Since the middle of 2014, the Asian LNG market has seen oil prices tumble, an increase in supply courtesy of new projects coming on stream in Papua New Guinea and Australia’s east coast in particular (albeit partially offset by curtailment of supply from certain established sources), and sluggish demand.  While the demand picture is partly attributable to seasonal factors, longer term structural changes in Asian markets also appear to be playing their part.

This article takes a fresh look at where this has left buyers and sellers in their long term contract price negotiations, and possible implications for price review and flexibility arrangements under those new contracts.  We consider what role ongoing efforts to establish an Asian LNG trading hub, most notably by Singapore, might play.  And, relatedly, we query whether developments with China’s “One Belt, One Road” Initiative (Initiative) and the nascent Asian Infrastructure Investment Bank (AIIB) might provide renewed impetus for comprehensive natural gas pipeline connectivity in the ASEAN region and an opportunity for Singapore to enhance its hub plans and regional leadership.

A new paradigm for Asian LNG pricing?

In 2014, while growth in supply to China was lower than expected and South Korea’s imported volume decreased versus 2013, aggregate Asian LNG imports did in fact grow marginally, to an estimated 182 million tonnes.  This represented about 75% of global LNG trade.[1]  Despite emerging queries about what the International Energy Agency (IEA) termed the “Golden Age of Gas”, the consensus view remains that gas is a key part of the mix which can help meet Asia’s growing energy demands while transitioning away from more carbon-intensive fuels.  And vast growth in LNG supply to Asia (by far the majority of total supply) continues to be forecast. 

However, in recent years much attention has been paid to the so-called “Asian premium” – the higher price paid by Asian buyers (relative to western markets) under long term contracts which are traditionally linked to the price of oil and under which destinations are often limited through tight restrictions on diversions and resales to ports other than defined base ports.  During this time, buyers in Asia have been increasingly reluctant to execute new long term deals at oil-indexed prices.  Pricing has become a critical tension point.  Freezing gas into a liquid and shipping it in purpose-built vessels is, fundamentally, a highly capital-intensive exercise (as is receipt and regasification of LNG, to a lesser degree).  Floating and other small scale LNG production and floating storage & regasification units, each capable of being deployed more quickly and cheaply than larger scale land-based projects, may be part of the solution but this is likely to be at the margins.

Finding a way forward, whereby Asian buyers’ desires for lower priced gas are balanced with sellers’ needs for the security of long term sales at a value sufficient to underpin their significant capital investments, is paramount if anticipated Asian demand for LNG is to materialise and, just as importantly, new LNG projects are to be sanctioned to meet that demand.

Henry Hub indexation - the silver bullet?

The advent of the United States as a potentially significant LNG exporter has provided a genuine alternative to oil-indexed pricing.  Proponents of US-sourced supply offer exposure to US Henry Hub (HH) gas pricing and a greater level of destination flexibility compared with that to which Asian buyers have become accustomed under their existing oil-linked arrangements.[2] At recent HH pricing levels, HH-indexed LNG had appeared to be comparatively cheap.

The sort of flexibility offered under some of the new US-sourced supply cannot be discounted as part of the solution to the LNG price dilemma (provided that flexibility finds its way through to buyers at Asian terminals).  However, the recent drop in oil prices has made clear that HH-indexed pricing cannot be regarded as a panacea.  Suddenly, at least in the short term, oil-indexed pricing looks comparatively good again (of course, this is a matter of degrees given the variety of slopes and constants applied under different contracts) and Asian buyers have been left in something of a quandary.

The oil price drop serves to highlight the point that HH-indexing does not guarantee a relatively lower LNG price. Putting aside its relativity to the price of oil, HH pricing is a function of the US market for natural gas.  It fluctuates with supply and demand pressures in that market, prone to the impact of structural changes (including the advent of LNG export projects in themselves), the ebb and flow of seasonal demands and spikes for events such as the polar vortex in January 2014. With the limited exception of incremental demand caused by US Gulf Coast LNG projects coming on stream, none of these factors is reflective of the fundamentals in Asian markets. 

An Asian trading hub (or hubs) and associated gas or LNG price index?

Focus on the “Asian premium” for LNG has brought an equal amount of attention to the questions of whether and how one or more open and competitive trading hubs for LNG or gas might be developed in Asia.  And, indeed, efforts to develop such a hub are underway on various fronts.

