Perspectives on the Development 

of LNG Market Hubs in the Asia

Pacific Region

March 2017

Independent Statistics & Analysis

www.eia.gov

U.S. Department of Energy

Washington, DC 20585
U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region i

This report was prepared by the U.S. Energy Information Administration (EIA), the statistical and 

analytical agency within the U.S. Department of Energy. By law, EIA’s data, analyses, and forecasts are 

independent of approval by any other officer or employee of the United States Government. The views 

in this report therefore should not be construed as representing those of the U.S. Department of Energy 

or other federal agencies.
March 2017

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 1

Introduction

This report was prepared by ICF International, Inc. under contract to the U.S. Energy Information 

Administration (EIA). The report discusses current initiatives to establish regional liquefied natural gas 

(LNG) trading hubs and pricing benchmarks in Asia and assesses the prospects for the Asian gas hubs in 

the near future. The report examines the characteristics of successful natural gas trading hubs and 

develops qualitative and quantitative indicators of the components of effective hubs, with emphasis on 

applying these indicators to Asian markets.

As the global LNG market continues to grow and as liquidity increases in part as a result of U.S. 

participation, EIA’s aim is to better understand the interplay between U.S. LNG exports and international 

natural gas prices. This understanding will inform EIA’s international energy models and its outlook for 

the development of world natural gas markets.

Historically, effective market pricing points (referred to as market hubs) emerged in North America 

following the deregulation of natural gas commodity markets and the development of an extensive 

natural gas pipeline network. As natural gas markets have become less regulated in other parts of the 

world, notably Europe and the United Kingdom, market pricing hubs have emerged in those areas. 

The large Asian markets (Japan, South Korea, Taiwan, and to a lesser degree China and India) have 

traditionally relied on LNG, which has been priced under long-term contracts tied to crude oil prices. 

With significant expansion of the global liquefaction capacity (primarily from new projects in Australia 

and the United States) and changes to LNG contracting, a more market-sensitive trade in LNG is 

emerging. However, Asia does not have a fully functioning pricing point that can reliably transmit price 

signals to the market. Development of reliable pricing indexes and market hubs in Asian countries that 

reflect the underlying demand-supply fundamentals becomes increasingly important as global natural 

gas markets evolve and mature. 

Global liquefaction capacity is projected to increase by one-third by 2020. In recent years, high oil 

prices and rapid growth in natural gas demand (primarily in Asia) spurred major investments in the 

global export capacity of LNG. As a result, global LNG export capacity is projected to increase by onethird by 2020, with most of the new capacity located in Australia and the United States. Once all 

liquefaction projects currently under construction come online, the United States is projected to have 

the world’s third-largest LNG export capacity. 

U.S. LNG exports will increase liquidity in global LNG trade and enhance supply security. The large U.S. 

LNG export capacity, combined with destination flexibility in the off-take contracts, will result in a 

greater liquidity in global LNG trade. The growth in liquidity will lead to a gradual shift away from longterm, oil-linked contract pricing toward more short-term, spot-based transactions. These changes will 

underscore the need for transparent and reliable regional LNG pricing indexes and trading hubs, 

particularly in Asia. 

Asian markets lack a transparent pricing benchmark. Although Asia is the major natural gas-consuming 

region (accounting for one-third of the global natural gas trade and three-quarters of the global LNG 

trade), the region lacks a liquid and transparent LNG pricing benchmark similar to the Henry Hub in the 
March 2017

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 2

United States or the National Balancing Point in the United Kingdom. Asian LNG consumers have 

historically relied on long-term contracts to guarantee the security of supply because they lack 

indigenous natural gas resources and have limited access to pipeline trade. Increasing volumes of 

flexible LNG supply in the region will lead to more liquid LNG trading in Asia. 

Multiple initiatives are underway to facilitate price discovery in Asian LNG markets. Japan, China, and 

Singapore are now developing regional trading hubs in Asia Pacific markets and have launched LNG 

pricing indexes to increase the transparency in price formation. For example, the Japanese government 

developed a comprehensive strategy to liberalize its domestic natural gas market and launched major 

initiatives to encourage private-sector participation in the development of an LNG trading hub and a 

pricing index. Japan’s Fair Trade Commission is now probing resale restrictions in long-term LNG 

contracts that could fundamentally shift how LNG is contracted and traded. All three countries have 

established benchmark LNG pricing indexes and announced various financial instruments to be traded 

on domestic exchanges to encourage LNG price discovery and transparency.

The formation of functional natural gas market hubs in Asia Pacific will take time. In the United States 

and Europe, the development of natural gas hubs and pricing indexes took 15 years and 10 years, 

respectively. Each of the proposed LNG market hubs in Japan, China, and Singapore faces considerable 

regulatory and infrastructure challenges, including lack of third-party access to infrastructure and 

limited pipeline connectivity within and between countries. To attract multiple participants and reduce 

possible dominance of large, incumbent players, market liberalization will be necessary, including a 

regulatory environment that assures equal third-party access to natural gas infrastructure (pipelines, 

regasification facilities, storage, etc.) and promotes transparent LNG pricing based on demand and 

supply fundamentals.

As the global LNG market continues to evolve and mature, reliable pricing indexes and market hubs in 

Asian countries will fundamentally transform the global LNG market into a more efficient, integrated, 

and transparent market.
Perspectives on the Development 

of LNG Market Hubs in the Asia 

Pacific Region

November 2016

Independent Statistics & Analysis

www.eia.gov

U.S. Department of Energy

Washington, DC 20585

Prepared by ICF 

Fairfax, VA

Under contract to Z, INC.
November 2016

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region i

Acknowledgements

This report was prepared by ICF under contract to Z, INC for the U.S. Energy Information Administration 

(EIA). 

Information concerning the content of this report may be obtained from Victoria Zaretskaya, 

(Victoria.Zaretskaya@eia.gov) and Mindi Farber-DeAnda (Mindi.Farber-DeAnda@eia.gov). 

ICF acknowledges the valuable contribution of LNG market experts David Carlson and Jinyu Cheong at 

the Singapore Exchange (SGX); Heloise Capon and Shelly Kerr of S&P Global; and Ruth Liao and Ben 

Wetherall at ICIS Heren.

Principal contributors from ICF are Leonard Crook, E. Harry Vidas, Cecelia Coffey and Natalie Amarin. 

This report was prepared by the U.S. Energy Information Administration (EIA), the statistical and 

analytical agency within the U.S. Department of Energy. By law, EIA’s data, analyses, and forecasts are 

independent of approval by any other officer or employee of the United States Government. The views 

in this report therefore should not be construed as representing those of the U.S. Department of Energy 

or other federal agencies.
November 2016

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region ii

Table of Contents

Table of Contents.......................................................................................................................................... ii

1 Executive Summary ...............................................................................................................................1

2 Introduction...........................................................................................................................................7

3 Market Hub Economics and Characteristics..........................................................................................9

4 Market Hubs in the United States and Canada ...................................................................................13

4.1 Background...............................................................................................................................13

4.2 Henry Hub and Select Hubs in North America..........................................................................14

4.3 Liquidity and the Churn Rate in the United States...................................................................15

4.4 Observations on U.S. and Canadian Hub Development...........................................................16

5 Market Hubs in Europe........................................................................................................................17

5.1 Overview of the European Gas Market....................................................................................17

5.1.1 Gas Market Reform in the United Kingdom...........................................................................17

5.1.2 Gas Market Reform in Europe................................................................................................18

5.1.3 European Gas Market Today..................................................................................................18

5.2 Key European Hubs...................................................................................................................20

5.2.1 Austria Central European Gas Hub (CEGH).........................................................................21

5.2.2 Belgium Zeebrugge Hub (ZEE).............................................................................................21

5.2.3 France Trading Region South (TRS) and Point d’Exchange Nord (PEG Nord) .....................22

5.2.4 National Connect Germany (NCG)......................................................................................22

5.2.5 Germany Gaspool (GPL)......................................................................................................23

5.2.6 Italy Punto di Scambio Virtuale (PSV) .................................................................................23

5.2.7 Netherlands Title Transfer Facility (TTF).............................................................................23

5.2.8 Spain Mercado Ibérico Del Gas (MIBGAS) ..........................................................................24

5.2.9 United Kingdom National Balancing Point (NBP)................................................................24

5.3 Price Convergence at Major European Hubs............................................................................25

5.4 Observations on European Hub Development.........................................................................26

6 Asia Pacific Gas Market........................................................................................................................28

6.1 LNG and the Asia-Pacific Gas Market .......................................................................................28

6.2 Natural Gas Prices and Price Formation...................................................................................32

6.3 Conditions for the Development of a Natural Gas Market Hub in Asia ...................................34

7 Market Hub and Price Index Developments in Asia Pacific.................................................................36
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region iii

7.1 Market Hub Developments ......................................................................................................36

7.1.1 Japan ...................................................................................................................................36

7.1.2 China-Shanghai ...................................................................................................................39

7.1.3 Singapore ............................................................................................................................41

7.1.4 Summary of Asia-Pacific Hub Developments......................................................................41

7.2 Indexes Tracking LNG Prices in Asia Pacific ..............................................................................41

7.2.1 Japan Monthly LNG Spot.....................................................................................................41

7.2.2 East Asian Index (EAX).........................................................................................................42

7.2.3 Japan Korea Marker (JKMTM)...............................................................................................42

7.2.4 SGX LNG Index Group (SLInG).............................................................................................43

7.2.5 Other LNG Indexes..............................................................................................................43

7.2.6 Comparison of Asia-Pacific LNG Indexes.............................................................................44

7.2.7 Prospects for an Asia-Pacific Gas Market Hub in Japan..................................................47

7.3 Summary Observations ............................................................................................................49

Appendix A. Acronyms................................................................................................................................53

Appendix B. Key Terms and Definitions......................................................................................................55

Appendix C. Churn Rate Analysis................................................................................................................58

Appendix D. Gas Price Formation in Japan and China ................................................................................60

D.1 Japanese Custom Crude Clearing (JCC) formula.......................................................................60

D.2 China Pricing Formula...............................................................................................................60
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region iv

List of Tables

Table 3-1. Stages of development of market hubs.....................................................................................10

Table 4-1. North American natural gas hub metrics...................................................................................14

Table 4-2. Example calculation of natural gas churn ratio for the United States.......................................16

Table 5-1. Natural gas balances for select European countries, 2015........................................................19

Table 5-2. Metrics for select European gas trading hubs...........................................................................21

Table 6-1. Natural gas balances for select Asia-Pacific countries, 2015.....................................................28

Table 6-2. Global LNG imports by region....................................................................................................29

Table 6-3. Largest LNG exporting countries, 2015......................................................................................29

Table 7-1. Characteristics of Asia-Pacific LNG price indexes ......................................................................45

Table 7-2. Comparing Asia-Pacific gas market maturity to U.S. and European development ...................50

Table C-1. Physical gas trades reported for 2015 to FERC and PREs..........................................................59

List of Figures

Figure 1-1. Stages of gas market hub development.....................................................................................1

Figure 5-1. Price movements at European hubs, January 2014–October 2016 .........................................26

Figure 6-1. World LNG trade by contract duration, 2000–2015.................................................................30

Figure 6-2. LNG contracted volumes and contract expirations..................................................................31

Figure 6-3. Selected annual average prices for gas and LNG, 2000–2015..................................................33

Figure 7-1. Japan’s natural gas infrastructure, 2015 ..................................................................................36

Figure 7-2. Price of LNG imported to China (Shanghai), 2016....................................................................40

Figure 7-3. Comparison of price indexes for spot LNG in Asia Pacific, 2014–16 ........................................46
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 1

1 Executive Summary

Natural gas market hubs have been a key feature of competitive gas markets in the United States, the 

United Kingdom, and Europe. These hubs provide physical locations for trading gas and ultimately for 

price discovery of natural gas sold in the hub. The most important hubs have publicly reported price 

indexes that are benchmarks for the value of gas in the larger market. These price indexes in turn form 

the basis for futures contracts and for managing price risk. 

With Asia Pacific as the world’s largest liquefied natural gas (LNG) consuming region, governments in the 

region have sought to liberalize their domestic markets to promote competitive LNG trading that can 

provide price discovery for LNG. This report examines the development of gas market hubs in North 

America and Europe to evaluate whether such hubs are likely to develop in Asia Pacific. 

The key stages of maturity in natural gas hub development are illustrated in Figure 1-1. The history of 

gas market hubs indicates that there are certain prerequisites necessary for market hubs to develop. A 

robust natural gas infrastructure is presumed. Gas market deregulation allowing prices to reflect supply 

and demand and third-party access (TPA) to transport facilities is also necessary. 

Figure 1-1. Stages of gas market hub development

Fully mature gas market hubs have many independent buyers and sellers, open access to transport 

facilities, trading liquidity, and clear and transparent price and volume reporting by price reporting 

entities (PREs). The reported prices can become indexes of market conditions at the hubs and attract 

non-physical traders who increase the market liquidity. The most successful hubs are liquid trading 

centers with many buyers and sellers buying and selling gas. These hubs can become the locus of 

financial futures contracts and ultimately a liquid forward price curve that allows for price discovery 

months and years into the future. 

The first natural gas hubs emerged in the United States in the 1990s. Market reforms initiated by the 

Federal Energy Regulatory Commission (FERC) promoted competitive gas markets and specifically 

encouraged the development of “market centers.” The United Kingdom and the European Union 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 2

subsequently began market reforms that also led to the development of gas market hubs. Henry Hub in 

the United States is the most successful gas market hub with a large, liquid futures market linked to the 

price index at the hub, which serves as a benchmark indicator of the value of gas in the United States. 

Benchmark pricing is also provided in the United Kingdom at the National Balancing Point (NBP) and the 

Netherlands at the Title Transfer Facility (TTF), although neither has a forward price curve as liquid as 

Henry Hub. 

These gas market hubs in the United States and in Europe are connected with natural gas pipeline 

systems that provide for continuous supply and trading as gas flows through the system. The Asia Pacific 

presents unique problems for hub development, given its geography, its reliance on LNG, and the 

relatively large ship-size volumes typical of LNG contracts and deliveries to regasification terminals. 

None of the major Asia Pacific LNG importing countries has a robust domestic market with fully 

deregulated gas prices and TPA. The traditional LNG contract structures contain long-term 

commitments, LNG prices linked to oil prices, and re-delivery restrictions that limit the buyer’s option to 

sell unneeded LNG to other markets. 

LNG markets are undergoing significant changes as a consequence of softening demand in Asia Pacific, a 

growing LNG supply, and lower oil prices. These conditions have encouraged the growth in spot LNG 

trading, shorter-term contracts, and pressure to modify destination clauses in LNG contracts. The 

governments of Japan, China, and Singapore have recognized the importance of creating gas market 

hubs for the purpose of price discovery and are each taking steps to promote such LNG market hubs. 

Japan’s Ministry of Economy, Trade and Industry has announced a strategy to promote the liberalization 

of the domestic gas market, which is tied to the development of a Japanese LNG market hub. The 

government of Japan will follow policies to encourage private sector parties to develop a trading hub. 

