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    [Premium] Gas Trading Hubs in Asia: A Constrained Outlook

Summary

There is plenty of demand for LNG in southeast Asia but limited regional interconnections and politically different objectives prevent the development of a coherent market.

by: Tilak Doshi

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Natural Gas News, Asia/Oceania, Premium, Corporate, Exploration & Production, Import/Export, Political, Ministries, Intergovernmental agreements, News By Country, Southeast Asia

[Premium] Gas Trading Hubs in Asia: A Constrained Outlook

The most notable development in southeast Asia’s natural gas sector in the past few years has been the spate of new LNG regasification terminals that have been built, are under construction or are planned (Table 1). Governments of member countries of the Association of Southeast Asian Nations (Asean) see LNG imports as the best way to meet domestic energy requirements. Technological progress in the fabrication of floating LNG regasification terminals allows for even quicker turnaround times to first gas imports.[1]Among the countries in southeast Asia that have operating LNG import terminals are Indonesia, Malaysia, Singapore and Thailand; while the Philippines, Vietnam and Myanmar are planning to install them.

Table 1: Regional LNG regasification terminals 

Operating Regasification Terminals in Asean Countries

Country

Terminal Name

Year Started

Nameplate Capacity (MTPA)

Owners

Type

Thailand

Map Ta Phut

2011

5.0

PTT 100%

Onshore

Indonesia

Nusuntara

2012

3.8

Pertamina 60%      PGN 40%

Floating

Singapore

Singapore LNG

2013

6.0

EMA 100%

Onshore

Malaysia

Lekas LNG Malacca

2013

3.8

Petronas 100%

Offshore

Indonesia

Lampung LNG

2015

1.8

PGN 100%

Onshore

Indonesia

Arun LNG

2015

3.0

Pertamina 70% Regional Govt 30%

Onshore

Regasification Terminals under Construction in Asean Countries

Philippines

Pagbilao LNG

2017

3.0

Energy World 100%

Onshore

Malaysia

Pangerang LNG

2018

3.5

Petronas 65%  Others 35%

Onshore

Source: International Group of Liquefied Natural Gas Importers (GIIGNL), 2017 LNG Annual Report accessed at http://www.giignl.org/publications

Countries such as Indonesia, Philippines and Vietnam have long faced difficulties in supplying electricity to remote locations with relatively small demand loads. Small diesel generating sets are often the only alternative, as it is not economically viable to deliver natural gas by pipelines. The other traditional means of delivering natural gas, as LNG in large cryogenic carriers, would require a scale of operations – including large berths, storage capacity and vessels – far in excess of that needed for the countless islands and remote locations distributed across the southeast Asian archipelagos and long coastlines.

The demand for small scale LNG is poised to grow in the region as governments look to fuel smaller power plants and industrial developments in remote areas not connected to pipelines or the national grid with natural gas. This would reduce reliance on expensive diesel-fuelled power generation. Small scale LNG is also seen as a source of gas supplies for quickly ramping up electricity production, directly replacing household liquid petroleum gas (LPG) use or for direct supply to industry in remote areas and islands.

According to one study, it is estimated that by 2020, eastern Indonesia, the southern Philippines, and northern Vietnam could require over 120 small 50-MW power plants.[2] These power plants could require up to 60 small-scale LNG carriers to supply LNG to the region.[3]

Traditionally, the typical LNG project has bas been very large in terms of money and capacity. A typical-sized liquefaction train has a throughput of 5-7mn metric tons. The LNG is shipped in large cryogenic LNG carriers with 125,000 - 244,000 m³ of storage capacity. But over the past decade, technology has made small and medium-scale LNG projects economically viable. The industry defines small scale liquefaction and regasification facilities as plants with a capacity of less than 1mn mt/yr; small LNG carriers are those with capacity of less than 30,000 m³. Small scale storage of LNG in modular tanks with between 10,000 and 40,000 m³ capacity are now used. 

