Japan has increasingly been forced, since the 2009 recession, to face severe challenges to its energy and environmental policies.
The March 2011 Fukushima disaster placed the future of nuclear energy under a cloud, leading to a September 2012 policy statement which called for the phase-out of all nuclear plants, by sometime in the 2030s. In October 2012, after years of debate, Japan finally addressed the carbon 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 54% of Japanese power generation in 2009 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 had accounted for only 28% of generation in 2009 (non-hydro renewables were 3%). Because of its higher costs, LNG has historically been relegated to intermediate dispatch where its generation share (pre-Fukushima) had never exceeded 28%. Gas had a lower industrial share: 9% to coal’s 30%.
But just as Japan is attempting to place greater emphasis on more expensive gas, LNG costs have been rising substantially. Import prices in 2012 were at an all-time high. Thus the appeal of importing US LNG, where the development of shale gas has driven gas prices there to levels not seen since the 1990s.
POST-FUKUSHIMA NUCLEAR SHUTDOWN FUELS LNG IMPORT HIKE
Whilst a decline in total required generation and an increase in oil-firing partially offset the loss between 2009 and 2012, gas-fired generation still accounted for 44% of the total replacement requirement. This led to a 36% increase in LNG imports, 89% of it attributable to added electricity use.
Japan also had to cope with declining gas availability from Indonesia, which had supply problems. While increases in long-term contracts with Australia, Qatar and Sakhalin helped, uncertainties forced Japan to utilize short-term imports, accounting for 62% of the increase.
2009-10 SURPLUS SET OFF REGIONAL GAS PRICE COMPETITION…
It has been common among analysts to speculate that growing LNG trade would ultimately create a “world gas market” by linking previously isolated regional markets. The 2009-10 LNG surplus finally made it happen. But the result bears little resemblance to the relatively uniform regional price structure of the world oil market. Accordingly, as a result of the surplus, international gas prices are experiencing unprecedented divergence.
Just how far out of balance they are is illustrated by average regional prices in 2012:
• US commodity prices at Henry Hub – $2.74
• Dutch commodity prices at the TTF Hub – $9.34
• German contract prices from Russia – $12.56
• Japanese LNG (as liquid) – $16.55
This is a radically new pricing environment: In the five years preceding 2008, the average price spread between the highest of the four (Japan) and lowest (TTF) was only 10%. Japanese prices were only 3% more than Henry Hub.
…AND FORCED POSSIBLE PERMANENT PRICE RESTRUCTURING
Some of the disparity is due to transient market conditions – distress pricing in the US and the Japanese response to the nuclear shutdowns. But part of it represents a permanent restructuring of international gas pricing to which Japan is vulnerable. The restructuring puts great stress on finding ways to reduce the costs of Asian LNG imports in order to maintain industrial competitiveness.
Much of the interest in US LNG exports is based on this huge 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 local French wines, “does not travel well”. Thus LNG importing countries will inevitably have higher prices than exporting countries.
The full effect of the US Shale Gas Surplus began to make itself felt in mid-2008 when 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. Dutch TFF was first influenced by weak surplus LNG prices; later by continental prices as markets tightened.
WHAT MIGHT A COMPETITIVE COMMODITY GAS MARKET LOOK LIKE?
One can devise an “Equilibrium” set of basis differentials between markets by assuming that transportation alone sets the regional price differences for the commodity. Alone among the major LNG trading partners, North America has a truly gas-to-gas competitive commodity market; while the UK also has a competitive commodity market, it tends to be influenced by continental oil-linkages 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.
Typical Japanese pricing clause is based on a simple formula linked to the Japanese customs cleared price for crude oil, JCC “the Japanese Crude Cocktail” (see p28). The formula 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 imported 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 reception terminal. The price clause is based on destination market conditions. Less common is the FOB contract in which ‘delivery’ is taken at the outlet of the liquefaction plant. But the pricing is commonly based on destination pricing and adjusted for tanker transportation.
All the US export contracts so far are also FOB contracts. But they are unique in that their pricing clauses are based on origin pricing – keyed 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 (see Chart 1).
US LNG projects destined for Japan require export authorization from the Department of Energy (DOE) and a certificate from US environmental regulator FERC.
Five Japanese contracts represent 10% of the DOE-approved capacity (see Chart 2). But none of that capacity (as of end-2013) has a FERC certificate. The IEA is not optimistic about long-term Japanese gas demand in its 2013 World Energy Outlook (WEO 2013). It forecasts a slight decrease to 2020 followed by limited growth to 2025. Thus the opportunity for imports of further US LNG depends on expiration of current contracts. This is expected to occur significantly in 2019-21 (see Chart 3).
The gradual emergence of a buyers’ market in Japan should give it a better bargaining position for contract renewals and new supplies.
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 (in the form of LNG) thus have a powerful appeal. But, 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 T Jensen is an energy economist at consultancy Jensen Associates (JAI-Energy.com; [email protected]). This article is adapted from a presentation to the Brookings Institute, Washington’s 14 January seminar on the Unconventional Hydrocarbon Renaissance and its Impact on Japan.