The Japanese strategy provides a coherent way forward to create the conditions for an LNG market hub. 

China has encouraged the development of a gas trading hub centered on Shanghai and private entities 

have begun reporting prices there. Chinese gas prices are heavily regulated and the outlook for a 

successful gas hub developing there in the near future is dim. 

Singapore has developed infrastructure to accommodate LNG delivery and storage and has a fully 

deregulated gas market. However, efforts to create a hub at Singapore must address the fact that it is a 

small market. 

A number of PREs (Platts, Argus Media, ICIS Heren, and others) have begun reporting spot LNG prices in 

Asia Pacific and have developed their own price indexes. Several exchanges also offer LNG futures 

contracts (although, there has been limited trading activity to-date). What is noteworthy is that the 

reported indexes are not founded on specific gas market hubs, but rather, on general LNG market 

trading across the Asia Pacific region. The price indexes rely on voluntary reporting by market 

participants for which PREs have established protocols for ensuring the consistency and reliability of 

reported prices. With the exception of the Platts Japan Korea Market (JKM) index, there appear to be 

few trades tied to these indexes. Nevertheless, these LNG indexes are likely to remain the most reliable 

indicator of natural gas market value in Asia Pacific. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 3

Key metrics of market hubs as they apply to countries in Asia Pacific are summarized below. 

Successful Gas Market Hubs are Highly Liquid

Fully developed gas market hubs have many independent buyers and sellers, open access to transport 

facilities, significant trading volume, and clear and transparent price and volume reporting – all of which 

allow for high liquidity. A market hub can be a specific location, like Henry Hub, or a notional hub that 

reflects a trades over a defined network. Examples of notional hubs are Canada’s AECO-C in Alberta, the 

National Balancing Point (NBP) in the United Kingdom, or the Title Transfer Facility (TTF) in the 

Netherlands. Other hubs can exist which serve many of the same functions of market hubs but do not 

have the liquidity to create pricing information adequate for indexation. The presence of an active 

futures market tied to a price index provides confirmation for the pricing reliability of the market hub 

and its index. 

Besides Henry Hub in Louisiana, the North American market has a number of other hubs with high 

liquidity, index pricing, and futures contracting. The regulatory reforms in the U.S. market that helped 

create the conditions for the emergence of gas market hubs included de-regulation of gas commodity 

prices, the unbundling of sales versus transport services, and open third party access to transportation. 

Preceding these reforms was a period of market upheaval, including excess supply that resulted in 

pressures on traditional ways of doing business (not unlike the events in Asia Pacific today).

Regulatory Reforms and Sufficient Physical Infrastructure are Critical Enablers of Hub Development

Market hubs in Europe grew out of regulatory reforms in the United Kingdom and later directives from 

the European Union to encourage competition in gas markets. The full development of gas market hubs 

in Europe has been slower than in the United States due to varying regulations and industry organization 

across the countries of the European Union. The expansion of large, transnational pipeline systems has 

progressed relatively recently, allowing regionally-interconnected networks to create opportunities for 

custody transfers of gas that facilitate the balancing of European gas markets and the propagation of 

price information. With price discovery occurring at key hubs like the NBP and the TTF, futures contracts 

have been developed and are traded in those locales. 

Although both North America and Europe have markets that are pipeline based, pipelines in Asia Pacific 

are limited to the countries themselves, the exception being Southeast Asia where transnational 

pipelines connect several countries and China with interconnections to other parts of continental Asia. 

The distinguishing feature in Asia Pacific is the LNG trade, which is the major component of gas supply. 

Three countries are vying to become the LNG hub for Asia Pacific – Japan, Singapore, and China 

(Shanghai). Efforts are underway in each of these countries to create the conditions whereby markets 

through the interactions of many buyers and sellers determine gas prices. 

LNG Price Discovery Exhibits Unique Challenges in Addition to those Surrounding Trading Hub 

Development

LNG price discovery presents a number of challenges to the pipeline-based model of market hub and 

price index development. This model relies on more or less continuous flows of gas, daily scheduling of 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 4

receipts and deliveries, homogeneity of product, uniform transportation and contracting rules, and 

diligent regulatory oversight. In contrast, LNG shipments are large and lumpy; there can be significant 

time between contracting and delivery; cargoes can differ in LNG specifications; LNG import terminals 

have limited interconnectivity, and bi-lateral contracts set the operating rules, not government 

regulation. 

Nevertheless, this study has found that the contracting regime for Asia Pacific LNG trading is rapidly 

changing in important ways. Long-term contracts are becoming shorter; there are more medium and 

short term deals, the latter defined as less than two years. There is more interest in breaking the 

destination clause restrictions thus allowing more contracted supply to be diverted to other terminals in 

response to market needs. There is some spot market contracting, but it appears to still be a small part 

of the market. Pricing terms are also changing with the addition of hybrid pricing terms: some deals are 

linked to spot indexes, such as Henry Hub, or sometimes to local price indexes, in addition to traditional 

linkages to various oil indexes, or a combination of all of these. 

There are also two publically available spot LNG indexes developed by Japan’s Ministry of Economy, 

Trade, and Industry and a free-of-charge index published by Singapore Exchange (SGX) reflecting a 

Singapore FOB price for LNG. All of these reported index prices are derived from actual trades that are 

adjusted in some fashion to create more transparent and consistent price index. In some cases, the 

indexes may also contain bid and ask offers or hypothetical trades based on known origin prices and 

transportation costs between the origin and destination points. LNG traders may use one or more of 

these price indexes to price gas by formula. Other than anecdotes, there is no solid information on 

which of these indexes is being used by traders. The JKM index was most frequently mentioned during 

interviews as being one that is used by traders to price deals. Nevertheless, oil-based contracting 

dominates, which is understandable given the liquidity of the oil markets and the ability to hedge on the 

oil indexes. 

No Location in Asia Pacific has a Sufficiently Developed Physical or Regulatory System to Promote the 

Imminent Creation of a Trading Hub

The research undertaken for this report suggests the market pre-conditions do not currently exist to 

allow Japan, China (Shanghai), or Singapore to be fully liberalized markets where natural gas prices are 

efficiently and transparently determined by supply and demand. Japan is just now moving towards 

liberalizing its internal gas market and has a limited network connectivity for internal trading of gas. 

China’s pricing regime has different price determinations for pipeline and LNG supply and limited 

communication between the two systems. Singapore, as noted before, is a small market and the 

surrounding countries markets still operate under price controls. Therefore, we do not see an Asian 

market hub evolving in the near-term with a liquid market capable of producing a reliable price index 

that can be used for Asia-wide or reginal transactions. 

However, spot and short-term Asian LNG trade does appear to be liquid enough to provide adequate 

price discovery and indexation, but with caveats. It is a large market operating over a transportation 

network of LNG tankers, under conditions akin to “open access” rules, where bi-lateral negotiations set 

prices parties will pay on fixed price basis or with formulas linked to oil or gas indexes. And there are a 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 5

variety of entities reporting prices and trading activity. On the other hand, Asia Pacific is vast, with the 

major markets operating under very different legal and economic conditions. Access to regasification 

terminals are not open to third parties for the most part. Transport costs within the region, though 

transparent are significant. This requires indexes at multiple locations or corrections to put a single 

index into a common locational basis.

Japan’s National Policy Directives May Outline a Way Forward for LNG Hub Development in Asia

The outlook for a Japan trading hub is uncertain, yet market liberalization and price index formation 

have set the country on a track toward the development of a larger, more liquid trading hub. Japan’s 

Ministry of Economy, Trade and Industry (METI) has summarized the essential problem well in its 2016 

Strategy for LNG Market Development. For a market hub to be developed, there needs to be a much 

more robust trade in physical LNG on a spot market. A more robust trade depends on greater flexibility 

in LNG commercial operations. At the same time, a spot market must have some way of identifying a 

market price in order to develop. The Government of Japan seems intent on promoting a Japanese 

market index for LNG and is encouraging private sector activities for the development of a market hub 

upon which such an index could be developed and led by the private sector. 

While the ideal achievement of a large, liquid hub with low transaction costs may still be a decade or 

more away, steps may be taken today to facilitate greater market development. These include 

establishing a standard for gas quality (heat content), expanding regional gas transport infrastructure so 

as to facilitate greater intra-national trade, and establishing forms of market oversight and cost recovery 

that allow for consistent third-party access both to infrastructure and to markets. Several barriers to hub 

development remain in Japan, including a status quo of legacy, long-term contracts that would need to 

be replaced with spot trading. Other barriers include the physical need for greater LNG transportation 

and storage capacity within Japan, as well as resistance from market players who fear losing their 

investments in the existing market structure, were a major gas market liberalization to be accomplished. 

Despite these barriers, greater price transparency provided by a number of LNG price indexes that have 

been developed in the Asia Pacific region and the commitment of METI to support market restructuring 

have established Japan as a regional leader in the development of a larger, more liquid LNG trading hub. 

LNG Indexes are Likely to Remain the Most Reliable Indicator of Natural Gas Market Value in Asia

Applying the U.S. and European concept of a trading hub to natural gas and LNG price discovery in Asia 

Pacific may not be appropriate in that no single location will have the proper characteristics in the nearterm. Rather, given the ongoing activity in developing spot and short-term LNG price indexes, it is more 

likely that index pricing using those LNG indexes will continue to grow so as to reflect a value(s) of LNG 

in different markets across the Asian trading landscape. Liquid physical trading hubs may eventually 

develop in Japan, Singapore, Shanghai and other areas, yet both publically-driven and privately-driven 

initiatives to increase trade volumes and price transparency will be critical steps in the maturation of 

these markets and the evolution of reliable hub-based price indexes. Such hub-based price indexes 

would reflect the monthly and half-month Asian LNG price indexes and, presumably, would expand to 

include hub-specific daily price discovery as well. As existing LNG price surveys continue to improve in 

accuracy and increase their significance as indicators of the market price for LNG and reliable hub-based 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 6

price indexes emerge, indexes will be more reliably used not only to set the pricing for sales and 

purchase contracts, but also to serve as the basis for greater volumes of futures and derivatives trading.

Key metrics to watch for in the development of reliable LNG price indexation include:

• The expiration of long-term LNG contracts, accompanied by indicators of their replacement by 

shorter-term contracts (i.e., 4 years or less)

• More spot LNG cargoes

• Progress in Japan’s gas market liberalization

• More short-term trades tied to indexes rather than negotiated fixed prices
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 7

2 Introduction

The United States is on the verge of becoming a major exporter of liquefied natural gas (LNG). Markets 

for these exports will include Europe, South America, and Asia. The large LNG-consuming nations of the 

Asia Pacific region1 are undergoing major changes in how LNG is bought and sold. While in the United 

States and to some degree in Europe, gas market centers (called hubs) provide pricing transparency and 

an indication of market balances, the situation in the Asia Pacific region is less clear. The U.S. Energy 

Information Administration (EIA)2 has undertaken a review of the developments in these export markets 

to get a better understanding of how and when LNG hub-based prices and market transparency may 

evolve.

LNG in the Asia Pacific region is traded primarily under long-term, full-commitment contracts between 

buyers in the region and sellers from around the world.3 LNG prices are often linked to the price of 

crude oil through formulas negotiated privately between the parties. The dominant crude oil linkage is 

with the Japan customs-cleared crude (JCC) price of oil. LNG contracts typically include restrictions on 

where the LNG can be delivered, referred to as destination clauses. They also have take-or-pay 

provisions that require buyers to pay for LNG even when it is not needed. In combinations, these 

contract terms offer buyers little flexibility in managing supply. At the same time, the value of LNG and 

natural gas is often distorted in that it largely follows oil prices and does not reflect market supply and 

demand dynamics. This contract structure has existed to ensure the revenue stream that supports the 

large capital investments in LNG liquefaction, shipping, and regasification facilities. The linkage to widely 

traded oil also provides a way to manage price risk through hedging strategies. 

The global LNG market is undergoing significant changes. Australia is adding large volumes of new 

liquefaction capacity. In the United States, the shale revolution in gas supply has ended U.S. imports of 

LNG and has spurred the construction of export-oriented liquefaction plants. New supplies may come 

online in east Africa in the next ten years. While markets for LNG in Asia are expected to expand in the 

long term, with growing demand in China, India, Pakistan, Thailand, Malaysia, Indonesia, and Singapore, 

and new upcoming markets in Vietnam, Philippines, and Bangladesh, demand for LNG has softened 

considerably at present.

With these developments, LNG contracts in Asia Pacific are coming under pressure, particularly with 

respect to the oil price linkages and the delivery restrictions in LNG contract destination clauses. Spot 

trading has increased. Japan, Singapore, and China are seeking a more transparent LNG pricing that 

represents the interplay of supply and demand. Several organizations in Asia have announced their 

intentions to develop natural gas market hubs. 4 However, at present there is no fully functioning 

pricing point in Asia Pacific that can reliably transmit price signals to the market. 

 1 Asia Pacific as used in this report represents the major LNG importing countries of the Western Pacific Ocean: Japan, South 

Korea, Taiwan, China, and Singapore. The other gas-consuming or gas-producing countries in the region include Vietnam, 

Thailand, Malaysia, Myanmar, Brunei, Philippines, Papua New Guinea, Australia, and New Zealand. India, Bangladesh, and 

Pakistan are not covered in this report because of the distance from other Asia Pacific countries. 

2 Appendix A contains a full list of acronyms used in this report. 

3 Full commitment contracts require buyers of LNG to take all of their gas from suppliers’ dedicated LNG facilities with very 

limited opportunities for adjusting the purchased quantities. These contracts also include take-or-pay provisions requiring 

buyers to pay for gas contracted, even if contract volumes are not taken. 

4 Bold italicized terms are defined in Appendix B. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 8

An important feature of gas market liberalization in the United States and Canada, as well as in the 

United Kingdom and Europe, is the emergence of natural gas market hubs. Market hubs develop where 

multiple pipelines converge and interconnect and where numerous parties meet to buy and sell natural 

gas at negotiated prices. Various publications report the price, volume, and number of the trades at 

these market hubs. The prices reported at market hubs can be important indicators of the natural gas 

supply/demand balance for the regions served by those market hubs. Major market hubs, where large 

volumes are traded among many parties, can become centers for futures contracts. These contracts and 

their derivatives help buyers and sellers manage financial risk around future deliveries. 

This study examines the characteristics of gas market hubs and assesses the likelihood of a natural gas 

market hub developing in Asia Pacific. A major emphasis is on the prerequisites for gas market hubs that 

create benchmark price indexes. These benchmark indexes, such as the Henry Hub gas price in the 

United States, are widely accepted by industry as indicative of the market’s supply and demand balance. 

