Changing Market Realities in Light of Continuing Low Gas Prices

The decline in the oil price coupled with physical oversupply in hydrocarbon markets and an economic slowdown in many developed and emerging economies explains the continuing low gas price. Throughout 2015 and early 2016 most liquid hubs experienced record price lows and a reduction in trade flows, while the rate of growth in demand for gas continued to decline in Europe and in Japan and South Korea, the world’s two biggest LNG consumers. A new market reality characterised by an excess of gas may persist for some years to come. The International Energy Agency has stated that this trend will not reverse until at least 2018. Even this prediction may be over-optimistic given McKinsey’s recent market assessments, which predict an oversupply of gas until 2020-22 [1].

In this context, certain structural effects of the decline in the gas price in the medium term are worthy of scrutiny. Three issues are of particular interest in this regard:  the future of the US shale gas revolution, given that the number of exploration rigs has reduced; the evolution of the liquefied natural gas (LNG) market, which is strongly affected by the low gas price; and the competitiveness of existing suppliers, such as Russia, in the context of European diversification strategies.

That the US shale gas revolution was largely stimulated by a positive Henry Hub price dynamic in the middle of the last decade is unsurprising. Back then, the North American gas price was pegged to oil at 14% of the West Texas Intermediate and, therefore, crude price hikes contributed to the Henry Hub’s elevated figures. In turn, small and medium sized producers across the US benefited from these high prices and invested in new production fields. It is worth noting that the flexibility of the shale gas industry derives from the fact that most of the activities it entails, from drilling to pipeline connection and marketing, have been outsourced. Local hubs receiving shale gas volumes have traded at even lower rates than Henry Hub. For instance, the gas price in the Marcellus hub dropped to $2/mn Btu in the summer of 2012, while the Henry Hub price was still at a level of $3.5/mn Btu.[2]

The flexibility of the market, among other factors, allowed the industry to survive despite the prevalence of low prices for extended periods. Nevertheless, in 2015-16 gas prices dropped to $1.5-2/mn Btu, thus narrowing the usual gap with local hubs (e.g. Marcellus) [3], as a result of which many producers found themselves unable to meet their debt repayment obligations.

Even quite large shale gas producers, such as Chesapeake, experienced significant financial problems by losing more than two-thirds of their profits. With the price decline in 2014-15, economically viable proven reserves have also been revised downwards by at least 63%.[4]

By contrast, vertically integrated companies such as ConocoPhillips and ExxonMobil did better with their refining businesses enjoying the benefits of cheap oil. Although their stocks declined significantly, their debt was not so badly affected, suggesting an ability to increase shale gas production by acquiring smaller producers. In conclusion, it seems probable that the lower gas price will reshape the current structure of shale gas production by favouring large companies over smaller ones to an even greater extent than was previously the case.

This brings us to the second aspect of the LNG market that is commonly discussed. The trade in gas shipped by tanker has grown significantly over the past few decades, with the amounts supplied reaching more than 240mn mt/yr. The use of more modern LNG tanker engines such as tri-fuel diesel electric (TFDE) propulsion, has reduced transportation costs by 25-30% over the last decade. These also save space in the tanker, allowing more capacity for LNG.

LNG transportation costs vary with the gas price. For example, in 2014, when Asia-Pacific gas prices stood at between $13 and 14/mn Btu, charter rates worked out at $0.7/mn Btu. By contrast, in 2015, when the Platts Japan-Korea Marker (JKM) for spot cargoes halved from its previous levels, charter rates went down to $0.4/mn Btu. Over the last decade, day-rates varied from $30,000 to $110,000. With the recent price decline the day-rates have gone below $29,000 even for TFDE propulsion vessels, and to $20,000  for older vessels. [5] Likewise, port charges for vessels have also halved at a number of harbours.  

Monthly Average Prices:

Source: Platts

1. Henry Hub prices represent NYMEX front month futures prices

 2. NBP and JKM prices represent Platts front month assessments for the UK and the Japan-Korea spot LNG markets.

Lower shipping costs do not offset entirely the capital-intensive commitments of new LNG export plants, where cost inflation, especially in Australia – where the hugely expensive Gorgon plant recently came on stream – Canada and Russia, has put them at a disadvantage relative to their competitors in the Middle East.[6] In many newly projected LNG export plants, liquefaction costs constitute around 30% of total capital expenses, mainly because of high construction, engineering, fuel and other costs. Most of them were based on the JKM being between $9 and $14/mn Btu. So with the JKM around the $6-7/mn Btu mark, more expensive liquefaction projects are likely to be deferred.

The low gas price and the physical oversupply of the markets thus affect the economic rationale of diversification strategies. In particular, diversification of supply has been a longstanding aspect of European energy strategy, mostly for security of supply reasons and in order to increase interconnection between countries. In fact, such diversification has been based on a certain level of willingness to pay for alternatives, especially to Russian gas. The latter has traditionally been traded by pipeline on the basis of long-term contracts at an oil-indexed price. Therefore, when the oil price rose in 2011-13 while the gas hubs experienced price decline, Russian gas became significantly more expensive in the European markets.

Thus, willingness to pay for diversification projects gained relevance. The most recent examples of this include the Klaipeda LNG import terminal, reverse flows to Ukraine and general political support for non-Russian alternatives.

Following the drop in the oil price, the oil-indexed gas price declined to its lowest levels. Interestingly, the much politicised discussion over phasing out oil indexation in gas supply contracts also faded away.

For both Europeans and Russians, the strategic value of oil indexation declined because the price differential with hub-traded gas became way less significant. In this context, one might expect, at least from a purely market perspective, a decline in willingness to pay for alternatives. After a big cut in exports in 2014, mostly due to the Ukraine crisis, 2015 saw Gazprom’s exports to Germany rise by 14%, to Italy by 12%, and to France by more than 30%. Furthermore, the first quarter of 2016 marked growth in the volumes exported by Russia of 36% compared with the previous year.[7]

Further, the decline in the gas price has reinforced Gazprom’s pipeline gas competitiveness. While from 2003 to 2014 its production costs grew significantly from $10/’000 m³ to $50/’000 m³, since 2014 these costs have reduced. Moreover, the favourable exchange rate between the Russian rouble and the US dollar contributes to Gazprom’s wellhead price. At the end of 2015 and early 2016, conversion rates brought about a reduction in costs in dollars of at least 30%. Russian gas production costs averaged $30/'000 m³, mostly as a result of this.[8]

In conclusion, the continuing low gas price provides a solid basis for international market transformation by strengthening the position of larger companies over smaller ones, existing suppliers over new, and cheaper producers over more expensive ones. In addition, the lower commodity price reduces interest in diversification and thus may change the overall political approach towards the sector.

A higher price stimulates alternatives and diversification while a low price may lead to consolidation and conservation of existing market structures. However, the forecasts are in agreement regarding the cyclical trends although no single analyst is likely to be able to correctly predict the time frame during which such reversal trends will occur.

Andrei V Belyi is senior researcher at the Centre for Energy, Environment and Climate Change Law at the University of Eastern Finland; at the Global Faculty at the Centre for Energy, Petroleum, Mineral Law and Policy at the University of Dundee and the author of Transnational Gas Markets and Euro-Russian Energy Relations”, London: Palgrave Macmillan, 2015