LNG market shaken by emerging supply sources
Factors affecting the future of global LNG supply are numerous and unpredictable, encompassing infrastructure development, financing, political risk and pricing. But, one way or another, it all comes back to what happens in the US
The liquefied natural gas (LNG) market is being shaken by the emergence of major supply sources that are competing to meet rising demand: Australia, the continental US, western Canada, Alaska, the eastern Mediterranean, east Africa, Russia, and others. Increasingly, buyers have more leverage than sellers, and prices, therefore, should come down. But how this story will play out is far from certain.
It is useful to put prospective supply into perspective. If one were to rewind to the mid- to-late-2000s, the LNG market was also full of possibilities: Algeria had a target to export 85 billion cubic metres (cm) of pipeline gas and LNG by 2010 (actual exports: 55bn cm); in Libya, Shell, Eni and BP each proposed an LNG export project as the country reopened its doors to foreign investment; Egypt had just started to export LNG and was considering adding more trains; Nigeria’s list of proposed projects was long (Nigeria LNG trains 7 and 8, Olokola, Brass); Equatorial Guinea had just finished its first train and was focused on a second; Venezuela had unveiled plans for three trains, supplied in part by the Loran and Mariscal Sucre fields; Qatar had just imposed a halt on its post-77 million tonnes per year (t/y) ambitions, but Iran was still pursuing exports (Persian and Pars LNG); Gazprom had finally picked partners for the Shtokman project (combining both pipeline and LNG); and Statoil (StatoilHydro at the time) was mulling a second train at Snøhvit.
In retrospect, it is shocking to see how few of these projects materialised – in fact, few of these options are even on the table anymore. Several have either been stricken for good (Egypt, for example), while others – including Libya, Nigeria, Iran, Algeria, Venezuela – require fundamental changes in the host country. It was this disappointment with prospective supply that fuelled the investment boom in Australian LNG and the near-oil-parity contracts signed at the peak of the cycle in 2008. Australia was almost the only place to go because the risks that LNG projects in 2005-09 faced were beyond the “control” of the project sponsors, who could not “throw money” at an LNG project in Iran or Libya or Nigeria or Algeria and actually secure LNG.
The logic of “higher prices will create more supply” needed Australia to function – the place where an LNG buyer could reasonably expect supply by paying more. Australia became such a huge recipient of capital because it was, essentially, the only place where buyers could expect to get additional supply in the post-2014 period – in the interim, they could go to LNG aggregators.
This history matters because, as Mark Twain reportedly quipped, “history may not repeat itself, but it does rhyme”. It may be useful to think of the US as the new Australia – not only because it will likely rival Australia as a supply source, but because its build-up will hinge largely on the pace at which other parts of the LNG world develop.
Most LNG forecasts assume that the US will end up with 40-50m t/y of LNG capacity by 2020 and 60-70m t/y by 2025. But these projections assume certain capacities outside the US in, for example, western Canada or east Africa. What if those other regions disappoint? Where will capital be redirected? Probably, to the US.
The US is thus similar to Australia circa 2008-10, where project risks are within the grasp and control of their sponsors. All US-based projects can secure an export licence to sell LNG to countries that have a free-trade agreement with the US, several projects have secured rights to sell LNG to anyone, and all projects have to overcome a set, albeit costly and time-consuming permitting process with the Federal Energy Regulatory Commission (FERC).
Aside from permitting risk, companies willing to take on the price risk of a US LNG project can build a plant. This is a different position from other parts of the world where geopolitics, politics, or permitting hurdles can delay or halt an LNG project altogether.
The risk may not be lower but it is more defined. Yet, there is one crucial difference between Australia and the US – at least so far. Australia pushed the cost curve up, while the US is bringing it down. In particular, the “Cheniere formula”, which starts with Henry Hub and adds a fuel surcharge and liquefaction (tolling) fee is profound on four levels.
