebb in the event of an extreme cold period.
In a less expected development, Cove Point is also serving as an import terminal for BP, Equinor, and Shell, all of which have retained regas capacity at the facility. Given all three are portfolio players, they have considerable freedom in sourcing and placing cargoes. BP unloaded a cargo of Trinidadian-sourced LNG at Cove Point on 9 December and Kpler data point to two tankers loaded by Shell in Nigeria due to arrive in Maryland before the end of the year. The importers can hold gas at Cove Point for up to 120 days, which as of now would mean the gas could be held until mid-April. BP and Shell are likely eyeing that supply for extreme cold weather events in the Northeast, when TZ5 prices are expected to surge to levels well above what will be offered anywhere else globally. The appetite for LNG cargoes in NE US markets, also seen at Canaport and Everett, is an outlier in a global market that has seen a very soft Q4 18 for demand.
In a rush to get 2018 business completed, several long-term supply deals were announced in the last week. Cheniere announced a 20-year 1.1 Mtpa LNG SPA with Petronas, with the LNG to be sourced from the proposed 4.5 Mtpa Sabine Pass T6 project—aiding Cheniere’s move towards an FID. Second, Poland’s PGNiG agreed to buy 2 Mtpa of LNG for 20 years from Sempra’s 11 Mtpa Port Arthur LNG terminal project, which is set to start up in 2023. PGNiG now has some 7.45 Mtpa of LNG under contract for delivery from 2023. The deal is Port Arthur LNG’s first firm LNG offtake agreement and it has a memorandum of understanding as well with Kogas. While the project is targeting an FID in 2019, that seems very ambitious given that most of the LNG capacity from the project has still yet to be sealed under a supply agreement with buyers. Third, RWE agreed a two-year deal (Q4 20–Q2 22) for an undisclosed volume of LNG supply from Woodside, to be sourced from Woodside’s 0.85 Mtpa contract with Cheniere’s Corpus Christi facility. Woodside agreed last year to deliver up to 12 cargoes of LNG between April 2018 and March 2020 to the German utility, so this contract is largely a term extension to the earlier deal.
On the less positive side of LNG supply developments, ExxonMobil has finally pulled the plug on it stalled 15 Mtpa West Coast Canada (WCC) LNG export project, located in northern British Columbia. Although the project had been in the permitting stage since 2015, no major documents had been filed since 2016 and the withdrawal from the project comes as no surprise. ExxonMobil is involved in a large number of far more advanced LNG supply projects, including the two-train, 8 Mtpa expansion at PNG LNG (Papua New Guinea), the 15 Mtpa Golden Pass (US), the 10 Mtpa Mozambique Mamba, and possibly some of the 33 Mtpa expansion in Qatar. In essence, the ExxonMobil announcement about WCC LNG simply reinforces our opinion that, with the exception of maybe one or two small projects, only the 14 Mtpa LNG Canada project, which received a green-light FID earlier this year, is likely to go ahead in Western Canada.