They are critical to the development of contracts for future deliveries and a myriad of financial hedging 

instruments. The analysis examines gas hubs in the United States and Canada as well as market hub 

developments in the United Kingdom and the European Union. For Asia Pacific, the focus is on efforts to 

create LNG and gas hubs in Singapore, China, and Japan. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 9

3 Market Hub Economics and Characteristics

The history and characteristics of natural gas market hubs have been well documented. EIA has 

published a number of reports on gas hubs in North America.5 The Oxford Institute for Energy Studies 

(OIES) has analyzed European gas market hubs.6 The International Energy Agency (IEA) published a 

report in 2013 on the outlook for developing a natural gas market hub in Asia.7

This section draws on this literature to describe stages of market hub development. These stages occur 

within the broader context of regulatory reforms to transform the natural gas industry from a highly 

regulated, monopolistic structure to a more competitive marketplace. Central to this transformation has 

been the development of physical gas market hubs with a close interaction between supply and 

demand. This section discusses the key characteristics of gas market hubs that support competitive 

markets and reliable benchmark price indexes. 

Gas market hubs that report reliable price information require a number of actions by government and 

industry aimed at creating the conditions for price discovery. The following discussion assumes that the 

physical facilities necessary for a market hub are already present. These include adequate physical 

pipeline capacity for large volumes of gas with access to both supply and end use markets, nearby gas 

storage, adequate interconnection facilities, and a market hub operator. An LNG market hub would also 

include port facilities, LNG storage, regasification or liquefaction capacity, and pipelines interconnected 

with the markets. The stages of market hub maturity are summarized in Table 3-1.

Stages 1 and 2 have been critical to the development of competitive gas markets and the operations of 

gas market hubs. Virtually all gas industries arose with transmission pipelines selling bundled service 

(gas and transportation) to distributors and end users. To facilitate market reform, government 

regulators have deregulated the price of gas and required the separation of gas sales from 

transportation and related services (e.g., gas storage). At the same time, regulators required 

transmission pipelines to offer non-discriminatory TPA. Removing barriers to entry in Stages 1 and 2 

allowed more parties to buy, sell, and transport gas (Stage 3) at the physical hubs through many 

individual bilateral transactions. As trading activities have grown, various PREs began canvassing parties 

and reporting price and volume trades. In Stage 4 the PREs’ reporting provides a degree of price 

transparency that leads to price discovery and allows market participants and outsiders to evaluate 

market fundamentals. This transparency has encouraged more parties to enter the market. Typically,

the PREs aggregate all sales and report average prices for the time period. In the United States, reported 

pricing follows guidelines established by the Federal Energy Regulatory Commission (FERC) as well as 

reporting standards set by the publications.8

 5 U.S. Energy Information Administration, “Natural Gas Market Centers and Hubs: A 2008 Update” (accessed October 2, 2016),

https://www.eia.gov/pub/oil_gas/natural_gas/feature_articles/2009/ngmarketcenter/ngmarketcenter.pdf; U.S. Energy 

Information Administration, “The Emergence of Natural Gas Market Centers” (accessed October 2, 2016), Natural Gas 1996, 

http://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/natural_gas_1996_issues_trends/pdf/it96ch3.pdf. 

6 The Oxford Institute for Energy Studies, “The Evolution of European Traded Gas Hubs” (accessed October 2, 2016), 

https://www.oxfordenergy.org/wpcms/wp-content/uploads/2016/02/NG-104.pdf.

7 International Energy Agency, “Developing a Natural Gas Trading Hub in Asia: Obstacles and Opportunities” (accessed 

September 24, 2016), http://www.iea.org/publications/freepublications/publication/asiangashub_final_web.pdf. 

8 U.S. Federal Energy Regulatory Commission, “Policy Statement on Natural Gas and Electric Price Indexes” (accessed 

September 23, 2016), https://www.ferc.gov/legal/maj-ord-reg/policy-statements.asp.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 10

Table 3-1. Stages of development of market hubs

Stages Explanation

1 Gas prices deregulated and 

gas sales unbundled from gas 

transmission

Governments deregulate the price of natural gas and regulators reform the market 

to separate the commodity sales function from transportation and other logistics 

services. Number of buyers and sellers increases.

2 Third party access to 

transport facilities, terminals

Regulators mandate that all potential infrastructure users have access on nondiscriminatory commercial terms, known as third-party access (TPA). This opens the 

hub network to the new buyers and sellers. 

3 Bilateral trading

predominates

Multiple parties begin to contract with each other on their own terms and over the 

TPA facilities. Producers can trade directly with distributors and large end users. The 

number of parties and transactions expands. 

4 Transparency in pricing and 

volumes traded 

Price reporting entities (PRE) begin publishing pricing information where prices and 

volumes are reported and published daily, weekly, or monthly, under rules to ensure 

accuracy. Reliable price information supports bilateral trading and reduces 

transaction costs.

5 Standardization of trading 

rules and contracts

Instituted by regulators or an industry organization, such as the North American 

Energy Standards Board (NAESB), ensures common use of terms and standardized 

trading and transfer practices. This facilitates trading by reducing transaction costs 

and making trading more efficient.

6 Over-the-counter (OTC)

brokered trading

In addition to producers, distributors, and end users, traders such as merchants, 

financial institutions, and brokers enter the market to trade gas and provide 

additional market liquidity. 

7 Price indexation Liquidity at the hub increases to the point that PRE-reported prices at the hub 

become a reliable indicator of market balance. The reported prices become a reliable 

index that parties will cite for future pricing in long-term contracts.

8 Non-physical traders enter Non-physical traders offering pure financial hedging instruments based on the hub 

index enter the market to take price risk and offer customized OTC hedging services 

linked to the index. 

9 Futures exchange A commodity exchange such as the New York Mercantile Exchange (NYMEX) creates 

a standardized tradeable futures contract and offers a trading platform under 

exchange rules. 

10 Liquid forward price curve Parties trade large numbers of futures contracts for deliveries many months out, 

providing future price discovery and a means of managing price risk on future 

commitments.

Source: Adapted from Patrick Heather, The Evolution of European Traded Gas Hubs, Oxford Institute for Energy Studies 

With the growth of trading at some gas market hubs, commodity trading exchanges have offered 

alternative platforms for executing physical trades. Exchange participants submit offers to sell and bids 

to buy on the exchange (i.e., bid and ask). The exchange matches bids and asks and establishes the 

market clearing price. Trading is anonymous; the exchange reports on its website the results of the 

trade, which include bid, ask, final price, and quantity. 

Standardization of contract terms and operating rules (Stage 5) further enhances trading by reducing 

uncertainty and lowering transaction time and costs. In the United States and Canada industry groups 

like NAESB have led the standardization. In Europe and the United Kingdom, government regulators 

have installed operating codes as part of overall market reform. With widely available price information 

and larger numbers of parties trading under uniform rules, other parties not directly involved in gas 

production or consumption enter the markets (Stage 6). These parties include banks, brokers, and gas 

merchants. Besides buying and selling gas, they also provide various merchant services and risk 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 11

management in over-the-counter (OTC) individual transactions. With the entry of these parties into the 

market, trading increases, and markets at hubs become more robust and liquid. 

Liquidity is an essential feature of a mature gas market hub. “A market is often said to be liquid when 

the prevailing structure of transactions provides a prompt and secure link between the demand and 

supply of assets, thus delivering low transaction costs.”9 A liquid market at a hub allows trades to occur 

quickly and with a minimal impact on the price. Liquidity is represented by the number of trades, the 

number of independent parties trading, and the volumes of trades. Churn rate is a term used to describe 

one aspect of liquidity: the number of times a unit of natural gas is traded at a hub, physically and 

through financial instruments such as futures contracts. A gas market hub with a high rate of churn is 

also a highly liquid market hub. 

The reliability and transparency of the prices reported by the PREs are critical in the development of a 

liquid gas market hub. Market participants must be comfortable that the prices reported are true and 

reflect the value of gas at any point in time for that hub location. When this acceptance is widespread, 

the prices reported at a gas market hub can be said to be an index for that hub (Stage 7). Buyers and 

sellers will be willing to strike deals for future deliveries at the future unknown index price for that hub. 

Price indexation, combined with other factors, can attract non-physical traders (e.g., investment banks, 

trading houses) offering purely financial derivative products tied to the hub index (Stage 8). The other 

factors include gas market liquidity at the hub, evidenced by the large number of participants trading 

large volumes of gas in many independent transactions. 

Where trading at a market hub is sufficiently robust, it can support a standardized financial futures 

contract offered by an organized exchange (Stage 9) such as the NYMEX or Intercontinental Exchange 

(ICE). Futures contracts and their derivatives provide low-cost, standardized price risk management for 

gas deliveries in the future and future price discovery. Where these contracts become highly traded 

across many months or years, the forward prices can become reliable indicators of what market 

participants consider the value of gas in the future to be at that gas market hub. A robustly traded 

forward price curve is the final stage in the evolution of a gas market hub that yields a benchmark price 

index (Stage 10). An indicator of a liquid forward curve would be a large amount of open interest for the 

futures or derivatives contract extending months into the future. 

Not all gas hubs have the same functionality and physical structure. The ten stages of hub maturity are 

useful for categorizing or distinguishing between hubs. Transit hubs operating in competitive markets 

have substantial volumes of gas moving across the hub, but little trading takes place. PREs may report 

prices at transit hubs despite relatively thin trading. These hubs operate at Stages 4 and 5. Successful 

gas market hubs operate at least at Stage 8 or even Stage 9. Prices at these hubs can be widely followed 

and frequently reported as indicative of the market conditions. (Gas market hubs may be located where 

major pipeline systems intersect or they may be notional points in a pipeline network; these latter 

points are referred to as notional market hubs and sometimes as virtual market hubs.) Few gas market 

hubs operate at stage 10, where there is a liquid forward price curve based on the hub’s price index. 

 9 Gabrielsen, Alexandros with Massimiliano Marzo and Paolo Zagaglia, “Measuring Market Liquidity: An Introductory Survey”

(accessed May 17, 2016), p. 1, http://arxiv.org/pdf/1112.6169.pdf. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 12

Indeed, one recent paper asserts that of all the hubs in the world, only Henry Hub in Louisiana 

constitutes a fully functional market hub where reliable price discovery takes place (Stage 10).10 

 10 Makholm, Jeff D., “There is but One True Hub, and His Name is Henry,” Wiley Periodicals: Natural Gas & Electricity, June 2016 

http://www.nera.com/content/dam/nera/publications/2016/GAS32_11b_Makholm.pdf. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 13

4 Market Hubs in the United States and Canada

4.1 Background

The world’s first gas market hubs appeared in the United States in the 1990s and were a result of 

governmental reform of the natural gas industry. 

Beginning in the mid-1980s, FERC initiated reforms of the natural gas pipeline industry that were aimed 

at promoting competitive markets for natural gas. These reforms culminated in FERC Order 636 in 1992. 

Combined with Congress’ lifting price controls on natural gas, the reforms transformed the U.S. natural 

gas industry. Two important reforms were fundamental in this restructuring. First, FERC separated gas 

sales from gas transportation; pipelines were limited to providing transportation services exclusively. 

Second, FERC mandated TPA. FERC prohibited pipelines from selling bundled gas service and required 

non-discriminatory open access to pipeline services. As FERC was reforming the U.S. gas industry, a 

parallel effort was underway in Canada to deregulate gas prices, separate gas sales from transportation, 

and require TPA.

FERC specifically prohibited pipelines from instituting rules that would limit the development of “market 

centers.”11 Market centers were defined by FERC as locations where pipelines interconnected and 

where there was a possibility for gas trading. Operators of market centers could offer commodity 

exchange services, e.g., wheeling, park and loan, storage, title transfer, and trading. By the mid-1990s, a 

number of these market centers had sprung up around the country offering these services and actively 

trading gas. The most important of these was Henry Hub in Erath, Louisiana.

Fairly quickly, gas buyers and sellers and a new breed of gas market middlemen (marketers, traders, and 

aggregators) began using these market centers, or market hubs as they came to be referred to, as 

locations for trading physical gas, mostly by means of direct bilateral deals between parties. Early on,

several PREs began publishing the prices of gas traded at Henry Hub and at other hub locations. These 

PREs relied on voluntary daily surveys of trading parties. While the reported prices were considered 

reliable, there were instances of misreporting of trades and more elaborate efforts at market 

manipulation at some hubs.12 The Energy Policy Act of 2005 expanded FERC jurisdiction to monitor 

markets and to issue rules prohibiting false reporting or other forms of market manipulation.13 

The NYMEX selected Henry Hub as the site for its natural gas futures contract beginning in 1990. The 

standard futures contract is for 10,000 million British thermal units (MMBtu). Daily clearing prices for 

futures contracts for monthly deliveries extend forward about eight years. Physical gas trading continues 

at the hub via OTC bilateral trading and to some extent on the exchange as well. Futures contracts 

trading dominates, however, and now averages approximately 400,000 futures contracts per day, and 

 11 Code of Federal Regulations, Title 18, Chapter 1, Subchapter 1, Part 284, Subpart A, 284.7, Firm Transportation Service, (b) 

(3): “An interstate pipeline that offers transportation service on a firm basis under subpart B or G of this part may not include in 

its tariff any provision that inhibits the development of market centers.”(18 CFR § 284.7 (b) (3)). 

12 The most famous case involved Enron’s manipulation of gas prices in the California energy crisis in 2000. 

13 The FERC’s market oversight authority extends to electricity markets as well. For a list of recent FERC actions, see the FERC 

website: http://www.ferc.gov/enforcement/market-manipulation.asp. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 14

more than that when options and other derivative products are included.14 (CME lists over 280 

derivative financial natural gas contracts in addition to the Henry Hub futures contract.)15 The CME 

Group offers various financial derivatives based on gas market indexes (futures contracts, swaps, and 

options) at approximately 40 hubs.16 These are the more heavily traded, liquid gas market hubs. (That 

said, very few of the listed financial derivatives at these other hubs are actually traded.) 

4.2 Henry Hub and Select Hubs in North America

Table 4-1 presents basic statistics for five major gas market hubs in the United States and Canada. 

Dominion South Point is a growing center for Marcellus production. Texas Eastern M3 is a major 

gateway to the Northeast and New England. Dawn is the major pricing point for gas flowing into eastern 

Canada from the United States and western Canada. Alberta Energy Company (AECO) is the notional hub 

for all Alberta production and provides large volumes of gas to the United States as well as Canada. 

Table 4-1. North American natural gas hub metrics

Market hub Location

Physical Trades Futures 

Average 2015 

volume

(000 

MMBtu/d)

Average 

2015 deals 

/day

CME futures 

contract open 

interest contract 

volume

CME forward open 

interest dates

Henry Hub Southern 

Louisiana 192 29 1,167,930 Nov. 2016 - May 2024

Dominion South 

Point

Southwestern 

Pennsylvania 

(Marcellus)

218 48 58,380 a Nov. 2016 – Dec. 

2020

Texas Eastern M-3 

Receipts

New York, New 

England 201 38 21,275 a Nov. 2016 – Oct. 

