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Opinion: Japan unveils ‘biggest shake-up’ in LNG since 1970s

Tue 14 Jun 2016

Opinion: Japan unveils ‘biggest shake-up’ in LNG since 1970s
Credit: Moyan Brenn

In contrast to the arrival of the first US LNG cargo, which sent journalists into a frenzy of Russian-pipeline-gas-versus-US-LNG-price-war rhetoric, the publication last month by Japan’s Ministry of Economy, Trade and Industry (METI) of the Strategy for LNG Market Development passed almost unnoticed, writes Jonathan Stern.

The importance this placed on LNG reflects the emerging realities of Japan’s future energy and power mix. The Energy Strategy unveiled in mid-2015 foresaw 20-22 per cent of nuclear in the power mix by 2030, but this appears very ambitious to most observers, with increased use of renewables, coal and LNG a more likely outcome.

But in the absence of carbon-capture systems (CCS), greater use of coal rather than LNG would present challenges to emission targets and, despite last year’s drop in LNG imports, for these reasons it appears likely that LNG will remain a key component of Japan’s future energy mix.

Given the impact of high oil and LNG prices on the country’s trade balance over 2010-2014 and on the financial health of gas and power companies, LNG will be more acceptable if it is affordable which, in Asian buyers’ eyes, means at prices delinked from oil.

The strategy’s main proposition that Japan, as the world’s leading importer can, “play an initiator role in creating a global LNG market”, is an ambitious aspiration, but two developments seem certain.

First, the strategy heralds the biggest shake-up of the Japanese gas and LNG market since its creation in the 1970s. Second, it is a declaration that traditional crude oil-linked (JCC) pricing has reached the end of the road, and will be followed by a new era of market-based pricing.


Main goals

The strategy’s main goals are the development of a flexible and liquid LNG market and the creation of an LNG trading hub. Flexibility will be achieved by expanding spot trade and pricing that “properly reflects the actual supply and demand of LNG”. This will eventually create “an internationally recognised hub by the early 2020s”.

The three fundamental elements needed to achieve these goals are the enhancement of trade, the creation of a proper price-discovery mechanism, and open access to facilities. Legislation passed in 2015 will create third-party access to regasification terminals in 2017 and separation of network assets from supply businesses of the three major gas companies by 2022.

These aspirations may not seem particularly remarkable to those operating in liberalised gas markets, but they are revolutionary in the conservative world of Pacific LNG.

Publishing strategy could be said to be the easy part, of course. But to be fair the document addresses many of the difficult implementation issues and, although it stops short of suggesting direct intervention in commercial negotiations, it is evidence of a determination to put in place the regulatory elements to support liberalisation.


Destination clauses

Japanese utilities have long complained about what Europeans call territorial restrictions in long-term contracts that require cargoes to be delivered to the market of the purchaser. Even outside Japan, this has become highly problematic as demand in some markets has fallen short of anticipated requirements and buyers are obliged to take contracted volumes – to honour take-or-pay clauses – for which they may have no requirement.

Since 2011 it has inhibited trading between parties with surpluses, mostly in Europe, and those with shortages, mostly in Asia, when the price signal provided a strong incentive for cargoes to move to the Pacific.

This gave rise to the bizarre practice of reloading – unloading a cargo into a storage tank to comply with the clause in the long term contract and immediately reloading it on to the same ship for delivery elsewhere.

For the next few years, Japanese buyers are likely to have contracted quantities in excess of actual LNG demand, making elimination of destination clauses increasingly relevant.



Mindful of the widespread view that long-term contracts have traditionally been essential for new projects to be financed, METI has been bold enough to suggest that “it would be advisable for financial institutions to positively review their financing policy in response to current and future…changes”.

The government’s JBIC and NEXI financing policy will reflect the priority of moving towards shorter-term contracts and developing a liquid market. The strategy acknowledges that “at present, as LNG spot trading has yet to gain sufficient momentum, there are still no price indices that are widely accepted by market players”.

This recognises that the spot JOE prices, reported by METI since April 2014, have not been embraced by the market as a reliable indicator on which to base contract prices. METI would still like to see development of price indices based on specifically Japanese transactions.

Recognising the traditional confidentiality of the LNG business, it suggests that: “It may be important for both parties to permit anonymous information disclosure to an agreed PRA from the perspective of developing better indices.”

Further support for this process is provided by the provision that: “To increase the appropriate use of price indices, LNG trading contracts using such indices will be positively taken into account for evaluation of national interest by JBIC, NEXI and JOGMEC.”


