Since the 2009 recession, Japan has increasingly been forced to face severe challenges to its energy and environmental policies. The Fukushima disaster in March 2011 placed the future of nuclear energy under a cloud, and led to a policy statement in September 2012 calling for the phase-out of all nuclear plants by sometime in the 2030s. Then, after years of debate, in October 2012 Japan finally addressed the carbons emissions issue by introducing a phased-in carbon tax.
These two policies, designed to reduce dependence on coal and nuclear, effectively downgraded the two energy sources that supplied 53% of Japanese power generation in 2010 and were relied on for base load. While these policies may not survive the recent change in government, they imply greater reliance on LNG-fired power generation and advanced coal technology. (LNG accounted for only 27% of generation in 2010).
Because of its higher costs, LNG has historically been relegated to intermediate dispatch, where its pre-Fukushima generation share had never exceeded 28%. Gas has a lower industrial share: 10% to coal’s 56%. But just as Japan is attempting to place greater emphasis on gas, LNG costs have been rising substantially; import prices in 2012 were at an all-time high. Hence the appeal of importing LNG from the US, where the development of shale gas has driven gas prices there to levels not seen since the 1990s.
The gas market surplus set off regional gas price competition, forcing a possibly permanent restructuring of the international gas pricing system. For some time, it has been common among energy analysts to speculate that growing LNG trade would ultimately create a “world gas market” by linking previously isolated regional markets. The LNG surplus of 2009-10 finally made it happen, but the result bears little resemblance to the relatively uniform regional price structure of the world oil market. As a result of the surplus, international gas prices today are experiencing unprecedented divergence.
Just how far out of balance they are is illustrated by average regional prices in 2012 (in $/mn BTU):
• US commodity prices at Henry Hub - $2.74
• Dutch commodity prices at the TTF Hub - $9.26
• German contract prices from Russia - $12.56
• Japanese LNG (ex-ship) -$16.66.
The restructuring puts great stress on finding ways to reduce the costs of imported Asian LNG in order to maintain industrial competitiveness. Much of the interest in US LNG exports is based on this disequilibrium between US commodity prices and European and Asian contract prices. It has been possible to talk of “world oil prices” because the costs of marine oil transportation are relatively low; the same is true of coal. But one cannot talk about “world gas prices” because gas, like those legendary local French wines, “does not travel well.” Thus LNG importing countries will inevitably have higher prices than exporting countries.
Prices have been driven by different forces in each of the four markets. The full effect of the US shale gas surplus began to make itself felt in mid-2008, and Henry Hub prices fell. But the oil-linked continental and Asian contract prices were driven by oil prices first rising, then briefly falling and then rising again. Europe has now partially adjusted to commodity competition.
Traditionally, the typical Japanese formula provided a higher price level for a given level of oil prices than the European one; while for a time this premium was partly offset by price capping clauses called “S Curves,” many of these have now been eliminated. TTF was first influenced by weak surplus LNG prices and later by continental prices as markets tightened.
A legitimate question is what a theoretical world competitive commodity gas market might look like. One can devise an “equilibrium” set of basis differentials between markets by assuming that transportation alone sets the price differences.
Alone among the major LNG trading partners, North America has a truly gas-to-gas competitive commodity market; while the UK has a competitive commodity market. It tends to be influenced by continental oil-linkage when LNG markets are tight.
The “equilibrium” commodity pricing system thus might be based on Henry Hub pricing. And although it lacks the liquidity and transparency of Henry Hub, Qatar plays a similar “Hub” role in LNG, since it can arbitrage Atlantic Basin and Pacific Basin prices. In such a theoretical system, the European gas value might be based on US prices plus the cost of transportation from the US Gulf coast to Europe; then those prices might be netted back to Qatar where they would in turn establish Asian equilibrium prices.
Graph 1 presents such an estimate; the equilibrium differential between US and Europe for 2012 is $5.21 (per mn BTU) and between US and Japan $13.92 ex ship (before regasification).
In this case $5.21 out of the total $6.52 margin between the US (Henry Hub) and Europe (TTF) represents the underlying transportation “Basis Differential”; only $1.31 is the disequilibrium between the US’s fully competitive commodity market and Northwest Europe’s mixed commodity/contract market.