2020

Dawn (Canada) Southwestern 

Ontario 644 109 None None

AECO (Canada) Alberta 1,562 138 None None

a Average daily volumes, deals and price ranges were calculated by averaging the values from a data sample composed 

of the first Trading day for each calendar month in 2015. The mean values from the twelve days were calculated using 

a simple average, with conversions made to USD/ MMBtu where necessary. AECO volumes converted from GJ to 

MMBtu.

Source: Platts Gas Daily, various issues; CME Group, Daily Energy Volume and Open Interest

The table shows the average physical volumes traded in 2015 and the average number of deals per day 

as reported to Platts Gas Daily. Not all trades are reported. According to FERC, Form 552, “Annual 

Report of Natural Gas Transactions,” PREs reported only about 49% of reportable transactions in 2015.17

The table indicates that Henry Hub has fewer volumes and trades reported by Platts Gas Daily than the 

other hubs. AECO appears to be the largest in terms of reported physical trading. 

 14 CME Group, “Daily Energy Volume and Open Interest,” (accessed June 2, 2016), http://www.cmegroup.com/marketdata/volume-open-interest/energy-volume.html.

15 CME Group, “CME Group All Products Code and Slate,” (accessed October 18, 2016), 

http://www.cmegroup.com/trading/products/.

16 Ibid.

17 Estimated from FERC Form 552 data. See Appendix Table C-1. 
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Also shown are data on the forward contracts for deliveries at these hubs in the form of the open 

interest for futures and basis futures contracts. CME Group open interest represents the “total number 

of futures contracts long or short in a delivery month or market that has been entered into and not yet 

offset or fulfilled by delivery.”18 Open interest indicates the liquidity of the forward price curve for the 

contracts in question; the higher the open interest, the more liquid the reported prices are. Only Henry 

Hub has a substantial number of forward contracts. (The number shown in the table is only for the basic 

futures contract; there are several other derivative products for Henry Hub that also have substantial 

open interest.) 

The implications of these data are that Henry Hub operates at Stage 10 in the hub development stages. 

Dominion and Texas Eastern are at least at Stage 9, and possibly at Stage 10. Dawn and AECO have 

futures contracts but are not actively traded locations; they are likely operating at Stage 8 or 9. 

4.3 Liquidity and the Churn Rate in the United States

One measure of a gas market hub’s liquidity is the churn rate. Churn rate refers to the number of times 

a single unit of gas is sold, including non-physical sales of financial derivatives at a location over a 

defined period of time. The calculation includes the estimate of first sales of gas at the hub, the number 

of resales of physical units of gas, and the number of financial product sales based on the physical 

market. Doing this calculation for individual hubs can be challenging. First, one must determine the 

relevant area to be considered in estimating the volume of physical sales (the denominator). For 

example, do nearby sales count? The second challenge is estimating the number of trades occurring 

across multiple platforms and derivative products.

One possible calculation for the natural gas market churn ratio is for the United States as a whole, 

shown in Table 4-2. For the United States, the sum of all monthly and daily physical market trades 

reported in FERC Form 552 in 2015 is 62 quadrillion Btu (corrected for double counting of both sides of

each transaction and rounded to the nearest whole number).19 U.S. natural gas consumption was 26 

quadrillion Btu in 2015. This indicates that the churn ratio in terms of only physical volumes traded was 

about 2.4. 

Looking more broadly, the amount of trading on the two large trading markets, CME’s NYMEX (Henry 

Hub futures and other products) and ICE (various products at Henry Hub and other locations), in recent 

years has ranged from 1,100 to 1,500 and 419 to 768 quadrillion Btu, respectively.20 (The natural gas 

volumes on NYMEX Henry Hub futures and ICE in the United States are higher in years with high price 

volatility and lower in years with less price volatility.) Using these measures, Table 4-2 shows a national 

churn ratio of 61–90. This estimated churn ratio does not count trades for companies too small to 

 18 CME Group, “Glossary” (accessed October 15, 2016), http://www.cmegroup.com/education/glossary.html. For calculation of 

open interest only one side of the contract is counted. 

19Cornerstone Research, “Characteristics of U.S. Natural Gas Transactions, Insights from FERC Form 552 Submissions 2016” 

(accessed October 13, 2016), https://www.cornerstone.com/Publications/Reports/Characteristics-of-US-Natural-GasTransactions-2016. The total sales are only wholesale and do not include sales to affiliates (e.g., Shell production to Shell 

Trading) or sales by distribution companies to their customers. 

20 Ibid., p. 5. Commodity volumes computed by ICF from contract counts. Also see Federal Energy Regulatory Commission, 

“State of the Markets Report 2015” (accessed October 2, 2016), https://www.ferc.gov/market-oversight/reports-analyses/stmkt-ovr/2015-som.pdf.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 16

report under FERC Form 552 and does not take into account differences in trading volumes among 

regional natural gas markets. However, the relevance of regional factors is ambiguous given that futures 

and other products at Henry Hub are used to hedge trades throughout the U.S. Even with these data 

omissions and definitional ambiguities, it is clear that natural gas markets in the United States on the 

whole are very liquid as measured by the churn ratio. 

Table 4-2. Example calculation of natural gas churn ratio for the United States

Type of trade Quadrillion Btu/y or 

ratio

1. Physical trades reported on FERC Form 552 for 2015 62

2. NYMEX natural gas products in recent years 1,100 - 1,500

3. ICE financial natural gas products in recent years 419 - 768

4. Total Trades [=1+2+3] 1,581 - 2,330

5. Natural Gas Consumption for 2015 26

6. Churn Ratio [=4/5] 61 - 90

4.4 Observations on U.S. and Canadian Hub Development

Natural gas market hubs are central to the operation of the U.S. and Canadian natural gas markets. 

Across the United States and Canada, gas prices quoted at over 100 market hubs provide daily snapshots 

of the gas supply and demand balance in both countries. The emergence of market hubs came after 

government regulators revamped the interstate gas pipeline system and Congress deregulated gas 

prices. The United States and Canada can be considered as operating in Stage 10 of gas market 

development, with Henry Hub providing a benchmark price of gas nationally with a highly liquid forward 

price curve. The Henry Hub index and futures contract provides a reliable basis for managing price risk 

for traders without having to rely on oil or other price indexes. The key elements in the success of the 

North American market are 

• A highly integrated pipeline network with multiple points of interconnectivity

• The separation of pipeline transportation services from gas sales

• Third-party access to pipelines, storage, and LNG terminals

• Transparency in the reporting of gas pipeline capacity utilization, tariffs, and prices at market 

hubs

• Broad liquidity in the physical and financial markets
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 17

5 Market Hubs in Europe

Gas markets initially evolved in Europe as a collection of discrete national markets. Over the last two 

decades, both market reforms and infrastructure projects have supported the development of a more 

integrated European market. Today, gas moves more freely across the European pipeline network. A 

number of notional gas trading hubs have developed where gas custody transfer takes place. At many 

hubs, gas prices and price discovery are becoming more reliable. Although the European market 

continues to evolve, lessons learned from the development of its major gas trading hubs may be applied 

to immature gas markets in the Asia Pacific region. 

5.1 Overview of the European Gas Market

European gas infrastructure initially consisted of only national gas systems. These developed internally 

within each country and were designed originally to deliver manufactured gas to local markets.21 

Following the 1959 discovery of the Groningen gas field in the Netherlands, the first transnational 

pipelines were installed to carry natural gas across Western Europe. Beginning in the 1960s, LNG 

imports from North Africa and the Middle East supplemented pipeline gas before piped gas from the 

North Sea (1970s) and Russia (1982) added to the European supply. Today Europe’s system resembles a 

constellation of national natural gas systems that are linked through a series of trunk lines to import 

gateways. The level of interconnectivity across national borders varies greatly from system to system.22 

Historically, each country regulated its own national gas industry and European wholesale buyers—

mostly national gas monopolies—operated through long-term contracts tied to the price of fuel oil. 

Today, greater gas market liquidity and competition at all levels of the supply chain have led to 

increased volumes of natural gas trading on a spot market basis. A series of market reforms and 

infrastructure improvements facilitated these changes. 

5.1.1 Gas Market Reform in the United Kingdom

The United Kingdom led the way with its Gas Act of 1986. The Act privatized the U.K. gas system and 

initiated a process of market liberalization where gas supply and demand would set prices across the 

network. Subsequent legislation in 1995 included the establishment of the Uniform Network Code (UNC 

or Code), which established a common set of rules for all industry players and substantially completed 

the process of setting up a fully integrated competitive gas market. Most importantly, it established the 

principle of non-discriminatory (third-party) access to gas transportation, or TPA. The Office of Gas and 

Electricity Markets (OFGEM) regulates and oversees the U.K.’s restructured gas industry. In addition to 

bilateral contracts, the Code provides for two forms of gas trading: 1) spot OTC for day-ahead 

transactions and 2) on-day commodity market (OCM) for deals to balance the market. A significant 

 21 Manufactured gas is an artificial gas made from coal, petroleum or coal, and oil mixtures. Also known at town gas, 

manufactured gas was the source for urban gas lighting in the 19th century.

22 International Energy Agency, “Development of Competitive Gas Trading in Europe: How to Achieve Workable Competition in 

European Gas Markets?” (accessed August 1, 2016), p.11, 

https://www.iea.org/publications/freepublications/publication/gas_trading.pdf. The United Kingdom was the first country to 

import LNG, receiving its first cargo from the United States in 1959; subsequent cargoes were from North Africa. France and 

Italy began importing LNG in the early 1970s.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 18

proportion of the gas sold under long-term contracts is also re-traded by buyers in the spot OTC market. 

The National Balancing Point (NBP) was established as the notional market hub where this trading could 

take place.

5.1.2 Gas Market Reform in Europe

Historically, the natural gas market in Europe was highly concentrated within individual countries. A few 

major buyers effectively controlled the transmission pipelines and negotiated contracts with large 

natural gas sellers. Gas traded under long-term contracts (20–30 years), with most contracts having

take-or-pay clauses. The price of natural gas was linked to the price of other fuels, primarily fuel oil, 

often some mixture of residual fuel oil and distillate. Producers received a net-back price from the 

consuming market, i.e., the market price less transportation costs. Re-delivery of gas was restricted, so 

buyers could not resell gas to others in other markets. Although contracts had occasional price 

reopeners to allow parties to harmonize terms with market conditions, the market as a whole was highly 

inflexible.23

Following the liberalization of the U.S. and U.K natural gas markets, the European Union (EU) sought to 

develop a competitive gas market across Europe. In 2009, the European Parliament passed legislation 

known as the Third Energy Package, which set in motion market reforms for natural gas (and electricity) 

system and harmonized network rules across the EU in order to create a large, competitive gas market. 

Market development was facilitated by the unbundling of transportation services from sales and nondiscriminatory TPA.24 As part of this reform, the EU also created the Agency for the Cooperation of 

Energy Regulators (ACER) to act as a super-regulator that works with EU countries to harmonize 

regulations and provide regulatory support for the integrated gas market (OFGEM is a member of 

ACER.)25 

5.1.3 European Gas Market Today

Over the past 15 years, the Northwest European gas markets have developed substantially, as both 

trading hubs and market-clearing exchanges supporting a greater variety of natural gas sources and 

growing regional trade in natural gas. Global technological and political trends that affect both the 

supply and demand sides of the global gas market have also influenced European hub development. 

Greater technological ability to recover shale gas as well as other unconventional sources of gas has 

rapidly increased the global gas supply during the past decade. Concurrently, the replacement of oil- and 

coal-fired power plants with natural gas plants has increased regional gas demand.26 The location of 

 23 Ibid., p. 13

24 This Directive superseded earlier directives issued in 2003 also aimed at creating an integrated market. 

25 As this report was being written, the United Kingdom voted to leave the European Union. It is unlikely that this departure will

affect gas market integration in any significant way, given the advantages integration holds for the United Kingdom, which 

receives gas from European suppliers. The relationship between Ofgem and ACER is likely to change. 25 International Energy Agency, “Golden Rules for a Golden Age of Gas: World Energy Outlook Special Report on Unconventional 

Gas” (accessed August 1, 2016), p. 87, 

http://www.worldenergyoutlook.org/media/weowebsite/2012/goldenrules/weo2012_goldenrulesreport.pdf. 

26 Ibid.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 19

infrastructure, including LNG export facilities, pipelines, and storage terminals is especially critical to 

maintaining high liquidity at physical hubs and thereby preventing gas shortages. 

Table 5-1 shows the gas balances and the pipeline and LNG trade for the nine European countries that 

have significant gas market hub activity. The largest gas-consuming countries in Europe, in order, in 

2015 were Germany, the United Kingdom, France, Italy, Netherlands, and Spain. Norway, Netherlands, 

and the United Kingdom are the largest producers of natural gas, with Norway and Netherlands 

exporting signficant amounts to the rest of Europe. LNG imports to the nine European countries listed in 

Table 5-1 were 4.1 Bcf/d in 2015 compared to approximately 40 Bcf/d of pipeline imports (pipeline 

imports plus Norway exports). As of January 2016, 24 regasification terminals were operational in 

Europe, with another 4 regasification facilities under construction.27 Europe’s LNG regasification 

capacity represented approximately 20% of world regasification capacity as of 2015, slightly eclipsing 

the United States’ 18% share, yet falling short of Japan’s 28%.28

Table 5-1. Natural gas balances for select European countries, 2015

 (Bcf/d)

Country

Estimated 

natural gas 

consumption b

Pipeline 

exports

Pipeline 

imports

LNG 

exports a

LNG 

imports

Natural gas 

production

Austria 1.18 0.05 1.11 - - 0.12 

Belgium 1.53 0.25 1.56 0.02 0.24 - 

France 3.88 0.36 3.66 0.05 0.63 0.00 

Germany 10.03 0.78 9.97 - - 0.84 

Italy 6.56 0.01 5.34 - 0.57 0.65 

Netherlands 3.19 5.39 3.43 - - 5.15 

Norway 1.58 9.62 - 0.56 - 11.76 

Spain 3.05 0.05 1.83 0.04 1.31 0.01 

United Kingdom 7.06 1.26 2.99 - 1.33 3.99 

Total 38.07 17.76 29.89 0.68 4.09 22.54 

a LNG exports include re-exports of LNG previously imported. b Estimated country-level consumption figures may vary slightly due to rounding

Source: ICF compilation of data from International Energy Agency Natural Gas Information (2016 edition). 

The combined impact of increased pipeline interconnectivity, a uniform and transparent regulatory 

framework and operating code, and a greater number of LNG import facilities connected to the network 

has supported the growth of gas market hubs in Europe. With greater gas availability and the support of 

financial systems that promote trade transparency and accessibility, buyers and sellers have fueled the 

development of more liquid trade structures, including an increase in spot trading of physical volumes 

and financial derivatives. Since 2009, European wholesalers have been increasingly reliant on spot 

markets to meet swings in customer demands.29 As a result, spot sales displaced or complemented gas 

volumes that historically had been traded under long-term take-or-pay contracts. Although both 

available gas volumes and accurate price discovery are seen as prerequisites of spot trading, it is the 

 27 The International Group of Liquefied Natural Gas Importers, “The LNG Industry” (accessed October 2, 2016), p.30, 

http://www.giignl.org/sites/default/files/PUBLIC_AREA/Publications/giignl_2016_annual_report.pdf.

