Floating storage returns

Published at 20:19 16 Jul 2019 by . Last edited 11:18 22 Aug 2019.

Summer global balances are now all about sniffing out available gas storage capacity. With European storage filling rapidly, floating cargoes as storage could become more of a focus. The Henry Hub-TTF arb for Sep-19 and Oct-19 contracts are open on paper once more, and our reference case assumes no US LNG trains will be shut in this injection season as cargoes will likely have been hedged previously, meaning a marked reduction in US LNG exports is unlikely. We do see a risk of Chinese LNG demand growth further easing, while infrastructure additions have helped boost demand in South Asia.

We expect European storage sites to fill in September, so the global gas markets will need to find somewhere else to put the gas. That storage space could come from the US, floating gas storage or, more unusually, Ukraine. The y/y storage surplus in Europe stood at 0.82 tcf (23.4 bcm) on 13 July, and another 0.40 tcf of surplus still needs to be unwound by the end of the injection season, as we expect storage capacity will be full with a surplus of 0.42 tcf y/y. The European market needs to pare down the storage surplus at a rate of 3.7 bcf/d by the end of the injection season, but it has only managed 0.5 bcf/d to date.

The steep contango in the JKM and TTF curves could mean renewed focus on putting gas into floating storage. The TTF Aug-19–Nov-19 spread closed at -$2.11/mmbtu on 12 July and the cross-basin TTF Aug-19 to JKM Nov-19 spread was -$2.39/mmbtu. With 90-day floating storage likely to cost around $1.95/mmbtu, either of these contango trades look profitable. This seasonal play could lead to floating cargoes being used as storage to be sold into either the JKM or Europe. There may also be a drop in feedgas to US terminals, which would reduce the total cargoes destined for the export market, without an outright shut in of a train. Our reference case remains that we do not expect any US LNG trains to be shut in this injection season.

In terms of Ukrainian storage, Naftogaz announced that it was targeting 0.71 tcf in storage at the end of injection season, some 0.11 tcf more y/y. However, that leaves a 0.35 tcf gap between storage capacity and the Naftogaz storage target, which could be inviting for European gas participants. For 2019, Ukrtransgaz launched a ‘custom warehouse’ service for its gas storage capacity for international parties, allowing them to store gas for 1,095 days without paying customs duties provided the stored gas is exported. Given Ukrtransgaz-published tariffs, we estimate that the cost of entering gas to Ukraine, injecting it, storing it for 180 days, withdrawing it and then exporting it would be around $2.40/mmbtu (€7/MWh).

Another tool of market balance we expected this summer is a fall in nominations for Russian gas. We still think that has happened, but we note that Gazprom has offset most of the drop in flows under long-term contracts with short-term sales on the Electronic Sales Platform. But at what price does Gazprom pull back from incremental sales and allow the decline in its nominations to lead to materially lower flows? Russian flows start to be loss-making against variable costs at prices of $3.00/mmbtu, according to our calculations. The TTF D+1 approached that point in late June at $3.05/mmbtu, although the TTF curve has seen flat price support since then on rising coal and EU carbon prices. The TTF D+1 closed at $4.31/mmbtu on 12 July.

Changes to the Norwegian summer maintenance schedule have been bouncing around, but the latest iteration provided some bullish news for the market. Gassco revised scheduled Q3 19 production and processing capacity constraints to 195 bcf, compared to 188 bcf previously. We still think that Norwegian production will be lower y/y by 124-141 bcf over Q3 19. If the decline is at the lower end of that range, that is just another bearish signifier for a market with room to fall.

The JKM-TTF spreads widened across the curve, which means the Q3 19 contracts are staying firmly at levels that keep US flows going to Asia. However, the strength of Chinese demand has come off significantly. Even though China’s LNG imports were up by 0.5 bcf (7%) y/y in May, this was the weakest monthly growth since 2016. That growth was partially supported by a reduction in pipeline imports (-0.2 bcf y/y), which highlights how the Chinese economic slowdown, exacerbated by the trade war, has delayed China’s dash to gas. Still, we expect Chinese LNG imports to grow by 4.5 bcf bcf y/y in Q3 19, although the risks now seem to be to the downside.

The only area of demand growth consistent over Q2 19 was South Asia, and we expect LNG imports in that region to be up by 4.8 bcf y/y in Q3 19. South Asia is one of the most price-sensitive regions for LNG, and the sub-$6/mmbtu pricing predominant in summer prices since mid-March is starting to be felt on the demand side. Indian growth of 1.2 bcf y/y across Q2 19 has been helped by some infrastructure developments, with the imminent commissioning of the 3.9 bcf/y Dahej expansion and the long-awaited completion of the Kochi downstream pipeline both suggesting further growth opportunities during the rest of the year.

Fig 1: Aug-19-Nov-19 spreads, $/mmbtu Fig 2: European gas storage, tcf
Source: CME, Energy Aspects Source: GIE, system operators, Energy Aspects


Fig 3: Russian flows to the EU, bcf Fig 4: Chinese production and imports, bcf
Source: Gazprom Export, Energy Aspects Source: China Customs, Energy Aspects

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