The often sparse and remote populations of Asean could make small-scale LNG the norm. For instance, Indonesian’s state energy firm Pertamina and state power firm PLN announced in 2011 that they plan to build eight “mini” LNG receiving terminals in eastern Indonesia, with a total capacity of 1.4mn mt/yr. As both demand and supply of LNG within the region become focused on smaller, quick start-up projects to exploit smaller stranded gas fields and to meet demand in remote or off-grid locations, intra-regional gas trade is likely to grow in the medium term. “Short haul” – under 1,500 nautical miles or three or four days’ sailing – covers distances from Singapore to Malaysia, Indonesia, the Philippines, Thailand, Myanmar, and Vietnam.

In Asia, gas sales contracts remain oil-indexed (usually to the Japan Custom-cleared Crude, or JCC, price which reflects the average price of crude oil imports into Japan). Asian LNG pricing relies on long-term, oil price-indexed export contracts, and hence it does not enjoy the diversification in its exposure to prices of the two fuels.

There is no Asia-Pacific Basin gas price index analogous to the real-time spot price determination at the UK's National Balancing Point (NBP) and US’ Henry Hub (in Louisiana) which serve the Atlantic Basin gas markets. US gas prices are set by “gas-on-gas” competition within the large but hitherto isolated North American market. In Europe, there is a progressive shift from oil indexation to spot-based pricing, particularly in northwest Europe, where spot gas trading hubs, such as the NBP and Title Transfer Facility (TTF) in the Netherlands, have displaced oil indexation.

It should be noted that the price reporting agency Platts (a division of S&P Global) tracks spot physical cargoes delivered ex-ship into Japan and South Korea via its “Japan Korea Marker” (JKM) price assessment. As the combined imports of LNG by these two countries constitute the largest share of total global LNG imports, the Platts JKM price constitutes a key reference in the Asian LNG spot market.

Vast new supplies of gas have been enabled by the “shale revolution” in the US as well as new LNG plants coming onstream in Australia and elsewhere. With a global surplus in natural gas supplies and relatively low LNG prices, gas sales contracts which used to be long term – typically 20 years or more – take-or-pay contracts are increasingly being replaced by shorter, more flexible contractual terms.

According to the International Gas Union (IGU), global spot and short-term LNG trades – defined as contracts that last no more than four years – rose from below 5% in 2000 to over a quarter of today’s global LNG sales.[4]  The increasing trend of new LNG vessels being ordered for construction on “speculation” – without underlying long-term charter deals to pay for such orders – will also boost the fleet availability for spot and short-term LNG cargo trades. If a significant spot and short-term trade in LNG cargoes were to develop in the region centred on a trading hub with adequate storage and trading liquidity, it could emerge as a source of price discovery for LNG cargoes in the wider region.

This, in turn, could have a significant impact on regional LNG sales and price-review negotiations, weakening the long-established link to an oil price index. Thus, the development of a regional hub for traded short-term LNG could lead to the emergence of an Asian gas-price index.

A number of Asian LNG importing countries plan to promote a “trading hub” as a means of encouraging liquidity and price discovery in the spot trading market for LNG in the region. For Japanese and South Korean utilities – among the world’s biggest buyers of LNG – the creation of a liquid LNG trading hub will allow them to purchase cargoes of specific sizes at short notice and would allow them a basis to hedge their price exposure.[5] Japan, China, and Singapore are now developing regional trading hubs in Asia Pacific markets and have launched LNG pricing indexes to increase transparency in price discovery.[6] For example, the Japanese government has developed a comprehensive strategy to liberalise its domestic natural gas market with major initiatives to encourage private-sector participation in the development of an LNG trading hub and a pricing index.[7]

Japan’s Fair Trade Commission last year outlawed resale restrictions and destination clauses in long-term LNG contracts that could fundamentally shift how LNG is contracted and traded in Asia.[8] All three countries have established benchmark LNG pricing indexes and announced various financial instruments to be traded on domestic commodity exchanges to encourage LNG price discovery and transparency.