28 Gas in Focus, “Existing and Planned LNG Terminals,” (accessed September 15, 2016), p.1, 

http://www.gasinfocus.com/en/indicator/existing-and-planned-lng-terminals/.

29 U.S. Energy Information Administration, “An Introduction to Global Natural Gas Markets, Drivers, and Theory” (accessed 

October 2, 2016), p. 40, https://www.eia.gov/workingpapers/pdf/global_gas.pdf. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 20

presence of a significant volume of spot trading activity that promotes efficient market pricing 

mechanisms. Further, it is the presence of futures trading —which, in turn, rely on these efficient pricing 

mechanisms— that confirms a gas market hub’s status as both liquid and stable enough to drive 

contract pricing. Stronger correlation among hub prices has continued to narrow spreads between 

regional gas markets since 2007. Absent the effects of regional geopolitics, technology changes, or 

supply disruptions, prices at the European hubs are increasingly correlated, even as locational prices 

vary.30

5.2 Key European Hubs 

The NBP was the first European gas market hub to become operational, followed by Belgium’s 

Zeebrugge (ZEE) hub, in operation since 2000.31 Since then, seven other major hubs were established in 

Northwest Europe: Netherlands Title Transfer Facility (TTF) and Italian Punto di Scambio Virtuale (PSV) in 

2003; the French Points d’Exchange (PEG Nord and Sud) in 2004; Austria’s Central European Gas Hub 

(CEGH) in 2005; and the German hubs more recently, with National Connect Germany (NCG) established 

in 2008 and Gaspool (GPL) in 2009.32 While these nine hubs make up the backbone of the current 

European hub landscape, other smaller or less liquid hubs are continuing to develop in countries 

surrounding the existing trade centers, including Poland, the Czech Republic, Hungary, and other eastern 

European countries.33 For many of the major European hubs—all of which are notional hubs except for 

Belgium ZEE—natural gas exchanges like the European Energy Exchange (EEX) or Powernext track spot 

transactions of gas and maintain detailed pricing records for the hubs within their jurisdictions.

34

Table 5-2 presents a quantitative comparison of the above European hubs. The table shows both 2015 

average daily volumes and 2016 year-to-date (through May) volumes, as compared to volumes traded in 

2011, the first year the London Energy Brokers Association (LEBA) published its monthly volumetric 

reports.35 Traded volumes are OTC bilaterally settled volumes and include a combination of prompt 

month and future months traded settlements, which may include the same gas sold several times. In the 

first five months of 2016, average daily volumes appear to have declined at all hubs, with substantial 

declines at the NBP.36 The U.K. NBP and Netherlands TTF are the most heavily traded locations in Europe 

as reported by LEBA, with the churn rate at TTF substantially higher than at the NBP.37 

 30 The Oxford Institute for Energy Studies, “European Gas Hubs: How Strong is Price Correlation?” (accessed on September 14, 

2016), https://www.oxfordenergy.org/wpcms/wp-content/uploads/2013/10/NG-79.pdf. 31 The Oxford Institute for Energy Studies, “Continental European Gas Hubs: Are they fit for purpose?” (accessed on October 1, 

2016), https://www.oxfordenergy.org/wpcms/wp-content/uploads/2012/06/NG-63.pdf.

32 Ibid., p. 4.

33 European Federation of Energy Traders, “European Gas Hub Development” (accessed September 12, 2016), 

http://www.efet.org/Cms_Data/Contents/EFET/Folders/Documents/EnergyMarkets/VTP_Assessment/~contents/3WAJGMFN7

MDJYZ2Q/GHD-Study_summary-ppt_part-1.pdf. 

34 EEX Newsroom, “About Us” (accessed June 17, 2016), p. 1, https://www.eex.com/en/about/eex.

35 LEBA did not record volumes for Austria, Italy, or Belgium in 2011, which is its earliest monthly volumetric report.

36LEBA changed the definition of French hubs in 2016, making comparisons impossible.

37LEBA publishes churn rates computed as 2015 trades divided by national consumption for 2014. Continental sum includes all 

listed trades except NBP and all national consumption except U.K. Methodology for this table is not the same as OFGEM 

calculations presented in the prior section showing a U.K. churn ratio of 22.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 21

Table 5-2. Metrics for select European gas trading hubs

Hub Year

established

Active 

market 

participants

Day-ahead trades 

per month

2011 

(Bcf/d)

2015 

(Bcf/d)

2016 

(Bcf/d)

Churn rate 

circa 2015

Austria CEGH 2005 10 798 - 2.8 1.7 3.53 

Belgium ZEE 2000 15 1,696 - 7.2 2.9 5.15 

French Hubs - 15 3,999 3.6 3.9 2.2 1.10 

 France PEG Nord 2004 10 3,217 NA NA 2.0 -

 France TRS 2015 5 782 NA NA 0.2 -

German Hubs - 25 7,184 10.1 22.2 10.8 3.22 

 Germany NCG 2008 - 4,913 7.3 14.5 7.0 -

 Germany 

GasPool

2009 - 2,271 2.8 7.7 3.8 -

Italy PSV 2003 12 NA - 6.5 3.8 1.18 

Netherlands TTF 2003 30 7,659 56.6 114.9 60.9 37.05 

U.K. NBP 1996 40 7,390 123.6 77.0 37.6 11.85 

Sources: London Energy Brokers Association, Oxford Institute for Energy Studies. 

Notes: NA stands for not available. Million MWh converted to Bcf at 3.31 Bcf/million MWh. 2016 data are averages through May. 

5.2.1 Austria Central European Gas Hub (CEGH)

Austria’s natural gas pipeline largely depends on inflows from Russia through Slovakia.38 As a result,

Austria’s notional hub, CEGH, offers limited transfer access between international and domestic natural 

gas supplies. The role of hub operator is shared between the Austrian Gas Clearing and Settlement 

(AGCS) entity, Gas Connect Austria (GCA), Wiener Borse Exchange, and the CEGH itself.39 The CEGH hub 

is a reliable location for title transfers and hosts all spot and futures trading on the Austrian system, 

although limited access is available for non-physical traders.40

5.2.2 Belgium Zeebrugge Hub (ZEE)

ZEE in Belgium is a physical hub with interconnections between pipelines and LNG imports terminals 

that connect continental Europe with the United Kingdom and Norway. ZEE was the second hub to be 

established in Europe when it became operational in 2000.41 It operates as a transit hub for gas flowing 

to Europe from the North Sea and gas to the United Kingdom. Pipeline infrastructure carries gas from 

Zeebrugge to interconnect with the Netherlands TTF and France PEG Nord gas systems, as well as with 

 38 International Energy Agency, “By Country: Gas Trade Flows in Europe” (accessed October 16, 2016), p. 1. 

https://www.iea.org/gtf/. 39 European Federation of Energy Traders, “European Gas Hub Development” (accessed June 15, 2016), p. 11, 

http://www.efet.org/Cms_Data/Contents/EFET/Folders/Documents/EnergyMarkets/VTP_Assessment/~contents/3WAJGMFN7

MDJYZ2Q/GHD-Study_summary-ppt_part-1.pdf.

40 Oxford Institute for Energy Studies, “The Evolution of European Traded Gas Hubs” accessed October 17, 2016), p. 100, 

https://www.oxfordenergy.org/wpcms/wp-content/uploads/2016/02/NG-104.pdf.

41 Oxford Institute for Energy Studies, “Continental European Gas Hubs: Are they fit for purpose?” (accessed October 16, 2016), 

p.4, https://www.oxfordenergy.org/wpcms/wp-content/uploads/2012/06/NG-63.pdf.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 22

both German hubs—NCG and GPL. Fluxys is both the hub operator for ZEE and the independent system 

operator for all natural gas transmission and storage infrastructure in Belgium.42 ICE currently offers 

futures contracts for physical delivery at ZEE, while ICE-Endex facilitates spot trading for gas at ZEE on its 

exchange, as does Powernext.

5.2.3 France Trading Region South (TRS) and Point d’Exchange Nord (PEG Nord) 

The French PEG hubs represent the entirety of the French natural gas market and operate within the 

Powernext natural gas exchange framework.43 Powernext offers both spot and futures trading for the 

French hubs, which are operated primarily under the oversight of GRTgaz.44 Originally, the French 

natural gas trading system was composed of three hubs: PEG Nord, PEG Sud, and PEG Transport et 

Infrastructures Gaz France (TIGF). As of April 2015, however, PEG Sud and TIGF merged to trade under 

the common name Trading Region South (TRS). 45 Today, the French Hubs are key fixtures in the 

Powernext trading exchange. 

5.2.4 National Connect Germany (NCG)

NCG, a market hub operated within the EEX, is Germany’s second notional hub. Initially established in a 

small region of southern Germany, the NCG gas transport system now represents a larger market area. 

This market is overseen by a coalition of transmission system operators that trade gas along their 

collective pipeline systems.46 Futures contracts are offered on the ICE and EEX for gas delivered through 

the NCG trading point. Spot contracts are also offered for NCG on the EEX.47 The NCG hub is sufficiently 

firm due to its integration into the EEX exchange and increases reliability in Europe as a benchmark for 

natural gas pricing. Going forward, if NCG continues to develop and if trading volumes increase, a wider 

variety of futures contract structures may be offered. Nevertheless, consistent higher trade volumes will 

be required for NCG to develop a reliable forward price curve.48

 42 Fluxys, “Independent Operator of the Natural Gas Transmission System in Belgium” (accessed October 13, 2016), p.1, 

http://www.fluxys.com/belgium/en/About%20Fluxys/AboutFluxys.

43 European Federation of Energy Traders, “European Gas Hub Development” (accessed October 16, 2016), 

http://www.efet.org/Cms_Data/Contents/EFET/Folders/Documents/EnergyMarkets/VTP_Assessment/~contents/3WAJGMFN7

MDJYZ2Q/GHD-Study_summary-ppt_part-1.pdf.

44 S&P Platts, “French Gas Traders Mull New Market Balancing Proposals” (accessed July 13, 2016), p.1, 

http://www.platts.com/latest-news/natural-gas/london/french-gas-traders-mull-new-market-balancing-26145343.

45 Reuters, “Southern France Gas Trading Hubs to Merge on April 1” (accessed October 20, 2016), p.1, 

http://af.reuters.com/article/commoditiesNews/idAFL5N0VY4XD20150224.

46 NetConnect Germany, “Company Profile” (accessed September 16, 2016), p.1, https://www.net-connect-germany.de/engb/About-us/Company-Profile.

47 Oxford Institute for Energy Studies, “The Evolution of European Traded Gas Hubs” (accessed September 17, 2016), p.100, 

https://www.oxfordenergy.org/wpcms/wp-content/uploads/2016/02/NG-104.pdf.

48 EEX, “NCG- PEGAS” (accessed June 17, 2016), p. 1, https://www.eex.com/en/market-data/natural-gas/spotmarket/ncg#!/2016/06/09.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 23

5.2.5 Germany Gaspool (GPL)

Germany’s Gaspool is a notional hub that represents pricing for gas traded along the H-Gas and L-Gas 

pipeline systems of northern Germany.49 Gaspool is operated by ICE, with physical trading, swap trading, 

block trades, and electronic futures all available for contract.50 Other spot trading opportunities and 

future contracts for GPL are offered on the EEX.51 Since Gaspool’s establishment in 2009, the number of 

potential traders has tripled, representing aggressive growth in the German market for natural gas 

trading. Trading volumes have increased 120% over the same time period.52

5.2.6 Italy Punto di Scambio Virtuale (PSV)

Italy’s PSV hub is a notional trading point operated by Snam Rete Gas with limited liquidity and price 

reporting reliability. Located on the Italian peninsula, PSV is relatively isolated from the majority of 

Western Europe’s natural gas pipeline system.53 Nevertheless, PSV represents the entire Italian gas 

market because storage is on an open-access basis.54 All trades settled at PSV are reported to the ICEEndex exchange.55 Beginning in 2015, Endex collaborated with Gestore dei Mercati Energetici S.p.A 

(GME) and Snam Rete to introduce physically-delivered Italian natural gas futures contracts at the hub.56

5.2.7 Netherlands Title Transfer Facility (TTF)

The Netherlands TTF is a notional hub for the gas grid in the Netherlands operated by Gas Transport 

Services, the country’s transmission system operator.57 The Netherlands grid is interconnected with 

several major pipelines in Europe. As trade volumes increased at TTF, the hub developed into a reliable 

indicator of spot prices for continental European natural gas trading.58 TPA and a favorable European 

 49 Gaspool Balancing Services, “Gaspool Hub” (accessed October 3, 2016), p.3, 

https://www.gaspool.de/fileadmin/download/information/5.gaspool-bkv-forum/5.gaspool_bkvforum_2013_07_en_gaspool_hub.pdf

50 Intercontinental Exchange (ICE) & the New York Stock Exchange (NYSE), “German Gaspool Gas Futures” (accessed June 23, 

2016), p.1, https://www.theice.com/products/27997606/German-GASPOOL-Gas-Futures.

51 Oxford Institute for Energy Studies, “The Evolution of European Traded Gas Hubs” (accessed October 10, 2016), p.100, 

https://www.oxfordenergy.org/wpcms/wp-content/uploads/2016/02/NG-104.pdf.

52 Gaspool Balancing Services, “Gaspool Hub” (accessed September 5, 2016), pp. 6-8, 

https://www.gaspool.de/fileadmin/download/information/5.gaspool-bkv-forum/5.gaspool_bkvforum_2013_07_en_gaspool_hub.pdf.

53 London Energy Brokers Assoc., “LEBA Monthly Volume Reports, Dec. 2015 and 2015 Year to Date, May 2016 and 2016 Year to 

Date” (accessed October 2, 2016), 

https://www.leba.org.uk/pages/index.cfm?page_id=59&title=leba_monthly_volume_reports.

54 Oxford Institute for Energy Studies, “The Italian Gas Market: Challenges and Opportunities” (accessed June 22, 2016), p.8, 

https://www.oxfordenergy.org/wpcms/wp-content/uploads/2013/06/NG-76.pdf.

55 ICE Endex, “Italian PSV Natural Gas Futures” (accessed July 12, 2016), p.1, 

https://www.theice.com/products/49321531/Italian-PSV-Natural-Gas-Futures.

56 Business Wire, “ICE Endex Collaborates with GME and Snam to Introduce Italian Natural Gas (PSV) Futures Contracts in 

September 2015” (accessed October 5, 2016), p.1, http://www.businesswire.com/news/home/20150604005497/en/ICE-EndexCollaborates-GME-Snam-Introduce-Italian.

57 ICE Endex, “Dutch TTF Gas Spot” (accessed September 12, 2016), p.1, https://www.theice.com/products/31435802/DutchTTF-Gas-Spot.

