Thierry Bros
2013.03.20
The four consequences of the US shale gas revolution
1/ US coal is displacing Russian gas in Europe
The US shale gas revolution pushed Cheap US coal and is displacing expensive gas for power generation in Europe. But, faced with record low European gas demand, Norway managed to increase its production, forcing Gazprom to act as the swing supplier.
In 2012, Norway became the leading gas supplier to Europe
Gazprom gas is available. With daily maximum output, Gazprom could have produced 605 bcm in 2012 vs 487 bcm effectively produced. Extra Gazprom gas was available during the Libyan revolution and could help mitigate any crisis (such as for example turmoil in Algeria). But it doesn't make a winning business model to sit on spare capacity and to wait for other producers to not be able to fulfill their contracts! Gazprom needs to adapt. After a retroactive payment of $2.6bn in 2012, Gazprom provisioned $4.5bn for 2013. An easier solution would have been to become more flexible on prices...
2/ US LNG is already a game changer
US LNG exports are a game changer and expensive LNG projects will no longer receive any Final Investment Decision (FID).
Disclosed capex of LNG projects
Ichthys could be the last greenfield LNG project sanctioned (January 2012) in Australia because, with rampant cost inflation and an increasingly price-sensitive customer base, these large-scale, expensive projects simply look cumbersome and outdated in the context of intensifying global competition. Indeed, Australian projects are being priced out of the market. This, coupled with delays (the next key newsflow from Australia could indeed relate to delays), which are set to erode returns from the country's already marginal developments. In the last two years, Qatar's pricing policy has meant that the highest cost producer, Australia, has been able to undercut the lowest cost producer, Qatar.
In February 2013, Repsol sold its LNG business (excl. Canaport and North American Marketing/Trading) to Shell for a price of $6.7bn. This includes cash of $4.4bn, balance sheet debt of $0.5bn and financial leases of $1.8bn. The assets sold include ALNG in Trinidad and Tobago (interests of 20-25% in four liquefaction trains (total capacity 14.6 mtpa) and offtake), Peru LNG (20% of liquefaction (capacity 4.5 mtpa) and 100% of the offtake), a fleet of 13 LNG tankers, a 25% interest in an 800 MW combined cycle power plant in Spain and its Marketing, Shipping & Trading businesses excluding North America. This acquisition adds some 7.2 mtpa of LNG volumes through long-term off-take agreements, including 4 mtpa of equity LNG plant capacity. If we assume, as an extreme case, that just equity LNG has a value, then we end up with the full price of $6.7bn for 4.2 mtpa capacity or $1.6bn/mtpa. This compares with $3.5bn/mtpa for Prelude, illustrating that expensive projects are facing challenges.
We believe that since the Sabine Pass FID (August 2012), we are moving to a lower cost LNG business. This is why all Asian buyers (and this is where demand is expanding) are pushing for North America to become a major LNG exporter. This could be detrimental for Russian pipe gas attempting to find a market in China.
The February 2013 Vladivostok LNG FID (excluding capex numbers not yet disclosed) could be viewed as an alternative for Gazprom to export gas from the Eastern part of Russia if the deal with CNPC to provide China with 38 bcm/y via the Eastern route fails to materialise.
3/ The US could impose its spot pricing model
Oil indexation is facing major challenges. Under the old system, long-term, oil-linked contracts were signed to ensure both security of demand and security of supply, while hub spot trading provided additional volumes. However, this system is on the brink of a step change. In Europe, the rationale for oil indexation disappeared many years ago, so hub pricing makes more sense today.
By directly sourcing US LNG priced under a HH formula, Asian customers are cutting out the middle man, the LNG aggregator. And, if the US becomes a major LNG producer as we believe, then this change in business model could start to reduce oil-indexation in Asia, as we are seeing in Europe.
The US could be the cheapest gas market by the end of the decade; other markets will be linked via the cost of arbitrage (liquefaction, transport and regasification).
Overview of gas prices in 2020e (with estimated spreads in $/MBtu)
4/ Producers needs to adapt
As mentioned earlier, oil indexation is facing challenging times. No European or Asian buyer wants to sign such contracts any longer. So, gas sellers will have to adapt. ‚Innovative‛ pricing will therefore be required for new projects to kick off. Expensive projects that can only be profitable with oil indexation will be indefinitely postponed, as was the case with the Shtokman project. The industry will have to move from a "gold-plated" to a "low-cost" investment standard. But it can be argued that if we have a low-cost air industry (that transports passengers safely) it should also be possible to create a low-cost (safe) gas industry as the customers are only interested in getting the commodity at the cheapest possible price.
However, as sellers are not willing to sign "cheap" contracts, "innovative" pricing will be needed. Sellers need a floor for each project to be profitable. This could be contractually agreed in exchange for a ceiling for buyers that don't want to face huge bills. And, between the floor and the ceiling, a hub pricing mechanism could apply. So new projects would go ahead on their merit order (cost basis) and the flexibility of the pricing that suits buyers while also maintaining a decent margin for the seller.
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