LNG spot prices could sink to $5-$6/mn Btu or lower this summer: Stern [Gas in Transition]
After the panic of last year, European gas supplies are looking good, perhaps too good. Gas inventories at the end of June had reached close to 80% full two months before the end of summer, suggesting they could hit tank top by September. In addition, Asian demand has not experienced the bounce expected following the end of China’s restrictive COVID-19 policies, leaving more LNG available for Europe.
As a result, when European storage is full, or if buyers slow their filling strategies, there could be a short-term surplus, potentially pushing prices down to $5-$6/mn Btu or lower, according to Jonathan Stern, Distinguished Research Fellow at The Oxford Institute for Energy Studies. “This is what Americans call an ugly market”, he says, meaning significant potential for downside price movements.
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The potential for unexpectedly low prices amid what is widely recognised as a structurally tight market, may be leading to complacency. Certainly, there is widespread view that this winter Europe may still face significant price risk, but no real volume risk.
But, according to Stern, forecasters work on ‘normal’ winters, and demand levels depend not just on a normal winter in Europe but a normal one in north Asia, home to the world’s largest LNG markets. Severe cold in either regions or both, particularly in early winter, could see storage levels fall sharply, demand rise and with it spot prices. If prices do experience a sharp drop, it is unlikely to last more than three or four months, Stern says.
On the issue of complacency, “there are too many moving parts to give a simple answer”, he says. If China’s economic growth remains below par, that will help, and if Japan brings more nuclear reactors back into service that too will ease demand-side pressure, he concludes.
China has become the centre of swing demand
Stern’s analysis in one respect echoes what many other industry figures argued at the LNG2023 conference in Vancouver, Canada. European gas prices are now much more dependent on events in Asia, particularly China.
According to Pat Breen, CEO of Gas Strategies, the energy crisis has fundamentally changed the structure of the LNG market and left Europe at a “significant economic disadvantage”, owing to the higher cost of LNG compared with Russian pipeline gas.
Europe has transitioned from being the market of last resort to a market of first resort. In the process, significant flexibility has been lost, he says.
With Russian pipeline gas, European buyers could vary considerably the volumes of gas imported, depending on whether demand was high or low. Europe’s domestic gas production, primarily located in the North Sea, has been and continues to work at full capacity. And inventory levels are now mandated by law, which means there is less scope to use storage as a form of short-term flexibility.
This means flexibility in the European energy system has effectively been outsourced to the LNG market, where China has become the swing market, argues Breen.
The Chinese gas market is structurally very different to Europe’s liberalised structures. Purchasing policy can be directed by the government and is controlled predominantly by the country’s three large national oil companies (NOCs).
According to Breen, volatility and uncertainty have become “locked in” – only the scale is unknown. The loss of market flexibility means there is an increased risk of spot price spikes up until 2026, and, thereafter, a risk of a price crash as new capacity comes onstream in Qatar and the US.
While Stern focuses on the short-term potential for price volatility, the completion of new liquefaction capacity in Qatar and the US post-2026 is a major cause of concern, but perhaps one which is overblown. “Energy economists are good at analysing energy systems, but not so good at general macroeconomics,” he observes. Even relatively small changes in Chinese GDP, in particular, can have an outsized impact on LNG demand, he says. Asian gas demand could rise strongly, if macroeconomic conditions improve over the next two to three years.
The LNG market has seen three turbulent years, moving from prices lower than could be imagined to prices higher than could be imagined, he says. Now analysts are working with a false equilibrium of $9-10/mn Btu, he argues. Nonetheless, at the least, the new liquefaction capacity coming online post-2026, predominantly in the US and Qatar, should create a period of relative calm.
But just as Stern questions whether new liquefaction capacity post-2026 will inevitably lead to a supply glut, he also queries whether European gas demand will fall as fast as some expect post-2030, driven by energy transition policies. There is a big difference between setting targets and realising them, he points out. If, as currently appears likely, Europe’s 2030 emissions targets are missed, will the political will exist to impose policies that make their realisation certain?
Similarly, China has taken a large leadership position in the energy transition in terms of transport electrification, on and offshore wind and solar power. There are large uncertainties governing the future trajectory of the country’s LNG demand, which may prove largely price driven. If LNG proves expensive, the country may rely more on coal for longer, while it builds out its already impressive renewable energy capacities.
Market power shifts to Qatar, China and the portfolio players
Ryan Hickman, Global Gas Fundamentals Manager – East for Shell also sees China having moved into a position of greater power within the LNG market.
He argues that when prices rose towards the end of 2021 and into 2022, Chinese buyers exited the high-priced spot market. Europe joined the LNG markets of North Asia, Japan and South Korea, as a ‘premium’ market, with buying driven by security of supply concerns. South Asia and other buyers still form a price-sensitive ‘residual market’, while China has emerged in the middle as the source of swing demand.
This leaves a market in which three financial structures exist, according to Hickman, one based on traditional oil-indexed pricing dominated by Qatar, another based on indexation to Henry Hub, dominated by US production and the spot market.
According to Breen and other speakers at LNG 2023, European buyer’s reluctance to commit to long-term sales and purchase agreements – largely the result of the expectation that emissions targets and other energy transition policies will see European gas demand fall post-2030 – will leave Europe largely dependent on spot mark purchases – the most volatile part of the market, representing about 30% of total LNG trade.
Breen also notes that in terms of market power, US sellers operating within a liberalised market will have much less clout than the large NOCs of China and Qatar. He sees the new market structure putting power in the hands of China, Qatar and the large portfolio players.
What appears certain is that, wherever market power may lie, Europe’s reluctance to enter into long-term contracts leave it on the sharp end of spot price volatility.