While Singapore is not without stiff competition from the likes of Japan (which launched an over-the-counter (OTC) LNG futures market late in 2014), the IEA has highlighted the city state as the leading candidate, noting that a free-market approach to its power and natural gas markets are “cornerstones of the Singaporean energy policy”. [3] The open access, multi-user Singapore LNG (SLNG) terminal opened at Jurong Island in 2013 with an initial capacity of 3.5 million tonnes per annum (mtpa), subsequently expanded to 6 mtpa and a second jetty in 2014.  Development is already underway for a fourth tank and additional regasification facilities intended to take SLNG to 9 mtpa of capacity by 2017.  This capacity is far in excess of BG Group’s current exclusive aggregator franchise of 3 mtpa (and the next 1 mtpa of demand for which Singapore’s Energy Market Authority is in the midst of a tender process), facilitating the provision of storage and reload services and, with that, an increase in physical volumes delivered into and out of Singapore.  On the financial side (the other element necessary for development of a hub), Singapore has indicated it is working with Singapore Exchange (SGX) and other stakeholders to develop an LNG price marker.

However, each of the prospective proponents of gas/LNG trading hubs in the region, including Singapore, has significant challenges to overcome in order to realise its vision.  A key factor, largely outside of the proponents’ control, is liquidity and flexibility – that is the volume of spot LNG available in the market to facilitate trading.  The IEA estimates that, in 2011, as little as 8 to 10% of LNG (or 1% of global natural gas production) was traded on a true spot basis (although the greater destination flexibility associated with new US Gulf Coast supply may aid in changing this over time).  For Singapore specifically, the relatively limited size and number of players in its domestic gas market is another challenge.  However, we consider below a possible opportunity for Singapore to address these challenges in concert with its ASEAN neighbours. 

Certainly, with its status as one of the world’s biggest oil-trading hubs and with comprehensive commodities trading infrastructure already in place, Singapore’s ability to achieve its aim cannot be dismissed lightly, despite the challenges.  No doubt in part due to well-established incentives such as Singapore’s Global Trader Programme, as at September 2014 it was estimated that, already, about 25 LNG companies had established themselves in Singapore. [4] Nevertheless, any transition to an Asian gas/LNG trading hub is not likely to happen quickly (the IEA estimates that development of a hub is likely to take 10 years) and will not offer a short term solution to the price dilemma.

A large scale LNG project typically takes in the order of 5 years (sometimes much longer!) to move from final investment decision (FID) to first LNG production.  In the longer term, it may be that liquidity (and hubs) in the Asian and global LNG markets develop to a level which is sufficient for project proponents to proceed on the basis of market support.  However, at least for the medium term, long term foundation contracts remain a key element of the package needed to take FID on a project.  It is neither in buyers’ nor sellers’ interests to take a “wait and see” approach and suspend contract discussions pending further hub and gas/LNG index price developments.  That approach risks a short term demand-side “bust” (which would hurt sellers) ahead of a longer term supply crunch (due to delayed or cancelled FIDs for projects currently slated to respond to anticipated demand growth) and subsequent price “boom” (which would hurt buyers) - an outcome diametrically opposed to that currently sought by Asian buyers.

So where to from here for LNG sellers and Asian buyers?

The relational nature of long term LNG sale and purchase agreements, and the long lead times and capital-intensive nature of the LNG industry, mean that (at least at this juncture) buyers and sellers find themselves in a somewhat symbiotic relationship.  If the “Golden Age of Gas” trajectory is to be sustained in the face of the price dilemma, parties need to be collaborative and creative in their long term contract negotiations.  In this regard, negotiating parties have two key sets of levers available – price and flexibility. 

Price

As discussed above, oil- and HH-indexation are the choices broadly available to buyers and sellers (at least in the medium term).  Naturally, US projects have led the charge with HH-indexed supply.  However, oil-indexation still remains, by some distance, the dominant price mechanism.

The attraction of exposure to a spot price for gas in a very liquid market (and high oil prices driving the Asian premium in oil-indexed contracts) has driven great buyer interest in the HH-indexation alternative.  But oil-indexation does not necessarily mean “expensive” and HH-indexation is not necessarily “cheap” (in absolute or comparative terms). 