Pacific Basin impact

Heavily influenced by this policy, the country’s single biggest LNG buyer JERA, a joint venture of Tokyo Electric and Chubu Electric, has already said that it favours a move to market prices, will diversify its purchase portfolio away from long-term contracts, will not sign any new contracts with destination clauses, and plans to renegotiate some of the terms of existing contracts.

To the extent that these initiatives are successful, it would be expected that other Japanese buyers will follow suit. But this raises questions about how the transition to a different pricing and contractual structure will be managed.

Any parties signing contracts for new LNG projects – which, given construction lead times, cannot start to deliver gas until the early 2020s – have been left in no doubt that price terms will need to be consistent with the evolving Japanese hub.

With the Singapore SGX already promoting its SLInG price, which has longer-term potential to evolve into a Southeast Asian hub price, and the Shanghai (Petroleum Exchange’s) hub trading small volumes of LNG, METI has arguably needed to scramble to catch up with events elsewhere in Asia.

However, the Japanese strategy is altogether more coherent, better argued and geographically more convincing than those of its competitors. Singapore is further advanced in terms of liberalisation and transparency, but is relatively small, with limited growth potential and geographically distant from major LNG markets.

Shanghai has huge potential volume and diversity of domestic and imported gas, but Chinese government policy in respect of market development is less clear, and it risks being considered open to manipulation by the three state-owned companies that dominate the gas market. However, there is no reason why these three hubs could not co-exist in the Pacific region – and develop strong price connections.

A truly liberalised Japanese gas market with prices determined at a physical hub, which could become virtual as and when greater national pipeline connectivity is established, is an entirely serious aspiration.

But timing is everything.

The strategy’s projection that the hub will be created only in the early 2020s is refreshingly realistic, in contrast to previous announcements of the launch of a futures market. But there is much to be done before the necessary conditions – including third-party access to LNG and pipeline infrastructure, transparency and establishing a wholesale gas price – are fulfilled.

These are essential for a trading hub with a trusted price discovery mechanism to emerge, particularly since separation of networks from supply will only be completed in 2022. But as we saw in continental Europe in the late 2000s and early 2010s, one of the most important changes needs to be in the mentality of established market players.

Once the latter accept that hub pricing will become the norm within a few years, they will start to position themselves to take advantage of – or at least not to lose out from – this new commercial environment.

Despite the financial battering to which electric utilities have been subjected following the closure and very slow reopening of their nuclear stations, the strategy has put all market players on notice that government will have little sympathy with those that fail to adapt to the new, competitive gas and power market.


Transition to hub pricing

It will clearly take time for competition to take hold in the Japanese gas market, but in relation to timescales for new LNG projects, the early 2020s is somewhere between tomorrow and the day after tomorrow. The immediate question is whether the market will manage a smooth transition to hub pricing.

Here, the strategy is somewhat less convincing: “In addition to collaboration with major LNG consumers, co-operation with LNG producers, such as Qatar, Australia, Russia, and the US is needed. Japan will contribute to discussions mainly at G7 meetings and LNG producer-consumer conference meetings and present concepts for an ideal LNG market…

“To further expand international co-operation, Japan will proactively communicate its approach in this field on such occasions as multinational meetings of the G20, APEC, and EAS, as well as at bilateral meetings with major LNG consumers in Asia and the European Union that have announced a policy prioritising LNG use.”

Co-operation with other consumers in Asia should be straightforward, if it means solidarity in switching to hub pricing and a trading mentality. But LNG exporters have been battered by price levels not seen since the early 2000s, especially those with major projects that required tens of billions of dollars of investment – capital costs substantially higher than originally planned – and that are starting or are due to start production in the period up to 2020.

These exporters may have little appetite for co-operation. They are trying to recoup as much money as they can from their traditional, JCC-based long-term contracts in a market where demand growth is currently much lower than was anticipated.

Offtakers locked into 20-year contracts for US LNG at Henry Hub plus prices may be similarly concerned as the so-called Asian Premium prices on which they were relying to cover their full costs have already disappeared and, with the emergence of hub pricing in Asia, are not likely to reappear.

This suggests to OIES that a period of commercial conflict over pricing – not unlike that experienced between continental European buyers and their suppliers since 2009 – is a more likely prospect.

Jonathan Stern is chairman and senior research fellow for the Oxford Institute for Energy Studies (OIES) natural gas research programme. Click here to read the full report



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