58 U.S. Energy Information Administration, “An Introduction to Global Natural Gas Markets, Drivers, and Theory,” (2014), p. 40.

https://www.eia.gov/workingpapers/pdf/global_gas.pdf. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 24

regulatory structure for gas trading were key factors that promoted this growth. When the Dutch 

market regulator removed the requirement in 2008 that traders must be invested in the physical gas 

market, both the number of market participants and the gas volumes traded increased substantially. 

Also in 2008, GasTerra, formerly the supply arm of Gasunie, began reporting its volumes traded on TTF. 

By far the largest portfolio operating through the TTF market at the time, Gasterra’s transactions 

increased market liquidity.59 Today, ICE-Endex and EEX operate exchanges for TTF spot contracts, while 

Powernext and ICE-Endex offer TTF futures contracts and long-term contracts.60 TTF has surpassed NBP 

as the most liquid hub in Western Europe. As of December 2015, the exchange represented 

approximately 45% of total gas volumes traded in Europe. 

5.2.8 Spain Mercado Ibérico Del Gas (MIBGAS) 

In December 2015 Spain launched a pan-Iberian natural gas market hub for trading in Spain and 

Portugal. The hub began trading with the Mercado Ibérico Del Gas (MIBGAS), serving as the market 

operator.61 The hub, referenced by the market as MIBGAS, joins a growing number of European gas 

hubs that are in earlier stages of development than those described previously. MIBGAS connects

Spain’s existing balancing point, Almacenamiento Operativo Comercial (AOC), a storage facility that 

limits market participation to traders who contract physical transmission capacity.62 Gas imports to 

Spain’s six LNG import facilities and increasing gas demand nationwide are expected to drive future 

development of the country’s natural gas trade.63 As one of Europe’s newest virtual trading points, 

greater OTC trade volumes will be required to trigger price indexation (stage 7 of the hub development 

process listed in Table 2-1). As of October 2016, MIBGAS announced that 38 registered traders could 

trade in its organized gas market, a development that suggests both trade volumes and market liquidity

may increase in the coming months.64 However, the liquidity at MIBGAS is likely to remain low until the 

new network codes for gas balancing are implemented in both Spain and Portugal.

5.2.9 United Kingdom National Balancing Point (NBP)

The U.K. government established the NBP in 1996 as part of the restructuring and liberalization of the 

U.K. gas sector. While originally designed as a daily gas injection/withdrawal imbalance clearing 

 59 Baringa Partners LLP “The Benefits of TTF Liquidity” (accessed June 2, 2016), 

https://www.acm.nl/download/documenten/nma/NMa_TTF_rapport_DEF.pdf; Kamerstukken, “Acceleration of the 

Development of the TTF and the Gas Wholesale Market” (accessed October 2, 2016), p. 26, 

https://www.rijksoverheid.nl/binaries/rijksoverheid/documenten/kamerstukken/2008/03/03/appendix-1-acceleration-of-thedevelopment-of-the-ttf-and-the-gas-wholesale-market/appendix-1-acceleration-of-the-development-of-the-ttf-and-the-gaswholesale-market.pdf.

60 Oxford Institute for Energy Studies, “The Evolution of European Traded Gas Hubs” (accessed October 20, 2016), p.84, 

https://www.oxfordenergy.org/wpcms/wp-content/uploads/2016/02/NG-104.pdf.

61 Mercado Ibérico del Gas, “The Market Operator” (accessed November 3, 2016), p.1, http://www.mibgas.es/en/gasmarkets/iberian-gas-market/market-operator.

62 Iberian Gas Hub, “The Iberian Natural Gas Market” (accessed November 3, 2016), 

http://www.iberiangashub.com/TheIberiannaturalgasmarket.aspx. 

63 International Gas Union, “2016 World LNG Report” (accessed September 12, 2016), www.igu.org/download/file/fid/2123.

64 Mercado Ibérico del Gas, “38 Agents are Registered in MIBGAS” (accessed November 3, 2016), p.1, 

http://www.mibgas.es/en/gas-markets/information-and-notices-MIBGAS.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 25

mechanism under the UNC (which established operating rules for TPA to the gas system), the NBP 

evolved into a notional market hub for the national transmission grid. Contracts for spot gas at NBP are 

offered on the ICE-Endex exchange.65 Today, prices quoted at the NBP represent natural gas trading 

across the U.K. gas network, which includes both LNG import terminals and pipeline supplies.66 This shift 

from stage 6 (OTC-brokered trading) to stage 7 (price indexation) occurred once clearing prices at the 

NBP came to be accepted by gas traders as indicative of market conditions. During the past five years, 

the NBP hub matured to the point at which non-shipper OTC trading was increasingly prevalent, the 

eighth benchmark stage of hub maturity.67

The on-day commodity market at the NBP is operated by ICE, which also offers futures and options 

contracts. During the past two decades, the role of the NBP pricing in the spot OTC and OCM markets 

has increased in significance as a price indicator across the U.K. It is believed that many of the new 

supply contracts between shippers, producers, and importers have pricing formulae that include an NBP 

component such that bilateral supply contracting reflects a combination of spot prices, oil prices, and 

inflation indices. As the NBP has gained status as a reliable pricing hub for gas contracts, the percentage 

of contracts that are bought and sold through ICE futures market has grown as a share of total NBPbased trades. Today, NBP is both the longest-standing European gas pricing point and the region’s most 

fully-developed market hub, having achieved the liquid forward price curve that reflects the tenth and 

final stage of hub development. 

5.3 Price Convergence at Major European Hubs

Pricing at the European gas market hubs is shown in Figure 5-1. Since 2014, prices have fallen 

considerably from an average of about $10/MMBtu to around $4/MMBtu. The decline in natural gas 

prices reflects lower oil prices and is consistent with the broader price movements in markets 

worldwide. Notably, prices across the more established European hubs move together, as is expected 

from efficient markets. The most recently established hub to be included, Spain’s MIBGAS, initially 

followed a different pricing curve than the other hubs, but by the fourth quarter of 2016, displayed

greater conformity with the rest of the markets. Overall, despite an expected degree of variation 

between prices at one hub versus another in response to local market conditions, natural gas trading 

hubs in Europe generally are exhibiting price convergence. 

 65 Oxford Institute for Energy Studies, “The Evolution of European traded gas hubs” (accessed October 2, 2016), p.100, 

https://www.oxfordenergy.org/wpcms/wp-content/uploads/2016/02/NG-104.pdf.

66 Pipeline & Oil Gas Journal, “National Grid at Home and Abroad” (accessed September 12, 2016), p.1, 

https://pgjonline.com/2016/01/13/22450/.

67 U.S. Energy Information Administration, “An Introduction to Global Natural Gas Markets, Drivers, and Theory” (August 2014), 

p.39, https://www.eia.gov/workingpapers/pdf/global_gas.pdf. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 26

Figure 5-1. Price movements at European hubs, January 2014–October 2016

Sources: Bloomberg, MIBGAS 

5.4 Observations on the European Hub Development

The emergence of gas market hubs in the United Kingdom and Europe resulted from government 

policies to promote more competitive gas markets, along the lines of those in the United States. The 

movement toward more gas hubs and competitive gas markets was also abetted by the need to 

decouple long-term contracts from oil pricing, by the increase in gas supply through LNG imports, and by 

new pipelines from the North Sea and Russia. This development echoes what happened in the United 

States in the 1980s and early 1990s, when supply abundance and a nascent spot market for gas 

prompted the development of natural gas trading hubs.

There are significant differences between natural gas markets in Asia Pacific, the United Kingdom, and 

the EU, which impact the outlook for hub development in Asia Pacific. Natural gas markets in 

continental Europe and the United Kingdom operate in a highly connected pipeline network. LNG 

imports, while important, are additional entry points into this network. Asia Pacific, on the other hand, is 

not interconnected for obvious geographical reasons and LNG is the principal source of natural gas for 

the countries there. Prevailing LNG contracting practices, particularly in long-term contacts, which 

include linkages to oil prices, are not conducive to the development of gas market hubs. In addition, Asia 

Pacific has no regulatory body similar to OFGEM or the European Commission that can lead the effort to 

liberalize markets and promote integration in the same way as has been done in Europe. Rather, each 

country has developed its own regulatory regime and is pursuing its own policies to promote 

competition. Indeed, the lack of maturity of some European gas trading hubs can be attributed in part to 

 2.00

 4.00

 6.00

 8.00

 10.00

 12.00

 14.00

Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16

USD/ MMBtu

NBP ZEEB PSV PEG Nord TRS

NetConnect Gaspool CEGH TTF MIBGAS
November 2016

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 27

the European Commission’s incomplete success in overcoming national monopolies and regulatory 

practices. This challenge is much greater in the Asia Pacific region. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 28

6 Asia Pacific Gas Market

In the United States and Canada, where the first gas market hubs developed and flourished, the natural 

gas pipeline transmission network provides the physical interconnections that make gas market hubs 

possible. The same is largely true for the United Kingdom and Europe. Asia Pacific is fundamentally 

different with widely dispersed and somewhat isolated national gas markets that have limited internal 

pipeline networks and little physical connectivity between countries. The Asia Pacific region relies 

heavily on LNG imports to supply individual domestic markets. This dependence on LNG has implications 

for the development of gas market hubs and price discovery in Asia Pacific. 

6.1 LNG and the Asia Pacific Gas Market 

The significance of LNG supply for the Asia Pacific gas market can be seen in Table 6-1, which shows 

natural gas balances in the major gas-consuming and producing countries in Asia Pacific in 2015. Total 

gas consumption for these countries was 54.45 Bcf/d with LNG accounting for 37% of total consumption. 

China has significant production, which is almost entirely consumed domestically. In recent years, China 

has increased pipeline and LNG imports to meet domestic demand. The major LNG exporting countries 

in Asia Pacific (Australia, Malaysia, and Indonesia) also have relatively large domestic markets. Crosscountry pipeline imports are modest, and include flows mostly from Myanmar and Malaysia to China, 

Singapore, and Thailand. 

Table 6-1. Natural gas balances for select Asia Pacific countries, 2015

(Bcf/d)

Country Estimated 

consumption

Pipeline 

exports

Pipeline 

imports LNG exports a LNG imports Natural gas production

Australia 3.73 - 0.62 3.62 - 6.74 

China 18.92 0.25 3.19 - 2.43 13.54 

Indonesia 4.17 1.40 - 2.10 - 7.67 

Japan 11.63 - - - 11.32 0.31 

Malaysia 4.33 0.13 0.71 3.26 - 7.01 

Singapore 1.10 - 0.81 - 0.29 - 

Korea 4.22 - - - 4.20 0.02 

Taiwan 1.70 - - - 1.67 0.03 

Thailand 4.72 - 1.06 - 0.35 3.31 

Total 54.52 1.77 6.39 8.99 20.26 38.63 

a LNG exports include re-exports of LNG previously imported.

Source: ICF compilation of data from International Energy Agency Natural Gas Information (2016 edition). These 

are the 2015 provisional estimates. 

The gas pipeline network in Asia Pacific is limited because the countries are separated by wide expanses 

of water. Thus, there is no pipeline-based model for gas market hub development in the region. China 

has large pipeline interconnections with Kazakhstan and Myanmar and imports gas from those 

countries. Southeastern Asia has multiple pipelines that cross national boundaries. For the most part, 

the pipeline infrastructure in Asia Pacific serves internal markets, connecting LNG terminals to 

consumers, offshore production to onshore markets, or internal production to consumers. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 29

Asia Pacific continues to dominate world LNG trade with approximately 66% of the world’s LNG imports 

in 2015.68 Table 6-2 shows LNG imports by region and share of world LNG trade. 

Table 6-2. Global LNG imports by region

Region Imports (Bcf/d) Percent

Asia 23.02 72.2

Of which Asia Pacific 20.98 65.8

Europe 4.88 15.3

Americas 2.69 8.5

Middle East 1.28 4.0

Total 31.87 100.0

Source: GIIGNL, 2016, Table: Quantities Received in 2015

As shown in Table 6-3, Qatar is the largest LNG exporter, with 32% of the world total, followed by 

Australia at 12%. Asia Pacific LNG exports stay in the Asia Pacific region, flowing primarily to Japan, 

South Korea, and China. The Middle East, however, exports to both Europe and Asia Pacific countries. 

This exporting pattern is expected to continue into the future. 

Table 6-3. Largest LNG exporting countries, 2015

Country

Liquefaction 

Capacity End of 

2015 (Bcf/d)

2015 Exports 

(Bcf/d)

Percent of World 

LNG Exports

Qatar 10 10.2 32

Australia 4.8 3.8 12

Malaysia 4.1 2.3 7

Nigeria 3.1 3.2 10

Indonesia 2.8 2.5 8

Subtotal 24.8 22 69

Rest of World 15.1 9.7 31

Total 39.9 31.7 100

Source: GIIGNL (2016), converting million metric tonnes per year to Bcf/d using 0.13. Note: Exports can exceed nominal 

capacity when the conditions defining nominal capacity change or when the number of days offline are fewer than expected. 

As shown in Table 6-3, world liquefaction capacity stands at about 40 Bcf/d.69 LNG exports in 2015 

totaled 31.9 Bcf/d, implying a liquefaction capacity utilization rate of 80%. LNG exporters are expanding 

liquefaction capacity in Australia, the United States, Russia, Malaysia, and Indonesia. 

Regasification capacity worldwide was 84.2 Bcf/d at the beginning of 2016 (excluding the United States,

where most LNG-receiving terminals are idle or being converted to export terminals.).70 Regasification 

capacity in Asia Pacific at the beginning of 2016 was 50.4 Bcf/d, or 63% of the non-U.S. total. LNG

imports were 31.9 Bcf/d in 2015, implying a utilization factor for non-U.S. regasification capacity of 

about 38%. With about 7.3 Bcf/d of new regasification capacity coming online in the near future (of 

 68 International Group of Liquefied Natural Gas Importers (GIIGNL), “The LNG Industry: GIIGNL Annual Report 2016 Edition” 

(accessed October 12, 2016), 

http://www.giignl.org/sites/default/files/PUBLIC_AREA/Publications/giignl_2016_annual_report.pdf.

69 Ibid., p. 3. This corresponds to 308 million tonnes per annum using conversion factor 0.13.

70 Ibid., p. 29-31. The total of U.S. import terminals send out capacity is 18.5 Bcf/d. 
November 2016

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 30

which 5.2 Bcf/d is in Asia),71 demand for LNG is expanding slower than the supply. A surplus of LNG 

supply will likely put downward pressure on LNG prices and may lead to review and revisions of 

restrictive contract terms. 

Traditionally, LNG in Asia Pacific is bought and sold under long-term contracts.72 The contracts have 

terms that tie the supply and delivery of LNG to specific liquefaction and regasification plants, with 

contract prices indexed to oil prices. This structure guarantees developers of LNG liquefaction projects

offtake volumes and prices that support the financing of their infrastructure investments. At the same 

time, buyers of LNG also are assured that LNG supplies will be forthcoming in the long term to justify 

their own infrastructure development. 