Parties will, of course, have their own (possibly divergent) views on future oil and HH price levels, which will inform their approach to the price discussions.  It is not yet clear whether the drop in oil prices will serve to bring oil-indexation back into favour and drive buyers and sellers closer together (which may happen if buyers take the view that the oil price drop is structural and long term and that higher oil-index slopes are acceptable as a result) or drive them further apart (a possibility if the price drop is considered to be temporary).

However, even where divergent views exist, negotiating parties have tools available to narrow (and hopefully close) the gap.  For instance, introducing an s-curve can help to provide both buyer and seller with some comfort about their LNG price within given oil-price ranges.  A number of deals have also been done on the basis of a hybrid of oil- and HH-indexation and more are sure to follow this path.  And, of course, parties can explore numerous combinations of slopes and constants.

Price reviews

Price review mechanisms, generally an important element of the price regime under a long term contract at the best of times, take on an even greater level of significance in the current environment.  Settling on an acceptable mechanism could prove to be the decisive factor in one or both parties having sufficient confidence to proceed on the basis of an initial price.

It is trite to say that there is no standard form of price review clause but that each should at least provide for (i) a trigger event (when can the price be reviewed), (ii) a framework for the price review (what aspects of the price can be reviewed/replaced and how any adjustment is applied), and (iii) what happens if the parties cannot agree (expert determination or dispute resolution, option to terminate, continuation with price unchanged, etc).  Parties must carefully consider the implications of proposed terms for these three elements (and the contractual drafting which reflects them).  However, each element represents an opportunity for creativity and closing deals.

Whatever the mechanism, as a general rule, both parties should be wary of agreeing a price review clause expressed in open “change of circumstance” terms and permitting a wide or unfettered scope of price review and adjustment to address the change in circumstances, particularly if that scope is coupled with provision for the matter ultimately to be determined by arbitration.  While often well-meaning (and sometimes used as a means of escape from difficult negotiations upfront), the European experience shows that such provisions can lead to arbitral price adjustment decisions (in the context of highly adversarial rather than cooperative processes) sometimes shifting billions of dollars of value to one party or the other.  Asian price reviews have traditionally been cooperative (certainly not litigious). However, a number of processes are underway, the nature of which indicate that this is starting to change.  At the same time, the English courts (English law often being the applicable law under Asian LNG sale and purchase agreements) are showing a greater preparedness to recognise and enforce the sorts of “good faith” type obligations which are often included in price review provisions.

If a price review is to be triggered by a change in circumstances, it is preferable for that change to be assessed by reference to an objective test (eg where a reference index moves outside of an agreed range, although such a test should allow short term fluctuations without triggering a review).  To prevent the possibility of constant reviews, consideration should be given to using a time based trigger instead of, or in addition to, a change of circumstances test (eg review permitted only following the 10th anniversary of the contract, or not more than twice during the contractual term).

Similarly, efforts should be made to define what aspects of the price are subject to review and the relevant benchmarks for that review.  For example, is the use of an index, or the index’s calculation, itself up for review or is it just a particular slope or constant? Is the assessment is to be made by reference to “comparable sales” and, if so, what makes a sale “comparable” (time of execution, geography, nature of parties, term of contract, etc) and how will the parties find that information given confidentiality of most long term contracts?

A third possibility for Asian long term LNG contract pricing (the first two being oil- and HH-indexation, as discussed above) may find its way into agreements through the price review mechanism.  That is, with a view to the possible development of one or more LNG trading hubs (and reference prices) in the medium term, the price review mechanism may open up the possibility of the price being adapted by reference to an appropriate “Asian hub” price which may develop after the contract is signed.

The need for caution is obviously heightened if the parties do elect to expressly include reference to a future “Asian hub” price, the nature of which is (by definition) not ascertainable in any real sense at the time of entering into the contract.  A conservative option would be to include a simple obligation to, on notice by either party, discuss and consider whether the contract price should be amended to take account of, or use, any “Asian hub” price which might develop through the term of the contract.  The provision might clarify that the parties are not obliged to agree a change.  It might also specify that the relevant hub price must be based on a given level of liquidity or have been in use for a given period before the obligation to discuss applies.  An arrangement such as this could augment a more comprehensive price review mechanism. 