The Singapore government has vigorously supported the development of an LNG trading hub by constructing the region’s first multi-user LNG import, storage, and regasification terminal and putting in place the necessary regulatory framework.[9] The government will allow the leasing of capacity in its third tank for trading purposes. As an incentive, the government introduced a concessionary tax rate of 5% on LNG trading income for companies under the Global Trader Programme (GTP) in May 2007.[10] SLNG, the terminal operator, sees a rise in small regasification and storage terminals for off-grid power generation in the region as an opportunity to develop short-haul trading opportunities in the southeast Asian region.[11] The terminal would provide the flexibility to barge small volumes of LNG, of between 10,000 m³ to 40,000 m³, to remote markets intra-regionally.

As floating liquefaction becomes more widespread in the region, output from smaller gas fields in the region could also be aggregated in the Singapore terminal for distribution to other markets.

Success will, of course, depend on a number of factors that are not within Singapore’s control: it has a small domestic gas market and southeast Asia lacks a regional pipeline network which would allow for flexible cross-border flows.

The impacts of a small domestic market and the lack of a regional gas pipeline network are worsened by the policy to limit the quantity of LNG imported into Singapore as spot cargoes to 10% of the total imported. Arguably, this cap would limit liquidity when long-term contracted LNG demand growth in Singapore is not expected to grow rapidly. The development of the small-scale LNG for intra-regional trade in Asean will be a relatively long term process. Given the on-going delays in building regasification terminals for receiving imported LNG in Myanmar, Indonesia, Vietnam and the Philippines, it could easily take a decade or longer before it becomes clear whether regional trade will be adequate for a regional LNG trading hub to flourish.

This outlook assumes that protectionist barriers to trade in LNG do not constrain the development of a Singapore trading hub. In Asean as elsewhere, the pressure on government agencies to promote domestic industrial development in the natural resource extractive sector through protectionist legislation is well researched.[12] In the specific case of LNG, this is apparent in the recent statements by Indonesian authorities that a non-binding heads of agreement they signed with Singapore “did not mean that they were going to buy LNG from Singapore”.[13]

Thus, it is expected that some Asean member countries would require the local fabrication of components in the small scale LNG value chain. There are potential developments that could help in integrating LNG trading in Asean – for example, Malaysia and Indonesia could import LNG via Singapore’s LNG regasification terminal by reversing the existing natural gas pipelines connecting both countries to Singapore.

But most industry observers are sceptical of the prospects for pipeline reversal, given the protectionist impulse in government policy. Economic nationalism favour policies that support the domestic location of the LNG logistics chain even if they are more expensive than using the existing facilities at the Singapore LNG import terminal.

The proposed LNG market hubs in Japan, China, and Singapore face considerable challenges. In particular, the lack of third-party access to infrastructure and limited pipeline connectivity within and between countries pose constraints to trade and hence LNG price discovery.

The vast majority of Asian LNG trade in short-term contracts and spot cargoes are focused in northeast Asia where the largest LNG importers such as Japan, South Korea and China are.[14] Northeast Asian LNG importers as well as other large LNG importers in the region such as India can source spot market cargoes directly from Europe, Australia and the Middle East without the need of a trading hub.

Conclusions

Despite a large literature on the imperatives for promoting Asean regional economic integration, it is important to note that there is nothing in economic theory that favours “regional” economic integration over other paths to economic development.

Southeast Asian intra-regional trade and investment have played a relatively minor role in the economic fortunes of the Asean countries, often far more integrated with the centres of industrial development in Europe and the US until well into the post-War period; in some cases, up to the present day.

 In the case of the natural gas sector in Asean the direction of development is thus towards less regional integration. While cross-border piped gas flows in southeast Asia are increasingly supply-constrained, more countries plan to build re-gasification facilities to directly import LNG from global markets.

Gas trade is well developed in the US Gulf Coast and parts of Europe: they have a sufficiently dense pipeline network, connecting gas fields in the North Sea and Russia to European markets; or Canada to the US markets for instance.

