The next five years around 150 million tonnes per annum (Mtpa) in production capacity will come on stream, mainly in Australia and the US, in addition to the existing 300 Mtpa. The question is, where will all this gas go and how much can the various regions absorb.
“We are expecting an LNG tidal wave”, commented one of the speakers at the 18th LNG conference in Perth last month. This event was attended by a few thousand people from the LNG industry, and discussed the significance of the fact that over the next five years around 150 million tonnes per annum (Mtpa) in production capacity will come on stream, mainly in Australia and the US, in addition to the existing 300 Mtpa. The first few shiploads of these increases have gradually been reaching the market in the last few months. The question is, where will all this gas go and how much can the various regions absorb.
The market players saw this new supply of LNG coming; after all, the investment decisions for the construction of the new liquefaction terminals were taken years ago, and most projects are running more or less on schedule, although there have often been some delays and in some cases significant cost overruns. But the market players seem surprised at the extent of the oversupply. Why is this? In the first place, demand for gas in the two largest LNG-importing countries, Japan and South Korea, has declined rather than growing slightly as had been expected. South Korean government policy has shifted towards a more diversified energy mix, with a larger role for renewable energy sources and coal and consequently a downgrading of LNG, in response to the high energy import bills which the country has been facing for some years.
Japan has cautiously started to reopen its nuclear reactors which had been closed down following the Fukishama nuclear disaster, so that demand for natural gas is expected to fall further in the future. In addition, the anticipated strong growth in demand for LNG from China has not (yet) taken place. There is also the issue of how far the Chinese government wants to allow this demand to grow, as it will have a direct effect on China’s reliance on imports. Although there is growth in demand from other Asian countries such as India and Indonesia, it is not sufficient to achieve the expected growth in LNG demand.
Another event that affects the LNG market in Asia is the fall in the oil price and the associated price in many long-term LNG import contracts. This has led to Asian importers taking more LNG from their long-term import contracts than had been the case in the past. Combined with lower domestic demand, this led, for example, to the world’s largest LNG importer, Kogas, having purchased too much LNG at some times and having sold surplus on the spot market. The effect of all these developments on prices in the Asian spot market has been considerable. In two years, the price of LNG in Asia fell from $15 to 20 / Mbtu to around $4.40 / Mbtu. This price level is more or less the same as the price in Europe. It therefore seems that the capacity of the Asian market to absorb additional LNG in the short term is limited.
As a consequence of a long period of high LNG prices in Asia, the Asian premium, Europe has in recent years to some extent served as the overflow pit of the LNG market: wherever possible, LNG cargoes destined for Europe were sent to Asia, and only if this was not possible was LNG pushed onto the European market. The volumes remaining for Europe were, certainly after Fukushima, very limited. The low volumes meant that the operating times of many European LNG terminals were for years well below 20%. In 2015 there was the first sharp rise in LNG imports (around 15%) in a long time, bringing the level of LNG imports in absolute terms back to the level of around 2005. Europe’s imports of LNG in 2015 (almost 38 million tonnes) is moreover in strong contrast to the almost 200 Mtpa LNG import capacity which exists in the EU and which is also expected to rise significantly in the years to come.
What will happen to the tidal wave of 150 Mtpa that will be coming on the market in future years? Much of this volume has already been allocated for a long time under long-term contracts (10-20 years). This applies to about 80% of American volume and a similar proportion of Australian volume. This volume can be further broken down into a proportion contracted directly by end users, mainly from Asia, and a proportion contracted by portfolio players such as Shell (in the past also BG), Chevron etc. These portfolio players often try to convert this type of long-term contracts into medium-term contracts (3-5 years) with European and Asian customers. This means that approximately 30 Mtpa of the 150 Mtpa will be traded on the spot market. BG, which has now been taken over by Shell, has estimated that the proportion of the American volume of 65 Mtpa that will reach the market in the coming years and that has not yet been contracted amounts to approximately 15 Mtpa, or half of the remaining 20%. In addition to this new LNG from the US that will reach the spot market, there will be further spot volumes from parties that see their long-term contracts replaced by the new long-term contracts from the US or Australia. Countries such as Yemen, Trinidad & Tobago and Indonesia could be affected by this.
 In some of the Australian projects, the construction of that part of production capacity intended for the spot market was put on hold until market conditions pick up.
Eyes turn to Europe
Sluggish demand from Asia, and the fact that the market currently seems to be overcontracted, has made the LNG industry turn its eyes to Europe, and more specifically to the terminals in north-west Europe which are connected to a dense infrastructure serving large markets. But this is traditionally also Gazprom’s export market, and the Russians have shown in the oil market that they are prepared to fight to keep market share. It is likely that they will be prepared to do the same for their only significant gas export market (excluding LNG). This scenario has led the Financial Times to talk this spring of the possibility of a global gas price war being fought on European soil. Although the Russians certainly have the capacity to engage in such a war, a degree of caution is advisable when considering this scenario. Gazprom has allocated most of its volume on the European market in long-term contracts that are also in many cases partly spot-indexed, and the price times volume (P x V) sum will probably have to determine whether it is worth the trouble of pushing any (American) LNG volume out of the spot markets.
The capacity of the European market to absorb additional LNG is therefore limited by the long-term commitments (not only with the Russian firm Gazprom but also with producers from Norway, the Netherlands and Algeria). The big question is how the cost of LNG will stand in relation to the price of pipeline gas in Europe. For LNG from the US, for example, a cost of Henry Hub + $1.5 Mbtu is anticipated. The good thing is that at that price gas becomes more competitive compared to coal in the electricity sector. A switch from coal to gas would have a significant impact on the physical gas market and so on absorption capacity.
Bearing this in mind, it is therefore easy to understand why the LNG industry is concerned about “the tidal wave” which is likely to affect the market in the years to come. It will be interesting to see how the markets will react to the LNG projects that are to be completed in the years to come.
 This $1.5 is currently regarded as the short-term marginal cost for obtaining LNG from the Henry Hub in Europe.