Flexibility

As indicated above, it may not be price (and price review) alone which is a decisive factor in reaching agreement.  Both buyer and seller should value flexibility, albeit that the valuation may vary depending on the circumstances of the parties.

As noted, the destination flexibility in HH-indexed US Gulf Coast free on board (FOB) contracts has received much attention (although, in a number of cases, the buyers under those contracts are, or aspire to be, portfolio players – how much of their destination flexibility finds its way to end buyers remains to be seen).  

But there is more to “flexibility” than just an absence of a destination restriction clause.  Flexibility might also entail the extent to which things such as destinations, load sources, delivery windows, vessels and quantities (cargo and annual commitments) can be amended by the applicable party.  Particularly where the bottom line price is in issue, parties should not ignore the potential for incremental movements in these positions to help close the value gap.  

New impetus for the Trans-ASEAN Gas Pipeline and an opportunity for Singapore?

Earlier in this piece, we noted that global liquidity and flexibility of the LNG market and the relatively small size of its domestic market are two challenges Singapore needs (and, indeed, to the extent within its control, is already taking steps) to overcome in its quest to develop itself as an LNG trading hub.  As noted above, SLNG’s significant, and growing, LNG storage capacity may facilitate the development of a hub in which the size of the local market is not a significant factor – one instead focused on building LNG volume and trades through storage and reload (and break bulk) services.

But might there be another opportunity for Singapore (and the ASEAN region) in this regard?  Might efforts focused on LNG be combined with the development of comprehensive natural gas pipeline connectivity between ASEAN countries so as to harness the broader region’s gas and LNG supply and demand, and storage and terminal infrastructure?

Certainly this would be an ambitious plan.  Comprehensive ASEAN pipeline connectivity is not a novel concept.  The Trans-ASEAN Gas Pipeline project [5] (TAGP) was announced in 1999 and formalised by execution of a Memorandum of Understanding (MOU) in 2002.  However, progress on it has been slow – in relative terms, development of LNG import and export capacity has flourished in the region while pipeline connectivity has stalled (a number of transnational pipelines exist but these are generally only bilateral).  Article III (Cross Border Issues) of the MOU itself recognises many of the material challenges which need to be overcome – arrangements for non-discriminatory access and use, transit rights and jurisdiction, taxes and tariffs, and technical specifications are some key examples.  Further, gas is heavily subsidised in Malaysia and Indonesia – this kind of (unequal) market intervention across some ASEAN jurisdictions is another obstacle for the TAGP project and would need to be tackled if a hub based on regional connectivity and trade is to be developed.

While noting the significant challenges which face the TAGP, the IEA has recognised the opportunity to combine the project with Singapore’s efforts to establish an LNG trading hub.  It notes that the combination of a Singapore-driven hub and the TAGP, with a resultant “TAGP” reference price for gas, could, in itself, help to drive an end to the different price (subsidy) regimes in various ASEAN nations (which, as noted above, have proven to be an obstacle to the TAGP project and lead to internal and regional trade inefficiencies).[6]

One other key challenge for the TAGP project is its funding.  In this regard, China’s Initiative and the nascent China-led AIIB may represent important developments. A key plank in the Initiative is capital and technology investment by China into Southeast Asian infrastructure, to improve the circulation of resources and market integration and to facilitate efficient trade and investment in the region. With 57 countries having now joined the AIIB as founding members (including the likes of Australia and the United Kingdom), the bank is gathering real momentum.

The challenges for the TAGP project referred to above cannot be ignored. The easier path, of course, is to focus on single country developments (including an LNG trading hub based solely or primarily on Singapore’s own supply, demand and re-export capability).  However, the opportunities it presents (both for the development of a regional hub and in terms of the broader implications for economic development and integration of the ASEAN region) are arguably greater.  Moreover, they are precisely the sorts of challenges which must be addressed more broadly if the vision of an economically strong, vibrant and cohesive ASEAN region is to come to fruition. 

Whether through direct funding from the AIIB’s anticipated US$100 billion war chest or (perhaps more likely) indirectly, through the confidence which the bank’s establishment and China’s broader Initiative should inject in ASEAN nations and investors into the region, might it be that the TAGP project can be given fresh impetus?  Here again, as a leading global financial centre and investment gateway for the ASEAN region, Singapore would be well positioned to take the initiative as part of its hub development plans.