In southeast Asia, the existing gas pipelines mainly serve to connect offshore or on-shore gas fields to supply domestic markets or liquefaction plants (in Indonesia, Malaysia and Brunei) to export LNG to international markets. There are a few cross-border gas pipelines such as those supplying Malaysian and Indonesian gas to Singapore or Myanmar to Thailand; but they account for a small share of total gas demand or exports of southeast Asia.

All large scale multi-lateral infrastructure projects face critical hurdles in the financing, construction, operation and maintenance of networks. The much-discussed Trans-AseanAsean Gas Pipeline (TAGP) project is no different, facing key challenges in all these dimensions: contractual, legal and political. Quite apart from the inherent challenges that all large-scale multilateral cross-border infrastructure projects face, it now also faces a more basic question of relevance.

Since the mid-1980s when TAGP was first discussed, its prospects are now subject to natural gas supply and demand fundamentals that have changed profoundly. If the TAGP project seemed over-ambitious, it now seems that the grand vision of a regionally-interconnected grid has been overtaken by fast-paced developments in the natural gas industry over the past decade or so.

Singapore’s potential role as an LNG trading hub is far from assured, given that the vast majority of Asian trade in short-term and spot LNG cargoes are focused in northeast Asia where the largest LNG importers such as Japan, South Korea and China are. While small scale LNG trade in the region will take some time to develop, the protectionist approach of some of the Asean member economies may constrain the closer integration of their natural gas markets.

 

Tilak K Doshi, Managing Consultant,

Muse, Stancil & Co.

 

 



[1] See, for instance, IEA, 2011. “The Golden Age of Gas: a special report”, accessed at http://www.iea.org/weo/docs/weo2011/WEO2011_GoldenAgeofGasReport.pdf

[2] These findings came from the Joint Industry Project, or JIP, initiated by DNV during Singapore Maritime Week in 2010, and which involved sixteen participants from the LNG industry. See Karen Boman, “Study Examines Prospects for Small Scale LNG in SE Asia”, Downstream Today, 24 March 2011

[3] LNG vessels of standard size (~140,000 m3) and newer larger carriers (up to 270,000 m3) have been the mainstay of long-term LNG sales. Short haul, small LNG carriers of 10,000–30,000 m3 (or even smaller) operate in parts of Europe and Japan for short sailing times and coastal LNG transportation.

[4] International Gas Union (IGU), “2017 World LNG Report” accessed at https://www.igu.org/ .

[5] Henning Gloystein and Osamu Tsukimori, 2016. “Asian exchanges set to hit the gas on LNG trading”, Reuters,

November 25, 2016.

[6] US Energy Information Administration, 2017. “Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region”, March 2017.

[7]  Mike Corkhill, 2016. “Japan prepares for global LNG hub role”, LNG Shipping, 12 May 2016

[8] Robin Harding and David Sheppard, 2017. “Japan outlaws restrictions on resale of LNG cargoes”, Financial Times, June 28, 2017

[9] Tilak K. Doshi, 2015. Singapore in a Post-Kyoto World: Energy, Environment and the Economy, Institute of Southeast Asian Studies, Singapore.

[10] Ministry of Trade and Industry Singapore, “National Energy Policy Report: LNG Trading” (Singapore: MTI, 2007), p. 61.

[11] “Singapore Sets Sights on LNG Hub”, Petroleum Economist, 22 March 2011.

[12] For instance, see Doshi, Tilak K. “Supply Side Perspectives: Cooperation and Competition in the Extractive Industries (EI) Sector”, PECC Signature Project: Extractive Industries Project, 2014 accessed at

http://www.pecc.org/resources/minerals-a-energy/2158-cooperation-and-competition-in-the-extractive-industries-sector-perspectives-from-demand-and-supply-sides

[13] Francis Chan, 2017. “Indonesia 'not buying LNG from Singapore'”, The Straits Times, September 16, 2017.

[14] Japan and South Korea together accounted for over half of all LNG consumed in the world in 2015. See BP, 2016, “Statistical Review of World Energy 2015”, accessed at http://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html