First, it is a cost-plus formula, where the final sales price reflects the cost of the commodity rather than the buyer’s ability to pay – which is how oil-parity contracts are structured. As such, it is the strongest indication of a buyers’ market.
Second, the formula produces an LNG price that is clearly lower than prevailing Asian LNG prices, at least at the Henry Hub levels of 2012 and 2013, although a cold spell during early 2014 pushed up Henry Hub to such heights that the arbitrage shrank considerably.
Third, it is transparent, thus challenging the absurd and sometimes farcical process of “price discovery” in Asia, which means an endless pursuit of the gossip around the latest deal as a means of gauging market fundamentals.
And finally, it is more volatile, exposing buyers to a price marker that fluctuates more than oil and which can be subject to big swings, especially during extreme weather events. Such volatility, as European buyers have learned, can pose challenges to a utility model where end-user prices for either gas or electricity are sticky.
Will these profound changes spread? In part, the offering of a Henry Hub-based contract has finally led to a meaningful conversation in Asia about whether LNG should continue to be priced relative to crude oil.
In reality, this is a more useful discussion than whether Henry Hub should be the new benchmark for Asian LNG since the US would have to export lots of LNG in order for Henry Hub to become a barometer of global – rather than just US – fundamentals. And while Singapore’s ambitions to become an LNG hub has attracted the most attention, it is, actually, the development of a liquid market in Japan that holds the greatest promise to reshape pricing in Asia.
Therein, however, lies a tension between two fundamentally different approaches towards lowering LNG prices, and Japan exemplifies this tension better than any other country. One approach says that securing cheaper LNG is chiefly about finding new and cheaper supply. For years, Japan has approached LNG pricing this way, and its embrace of US-based LNG continues in that tradition.
The other approach says that countries can make substantive changes to pricing by focusing on internal, rather than external mechanisms.
Japan is gradually shifting its focus from an exclusive emphasis on new supply to looking for internal changes to bring down gas prices. In that context, the possible restructuring of the Japanese power sector is crucial.Europe, in large part, followed on this path over the last five years. While benefiting from the oversupply of LNG and gas, it was its focus on liberalising the internal market that allowed such a speedy adoption of hub-based pricing in long-term contracts – Europe did little to create new supply, in part because it already had too much, but focused on downstream competition, open access to infrastructure, and on the creation of several (often immature) pricing points. Combined, these forces enabled the pricing transformation that the continent has witnessed since 2009-10.
In most countries, electricity sector reform has predated gas sector reform, and so the speed with which Japan restructures its electricity sector could provide a barometer for the pace of gas sector reform – which, in turn, is a prerequisite for meaningful reform to the current system of pricing gas in Japan and Asia in general.
Without open access to infrastructure and competition downstream, the introduction of hubs and futures markets will provide only marginal relief – it is only a greater market liberalisation that can offer a real change to the pricing system of LNG in Japan.
As such, Henry Hub-based LNG into Asia has provided a useful shock to the system, but it could, counter-intuitively perhaps, slow down the transition to a true Asian LNG marker by offering an acceptable path to lower prices without forcing countries such as Japan to break up the monopolistic or oligopolistic market structures that dominate their national energy markets.
The wildcard, of course, is Qatar. In Europe, gas suppliers responded very differently to the challenge to oil indexation. Statoil, for example, embraced it, while Gazprom accepted it only begrudgingly, and Sonatrach has resisted it even more than Gazprom, and these varying responses set the tone for how prices evolved in Europe.
Will Qatar just lower its price expectations? Or will it become more aggressive, possibly trying to undercut new suppliers, especially as some of its contracts expire? Or could Qatar even call for a different pricing system altogether?
In one way or another, it all comes back to the US – to the trajectory of Henry Hub, to the level of LNG exports, and to the pricing system that will govern the LNG from the US. And yet, the world is still at odds about how to absorb all this LNG and whether it will usher a new era of gas and LNG pricing in Asia.