But because the theoretical equilibrium value of LNG in Japan is not different from that in Rotterdam (the tanker distances from Qatar are similar) the disequilibrium in Japan is very large at $7.29. It is this very large “Asian Premium” that attracts Japanese customers to US supply; and while 2012 market conditions – weak US prices and very strong Japanese prices accentuate the disequilibrium, the IEA in its WEO projections expects some premium to persist (see Graph 2).
The typical Japanese pricing clause is based on a simple formula. It is linked to the Japanese customs cleared price for crude oil: JCC or the “Japanese Crude Cocktail.” It is in the form of P=C+S*JCC. Where P is the price in $/mn BTU, C is a constant expressed in $/mn BTU and S is the “slope,” a dimensionless number. Discounting is most often done by changing the slope and sometimes the constant; but its simplicity limits the contract options for competitive discounting and, once negotiated, the only thing that changes is the oil price.
Northwest Europe has benefited from the price competition that was unleashed by the LNG surge in 2009-10. There LNG arbitrage together with North Sea commodity competition exported weak North American prices to the continent through the open access EU pipeline system and undermined oil-linkage.
No similar price competition has been possible in Asia because there is no access to commodity gas. This has been a powerful driving force behind the Asian interest in US exports, since it gives Asia a source of gas-to-gas competitive commodity supply similar to that which has already benefited Europe.
The most common type of LNG contract is the Delivered Ex-Ship (DES) contract in which the seller delivers to the buyer’s receipt terminal. The price clause is based on destination market conditions. Less common is the non-delivered (FOB) contract in which the delivery is made at the outlet of the liquefaction plant; but the pricing is commonly based on destination pricing and adjusted for tanker transportation.
All of the US export contracts so far are also FOB contracts. But they are unique in that their pricing clauses are based on origin pricing – linked to the North American Commodity Price at Henry Hub. Thus unlike traditional clauses, the economic rent – and the price risk – go to the buyer, not the seller. That is their appeal to oil-linked contract buyers.
Japan, not having a Free Trade Agreement with the US, requires Department of Energy (DOE) approval to import US LNG. But, assuming that US exports will be permitted, four Japanese utilities and three Japanese trading houses have signed contracts with pending export projects.
The IEA is not optimistic about long-term Japanese gas demand. In its 2012 WEO it forecasts a slight increase to 2015 and a slight decrease to 2020. Thus the real opportunity for US imports depends on replacing the volumes in soon-to-expire existing Japanese import contracts. This is expected to occur to a major extent during 2019-21. By 2021, tentative utility contracts are expected to account for 45% of the new requirements and traders’ portfolios for 43%.
Japanese prices have been partially supported by the high cost of Australian LNG liquefaction projects. Graph 3 uses Australia’s Pluto LNG as indicative of Australian offshore costs and Queensland’s GLNG for coal seam costs. Some of the proposed projects may be more costly.
The new Australian projects are threatened not only by US exports but also by potential new projects such as those on the Canadian Pacific coast (British Columbia) and Mozambique. Mozambique field costs may be as low as $3/mn BTU, but no tax regime is yet in place. These projects, as stranded gas, will presumably utilize traditional DES contracts; US FOB contracts thus have a potential market advantage to a buyer seeking the rent and willing to accept the price risk.
Japan faces serious energy cost challenges as it attempts to deemphasize coal and nuclear in favor of expensive imported LNG. Imports of low-cost US shale gas thus have a powerful appeal.
To date four Japanese utilities and three trading houses have signed US LNG contracts in the hope that exports to Japan will be approved.
And while the present price spread between US and Japanese prices may be unrealistically large, some spread will remain. Thus a major appeal of US imports is the ability to introduce commodity price competition into the high-priced, and structurally rigid, traditional Asian oil-linked pricing formula.
* James Jensen is an energy economist at consultancy Jensen Associates (JAI-Energy.com; email: [email protected]). This article is adapted from a presentation to the Conference on US Shale Gas & Pacific Gas Markets, sponsored by the Center for Global Energy Policy, Columbia University and the Center for Energy Governance & Security, Hanyang University, 14 May, 2013.