This traditional approach to LNG contracting is changing. One sign of the change is the growth in shortterm or spot LNG sales. As indicated in Figure 6-1, spot/short-term sales have been growing steadily in 

the last 15 years. The increase in spot and short-term sales has tracked the overall increase in the global 

LNG trade and the expansions in infrastructure. In 2000, short-term sales accounted for just over 5% of 

all LNG sales; by 2015, the estimate is that about 27% of sales are of a duration less than four years. 

Figure 6-1. World LNG trade by contract duration, 2000–2015

Source: GIIGNL, The LNG Industry in 2016 and earlier years.

Another indicator, or change, is the expiration of long-term contracts. GIIGNL’s annual report for 2016, 

covering the year 2015, lists the long-term and medium-term LNG contracts in force as of the end of 

 71 Ibid., p. 26. 

72 GIIGNL considers contracts of greater than 4-years duration as long-term contracts; less than 4 years are short-term 

contracts. GIIGNL, “The LNG Industry: GIIGNL Annual Report 2016 Edition” (accessed October 12, 2016), p.6. 

http://www.giignl.org/sites/default/files/PUBLIC_AREA/Publications/giignl_2016_annual_report.pdf.

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0

5

10

15

20

25

30

35

2000 2002 2004 2006 2008 2010 2012 2014

Volume of transactions (Bcf/d)

Long- and medium-term Spot/Short-term Percent Spot/Short-term

Percent spot/ short-term
November 2016

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 31

each year. The total for 2015 volumes for these contracts comes to approximately 39 Bcf/d. Figure 6-2

shows contract volumes for Asia, Europe, and the Americas, with the middle tranche being contracts to 

the international oil companies (IOCs) for their own portfolio sales. By 2020, an estimated (cumulative) 

3.0 Bcf/d of contracts will expire, and by 2025 10.4 Bcf/d will expire. Most of these expiring contracts

are in Asia Pacific markets. These expiring volumes may be renegotiated with the same buyers and the 

contracts extended or sold to other buyers as new contracts, sellers may decide not to renew contracts 

because of resource exhaustion in the export countries, or sellers may have to divert natural gas for 

domestic uses.

Figure 6-2. LNG contracted volumes and contract expirations

Source: Calculated from GIIGNL, The LNG Industry in 2015

Another aspect of LNG contracting has been the destination clauses that restrict buyers from diverting 

LNG from the intended port to another location or reselling excess cargoes when they cannot use all of 

the contract delivered volumes. A number of press accounts have reported buyers pressing for 

destination clause relief.73 A general consensus in the industry is that destination clauses will be phased 

 73 The Hindu, Business Line, “India-Japan to Push for Removal of Destination Clause in LNG Contracts” (accessed June 6, 2016), 

http://www.thehindubusinessline.com/economy/indiajapan-to-push-for-removal-of-destination-clause-in-lngcontracts/article8106985.ece; and Platts S&P Global, “LNG buyers call for more delivery flexibility to manage supply 

glut”(accessed June 6, 2016), http://www.platts.com/latest-news/natural-gas/singapore/lng-buyers-call-for-more-deliveryflexibility-27817357.

0

5

10

15

20

25

30

35

40

45

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Asia Pacific Portfolio Europe Americas Expiring Expiring Asia Pacific

billion cubic feet per day
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 32

out.

74 There is some indication that destination clauses are indeed weakening. JERA Co. Inc. (JERA), a 

joint venture of Tokyo Electric Power Company, Inc. and Chubu Electric Power Co., Inc. formed in April 

2015, announced that it will no longer entertain destination clauses in its LNG contracts. JERA is the 

world’s largest buyer of LNG, and in a world of competitive LNG suppliers, JERA is likely to prevail.75 

Japan’s Ministry of Economy, Trade and Industry (METI) also has indicated that it will support removal of 

destination clauses in LNG contracts in an effort to enhance LNG trading.76

6.2 Natural Gas Prices and Price Formation

In Asia Pacific, natural gas end users pay a combination of market-based and regulated prices. Because

LNG provides the majority of natural gas supply in all countries of Asia Pacific except China, LNG prices 

set in the world market dominate domestic prices. Domestic prices, on the other hand, are largely 

regulated or are constrained by regulation of the pipeline transmission sector. 

In the Asia Pacific LNG market, the contract formula based on the price of crude oil delivered to Japan, 

called the Japanese Customs-cleared Crude oil price or JCC (also known as the Japanese Crude Cocktail) 

is widely used. (The formula is described in detail in Appendix D.) Buyers and sellers negotiate prices for 

delivered LNG that usually have three components: a negotiated fixed component, the JCC as published 

by the Petroleum Association of Japan, and a negotiated fraction used to multiply the JCC. The fraction 

normally discounts the JCC component. Other elements of the negotiated price can include floors and 

ceilings on the JCC component. JCC-related prices for LNG have been the norm in Asia Pacific in longterm contracts. 

The influence of the JCC is illustrated in Figure 6-3, which compares the Japan LNG price with the prices 

of natural gas in the United Kingdom, Germany, and the United States (Henry Hub). All of the indexes 

track together through 2008, and then diverge. In the U.K. and Germany, market liberalization has 

reduced the linkage of gas prices to fuel oil and introduced more gas-on-gas competition. Shale gas 

production in the United States has caused gas prices to essentially decouple from oil prices. 

Japanese electric and gas utilities are the major buyers of LNG. Prices are passed through to consumers. 

Japan does not have a backbone gas transmission network, so there is little trading of landed and 

regasified LNG, other than in the immediate vicinity of the LNG terminals. Japanese pipelines mainly 

connect LNG terminals to local markets. TPA is required in pipeline tariffs, but enforcement of these 

provisions is limited, in part because of a small infrastructure grid. 77 

 74 Reuters, “Destination clauses on LNG will soon fade away: gas union president” (accessed October 12, 2016) 

http://www.reuters.com/article/us-asia-lng-contracts-idUSKBN0LT0YY20150225.

75 The Economic Times, “Top LNG buyer Japan's JERA to accept no destination clauses” (accessed June 6, 2016), 

http://energy.economictimes.indiatimes.com/news/oil-and-gas/top-lng-buyer-japans-jera-to-accept-no-destinationclauses/51850296.

76 Ministry of Economy, Trade and Industry (METI), “Strategy for LNG Market Development: Challenges and Countermeasures 

toward the Creation of Flexible and LNG Market and LNG Trading Hub in Japan” (accessed May 2, 2016), 

http://www.meti.go.jp/english/press/2016/pdf/0502_01a.pdf.

77 International Energy Agency, “Natural Gas Information” (accessed September 10, 2016).

http://wds.iea.org/wds/pdf/Gas_documentation.pdf. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 33

Figure 6-3. Selected natural gas and LNG prices, 2000–2015

Source: BP Statistical Review of World Energy June 2016, p. 27. 

Note: cif refers to cost, insurance, and freight; see Appendix B for definition.

The Japanese domestic market is undergoing a major liberalization reform. Liberalization of the 

electricity market commenced in April 2016, and liberalization of the domestic natural gas market will 

begin in 2017. The reforms could allow Japanese gas buyers to secure a more flexible and marketresponsive gas supply. According to METI, “To adapt to such changes, Japanese companies will attempt 

to leverage a flexible market as means for optimizing and hedging quantities and prices of their LNG 

portfolio. In the near term, there may be more cases where some purchasers that have surpluses under 

long-term contracts become spot sellers both within Japan and overseas.”78

Prior to 2007, China consumed only domestic natural gas. China’s internal gas pricing system balanced 

the cost of production, transmission, and distribution with affordability. The National Development and 

Reform Commission (NDRC) regulated prices at each step along the value chain to recover the cost of 

production through distribution, but did not reflect the value of demand. (See Appendix D.) Once

China’s demand began to exceed domestic supply, pipeline imports from central Asia and LNG were 

needed to make up the difference. These sources cost more than domestic gas. In 2011, China began a 

pricing reform that tied the price of incremental supplies to the prices of alternative fuels—fuel oil and 

liquefied petroleum gas (LPG). An important aspect of the reform, from the point of view of this paper, 

is the use of Shanghai as the market location for setting the price. Besides being China’s largest city by 

 78 METI, Strategy for LNG Market Development Creating flexible LNG Market and Developing an LNG Trading Hub in Japan, May 

2, 2016, p. 4. 

$0

$2

$4

$6

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$10

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$14

$16

$18

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

USD/ MMBtu

Japan LNG (cif) U.K. NBP German pipeline import US Henry Hub
November 2016

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 34

population and a worldwide financial center, Shanghai and environs are a large consumer of natural 

gas.79 Prices in China remain regulated, even as LNG is purchased on the world market.

South Korean gas supply is dominated by Korean Gas Company (KOGAS), which operates a monopoly on 

gas transmission and sales. South Korea is almost entirely dependent on LNG. Prices are passed through 

to consumers usually with a month or more delay. 

Malaysia, Myanmar, Vietnam, Indonesia, Thailand, Philippines, and Singapore combined have a total gas 

consumption about half of that of China, Japan, and South Korea. The major characteristics of these 

countries are:

• Several have domestic gas resources and trade within the Association of Southeast Asian 

Nations (ASEAN) zone 

• Individual markets are dominated by monopolies for gas production, transmission, and 

distribution

• They have different regulatory regimes and hydrocarbon subsidy programs for consumers and 

most have gas price regulation

• Pipeline interconnections between countries are limited and mostly bilateral 

With the exception of Singapore, these countries have made little progress toward liberalization that 

provides a foundation for competitive natural gas price setting based on underlying demand-supply 

fundamentals. The government of Singapore has moved to liberalize its gas market in an effort to create 

an internal market for natural gas and to establish itself as an LNG trading hub. This includes

encouraging a spot market for gas, TPA, and a secondary market for domestic gas consumers. 

Singapore’s large refining capacity has enabled it to become an oil pricing point. Its location in the 

center of Southeast Asia gas pipeline network and astride major seaborne trade routes to Asia from the 

Middle East and Australia provides a strategic base for establishing an LNG trading hub. 

6.3 Conditions for the Development of a Natural Gas Market Hub in Asia

LNG is the dominant supply for natural gas in Asia Pacific. The infrastructure around LNG is 

fundamentally different from the pipeline-based markets in the United States, Canada, Europe, and the 

U.K., where gas market hubs have developed. The national gas markets in Asia Pacific are in the early 

stages of liberalization, with the exception of Singapore with its fully deregulated gas market. Pipeline 

interconnections between countries are limited to the ASEAN region. 

The national markets in Asia Pacific at present are largely undeveloped and do not appear to provide a 

foundation for market hubs within the individual countries. This is because of underdeveloped 

infrastructure, government regulation of prices to make gas affordable, and the small size of the 

markets. Because the marginal supply of natural gas is LNG in Asia Pacific, the question is whether 

conditions exist within the LNG market that would support market hub development where price 

 79MIT, ““Natural Gas Pricing Reform in China: Getting Closer to a Market System?” (accessed October 2, 2016), 

http://www.sciencedirect.com/science/article/pii/S0301421515002451. This paper offers an in-depth description and 

evaluation of the effects of the policy. 
November 2016

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 35

discovery would take place. The prerequisite for this includes an active spot market for LNG, where the 

price of LNG is unbundled from its delivery mechanism and buyers have easy access to the LNG market 

(the equivalent of TPA). A spot market is expanding for LNG in Asia Pacific, but unbundling LNG from 

restrictive contract terms for its delivery and TPA to regasification facilities has been quite limited. This is 

true in the major LNG importing markets of Japan, South Korea, China, and the ASEAN countries. 

In considering the stages of development listed in Table 3-1, the picture is mixed. Only Singapore has 

fully achieved stages 1 and 2 as a practical matter. Bilateral trading dominates the market (stage 3), 

albeit under long-term contracting. At the same time, a number of PREs report prices of LNG trading in 

the nascent spot market that includes brokered trading (stage 6) and attempts at indexation. 

Governments in Asia Pacific are seeking ways to make the LNG and domestic gas markets more market 

based with varying efforts at liberalization. 
November 2016

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 36

7 Market Hub and Price Index Developments in Asia Pacific 

At present, there are no natural gas or LNG market hubs in Asia Pacific that provide the type of price 

discovery that can be useful for indexation of contract prices. While there is much interest across the 

region in developing such a hub, efforts to-date have been limited, in large part due to the absence of 

large volume pipeline interconnections or a significant spot market in pipeline gas or LNG trading. The 

amount of pure spot trading is small relative to the size of the market. Most of the trading is done under 

long-term contracts, with a growing share of short-term contracts. Prices are either fixed through 

negotiations, or reference various oil and gas indexes. 

7.1 Market Hub Developments

7.1.1 Japan

Except for a small volume of domestic production, Japan is entirely dependent on LNG imports. With 33 

operating LNG import terminals on the islands, Japan’s pipeline infrastructure is designed to connect the 

terminals and nearby markets80 (Figure 7-1). There is little pipeline interconnectivity among regions, 

hence little in the way of an integrated national market. This market is dominated by a mix of large 

electric utilities, gas distribution utilities, and large industries. 

Figure 7-1. Japan’s natural gas infrastructure, 2015

Source: IEA, Natural Gas Information (2016 edition), p. VI 43.

 80 International Group of Liquefied Natural Gas Importers (GIIGNL), The LNG Industry: GIIGNL Annual Report 2016 Edition, 

(accessed September 15, 2016), 

http://www.giignl.org/sites/default/files/PUBLIC_AREA/Publications/giignl_2016_annual_report.pdf.
November 2016

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 37

Japan has initiated a liberalization of the power sector, and in April 2017, will begin liberalizing the

natural gas sector by opening up the residential and small commercial user’s market to full 

competition.81 To support this market restructuring, the METI released the 2016 “Strategic Energy Plan”

that includes a number of initiatives to secure “greater supply flexibility and resiliency and market 

utilization.”82 This policy implies that there will be more potential players in the gas market seeking 

access to LNG terminals, as well as buying and selling gas system-wide. Eventually, this may evolve into 

gas trading on a larger scale than is now the case. 

The Japanese government believes that a market hub located in Japan would provide valuable price 

information for both the domestic and the global LNG market. The JCC LNG pricing formula has long set 

gas prices across Asia Pacific. More recently, the Platts JKMTM price, which represents LNG trades in 

Japan and South Korea, has provided indication of spot market prices for the region. A major step 

toward the development of a liquid trading hub would be the establishment of reliable price indexes 

based on competitive market forces. METI accepts that multiple LNG price indexes across Asia Pacific 

can develop to reflect local supply-demand balance and establish prices in relation to the larger 

Japanese market. 

Given the ongoing liberalization of the power and gas markets in Japan, METI encourages the Tokyo 

Commodities Exchange to “design and improve systems while proceeding with its efforts to create a 

comprehensive energy market.”83 Although METI believes market players will cooperate in the 

development of a Japanese index by providing information, contributing to the development of physical 

infrastructure, and publishing accurate transaction prices, the Ministry itself plans to take the lead in 

facilitating communications and ensuring that appropriate indexes are developed.

Japan’s current “Strategy for LNG Market Development” highlights several areas in which federal 

regulatory support will guide and enable the development of a new procurement model that is delinked from crude oil prices and puts less emphasis on long-term contracting. This regulatory support 

could allow the country to develop a larger, more liquid hub with lower transaction costs. METI’s stated 

goal is that Japan obtains internationally recognized LNG hub status by the early 2020s. METI has 

identified three policy initiatives to further this goal:

84

1. Enhance the tradability of LNG and natural gas–METI will promote the elimination of destination 

clauses in LNG contracts that it views as a barrier to easier trading.85 METI will also work to 

resolve other barriers to trade, promote wider use of natural gas and LNG, improve pipeline 

connectivity, work with other countries and industries to develop standard practices and 

uniformity, improve tanker access to LNG terminals. 

2. Create a proper price discovery mechanism–METI will encourage further spot trading and the 

development of price indexes that reflect gas supply and demand fundamentals. 

 81 METI, “Strategy for LNG Market Development” (accessed October 3, 2016), 

http://www.meti.go.jp/english/press/2016/pdf/0502_01b.pdf.

82 Ibid., p. 2. 

83 Ibid., p. 13.

84 Ibid., p. 7.

85 Japan’s Fair Trade Commission has launched an inquiry into destination clauses to determine whether the restriction on 

resales violates Japan’s competition laws. See Bloomberg News, “Japan Said to Review if LNG Contracts Baring Resale Violate 

Law.” July 14, 2016. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 38

3. Enhance the physical infrastructure and improve access–METI will promote TPA to LNG 

terminals and to the gas network and support efforts to improve the LNG, pipeline, and storage 

infrastructure. 

Additionally, the physical components of Japan’s natural gas market restructuring reflect the following 

four key priorities: 

1. Make physical gas traded within the country interchangeable. Whether a high-BTU or low-BTU 

standard is established, it is critical that gas distributed and consumed in various regions of the 

country be of a similar quality if national pipeline infrastructure is to be used effectively to 

balance local markets.

2. Increase the current number of interconnecting pipelines to support growing volumes of gas 

transport and trade. A greater number of pipelines ought to be interconnected with each other 

to ensure that localized LNG imports do not skew national gas pricing mechanisms. 

3. Solve gas dispatch issue. This may be accomplished through the establishment of an 

Independent System Operator (ISO) and the construction of substantial ‘backbone’ gas 

transportation infrastructure. 

4. Establish transparent cost recovery system with a fee structure to promote the construction of 

new infrastructure (including pipeline, storage and backbone systems). Without a guarantee of 

cost recovery, private local distribution companies are unlikely to invest in interconnecting 

infrastructure at the scale necessary to catalyze Japan’s national gas distribution system growth 

and to support the near-term development of a national hub for price discovery. 

Structural changes to Japan’s physical gas infrastructure and the removal of associated trade barriers 

could further support market restructuring, but Japan has yet to develop a substantial pipeline 

interconnectivity and TPA. As long as LNG import terminals remain customized to a single importer’s 

supply portfolio, third party access will necessarily also be limited.

Since the national gas industry is dominated by private local distribution companies, which supply the 

majority of gas for commercial and residential use, both regulatory and financial incentives provided by 

the government to private industry could expedite market restructuring. One major paradigm shift 

would involve the restructuring of the gas delivery system by placing both transportation and

distribution infrastructure under the jurisdictional oversight of an ISO. This would ensure open access to 

the gas delivery and storage infrastructure necessary to promote market liberalization. While local 

distribution systems could remain under private ownership and operation, the overall gas import and 

delivery system (including both import terminals and gas pipelines) would be overseen by the ISO. 

Concurrent regulatory support to promote greater gas system interconnectivity would further enable 

market liberalization. Standards dictating the heat content and other quality specifications (also referred 

to as ‘interchangeability’) of natural gas being transported and traded could promote the 

interconnectivity of regional pipeline infrastructure. Implementation barriers do exist, however, as a 

standard for gas quality would also require either the downgrading of high-BTU gas (by fractionation to 

remove ethane and other petrochemicals or dilution of high-BTU gas with nitrogen) or the upgrading of 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 39

low-BTU gas by the addition of ethane after importation and prior to distribution. A system capable of 

conveying large quantities of gas transnationally would also be crucial to ensure gas markets are able to 

be balanced in various regions of the country. This transport function could be served in one of two 

ways: by a substantial ‘backbone’ pipeline capable of connecting multiple local distribution systems, or 

by a fleet of LNG shuttle tankers capable of transporting small cargo volumes efficiently from one region 

of the country to another.

Finally, in addition to the necessary physical gas infrastructure expansion and concurrent market 

liberalization in Japan supported by METI, development of the fundamentally-global LNG market will be 

aided by international as well as intra-national collaboration. Japan may wish to engage and promote 

collaboration with other countries to promote LNG trading, including Qatar, Australia, Russia, United 

States, the G7, the G20, and other international organizations to address the barriers to LNG trading.

One way of doing so may be to promote dialogues with all private sector market players and support

newcomers to the LNG market involving LNG trading, operation of open-access LNG terminals, or LNG 

bunkering.

Although the outlook for a Japanese trading hub is uncertain, METI has outlined several initiatives 

designed to overcome barriers to development. For a trading hub to become larger and more liquid, 

there needs to be a much more robust trade in physical LNG on the spot market.86 A more robust trade 

in turn depends on greater flexibility in LNG commercial operations, while at the same time, a spot 

market must have some way of identifying a market price in order to develop. By working to promote a 

national market index for LNG and by examining opportunities to support market liberalization through 

financial and regulatory incentives, the Japanese government is encouraging private sector activities 

that may pave the way for the eventual development of greater centralized spot trading and a gas 

market hub where price discovery can take place.

7.1.2 China-Shanghai

China, like Japan, is pursuing policies that would establish a regional market hub that reflects the gas 

market conditions applicable to the mainland. The focus has been on Shanghai, which besides being 

China’s largest city, is also a significant market for natural gas that receives both pipeline and LNG 

supplies. The pipeline network in eastern China is relatively well developed, interconnecting markets 

with supplies.87 Shanghai also has access to several LNG terminals along the coast through the pipeline 

network. 

The government of China has taken steps to set up institutions to promote more market-driven oil and 

gas trading. The Shanghai Petroleum Exchange (SPEX) began offering spot LNG contracting in 2010. In 

2013, the Shanghai Free Trade Zone and Shanghai International Energy Trading Center were established 

to facilitate the international trading of oil and gas. In July 2015, the Shanghai Petroleum and Natural 

Gas Exchange (SHPGX) was launched to provide a market-based trading platform for oil and gas. The 

SHPGX reports daily trades in pipeline natural gas and LNG. For the first six months of 2016, there were 

 86 METI, “Strategy for LNG Market Development” (accessed October 10, 2016), 

http://www.meti.go.jp/english/press/2016/pdf/0502_01b.pdf.

87 International Energy Agency, Developing and Natural Gas Trading Hub in Asia: Obstacles and Opportunities, accessed 

September 5, 2016.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 40

458 LNG trades, averaging 20,000 MMBtu per trade from the Ningbo LNG import terminal near 

Shanghai.88 The reported prices in Figure 7-2 show a stair-step pattern of stable prices for a period of 

time, followed by an adjustment that appears to be related to LNG cargo deliveries and not to marketclearing activity. 

Figure 7-2. Price of LNG imported to China (Shanghai), 2016

Source: Shanghai Petroleum and Natural Gas Exchange, 2016. Cargoes delivered to Ningbo terminal near Shanghai through July.

Chinese companies purchase LNG under long-term, short-term, and spot contracts. But, as in Japan, the 

Chinese market is in the midst of reforms that should eventually lead to market-based gas pricing. At 

present, the pricing system remains opaque and the city-gate prices, which are regulated by local 

authorities, and are managed to subsidize residential consumption at the expense of industrial uses. 

Pipeline gas pricing under the formula shown in Appendix D is administratively determined. Three sets 

of prices prevail:

• domestic pipeline gas priced by formula

• LNG and imported pipeline gas priced under bilaterally-negotiated long-term contracts

• LNG and imported pipeline gas priced in reference to oil prices (JCC, for example)

Over time, if the reforms continue, a market hub could develop that would reflect the interplay 

between pipeline gas and LNG imports. 

 88 Shanghai Petroleum and Natural Gas Exchange, “LNG Data” (accessed August 22, 2016), 

http://www.shpgx.com/web/news/datasingle.jsp?parentid=49&classid=94. 

$8

$9

$10

$11

$12

$13

$14

Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16

USD/MMBtu
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 41

7.1.3 Singapore

Singapore, like Shanghai, receives both pipeline gas and LNG, but is not a large gas market, with 

consumption of only 1.09 Bcf/d in 2015.89 Natural gas is primarily used in power generation and 

industrial sectors; residential and commercial sectors rely on manufactured gas. Singapore has a single 

natural gas transporter that provides open-access transportation to importers and other natural gas 

suppliers. Buyers are free to buy natural gas from any supplier. The sector is regulated by the Energy 

Market Authority (EMA), which oversees the power and oil sectors.90 Singapore has a more freewheeling business economy that allows for the development of an LNG trading center. 

Singapore offers some advantages as an LNG market hub for Asia Pacific. Singapore is strategically 

located and the port can accommodate large LNG tankers. Singapore LNG Corporation has been 

expanding its LNG facilities to increase receiving and storage capacity and allow re-export of LNG.

As a foundational market for a gas hub, Singapore’s size and infrastructure are problematic. Despite 

significant expansion of storage, the storage capacity remains small relative to the size of the LNG 

market in Asia Pacific. 

7.1.4 Summary of Asia Pacific Hub Developments

The markets in Japan and in Shanghai, China are still in the development phase and do not yet appear to 

support a robust gas market hub where prices reflect the balance of supply and demand from numerous 

bilaterally negotiated transactions. The Singapore market is more open, but small. It is unlikely that any 

of these markets could soon serve as a market hub that provides price signals for the whole Asia Pacific. 

Rather, it is more likely that LNG price indexes covering the entire region, or a significant part of it, will 

grow in prominence at the same time that localized market hubs would emerge in China (Shanghai), 

Japan, Singapore, and perhaps other markets as they liberalize and evolve. The absence of a physical 

market hub representative of Asia Pacific has not limited the development of several LNG price indexes 

published by PREs and need not be a limiting factor in the future. 

7.2 Indexes Tracking LNG Prices in Asia Pacific

Several price indexes have been developed to track LNG trade in Asia. These include the Japan Monthly 

LNG Spot index tallied by METI, the East Asian Index (EAX) tracked by ICIS Heren, the Platts Japan and 

South Korea Index tracking the price of LNG delivered to these two countries (JKMTM), and the Singapore 

Exchange LNG Index (SLInG) compiled by SGX. 

7.2.1 Japan Monthly LNG Spot

METI developed the Japan Monthly Spot index to track contract prices for the LNG cargoes delivered to 

Japan. In 2014, METI began publishing the results of a monthly census distributed to LNG market 

 89 BP, “Statistical Review of World Energy” (accessed October 2, 2016), https://www.bp.com/content/dam/bp/pdf/energyeconomics/statistical-review-2016/bp-statistical-review-of-world-energy-2016-full-report.pdf. Million metric ton of oil 

equivalent converted to Bcf using 39.2 Bcf per million metric ton oil equivalent.

90 Singapore Energy Market Authority, “About Us” (accessed October 13, 2016), https://www.ema.gov.sg/index.aspx.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 42

participants that tracked the LNG bid and offer prices among active traders.91 This has provided some 

indication of LNG value. 

METI polls 15 market participants on a monthly basis for the prices of delivered LNG called delivery exship (DES) prices. Reported LNG prices include prices of both contracted and delivered LNG in that 

month and exclude names of trading companies (to protect confidentiality of transactions).

92 This 

method results in the creation of two indexes—the Contract-based monthly LNG spot price and the 

Arrival-based LNG spot price. The Contract-based price reflects the pricing for those deals made within 

the month, and the Arrival-based price includes prices of LNG cargoes, which arrived during the survey 

month. The Japan Monthly LNG Spot price index applies to ships of any cargo size with spot LNG freight 

to be delivered to any location in Japan. 

7.2.2 East Asian Index (EAX)

The EAX is published by ICIS Heren and is calculated by averaging each day’s DES front-month and 

second-month ahead assessments for Japan, South Korea, Taiwan, and China.93 Price assessments for 

the EAX index are published daily.

94 The EAX index relies on surveys conducted via phone and online 

with a variety of market participants (gas producers, LNG brokers and traders, and LNG end users). Price 

assessments are completed for prompt delivery up to 90 days ahead.95 Five half-month contracts are 

assessed for the second, third, fourth, fifth, and sixth half months ahead.96

All standard LNG cargo sizes are eligible for price discovery, with tanker capacities ranging from 30,000 

cubic meters (m3

) LNG (0.6 Bcf) to 266,000 m3 LNG (5.6 Bcf)97. The largest volume is the capacity of the 

”Q-Max” tankers, which refers to the Qatar Max carrier, the largest LNG carrier class in the world at 

267,335 m3 LNG or 5.7 Bcf of capacity.98

7.2.3 Japan South Korea Marker (JKMTM)

Platts Japan South Korea Marker (JKMTM) is estimated from daily surveys of market players (the number 

of survey participants is unknown) via phone or other electronic forms of contact. The JKMTM price 

assessment for any given delivery period is based on trades, bids, and offers that must be both recent 

and repeatable.99 Requiring the “repeatability” of trades supports price transparency by ensuring that 

one-time sales of single cargoes either below market price (for the purpose of liquidating a cargo 

immediately) or above market price (to a shortage-strapped buyer) do not unduly impact market 

volatility. 

 91 Japanese Ministry of Economy, Trade and Industry, “Trend of the Price of Spot-LNG” (accessed September 16, 2016), 

http://www.meti.go.jp/english/statistics/sho/slng/result/pdf/201605-e.pdf.

92 Ibid., p. 2. 

93 ICIS Heren, “LNG Markets Daily Methodology” (accessed October 2, 2016), https://s3-eu-west-1.amazonaws.com/cjp-rbi-iciscompliance/wp-content/uploads/2016/05/Global-LNG-Markets-Methodology-12-May-2016.pdf.

94 Ibid., p. 3. 

95 Ibid., p. 7. 

96 Ibid., p. 12. 

97 GIIGNL, The LNG Industry, annual report, 2016, pg. 14-18.

98 Maritime Connector, “Q-Max” (accessed October 14, 2016), http://maritime-connector.com/wiki/q-max/. 

99 S&P Global Platts, “Platts JKMTM (Japan Korea Marker) Gas Price Assessment: Price Assessments” (accessed October 12, 

2016), http://www.platts.com/price-assessments/natural-gas/jkm-japan-korea-marker.
November 2016

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 43

Platts LNG assessments are market-on-close (MOC) prices and include all transactions for cargoes within 

the range of standard ship sizes.100 Development of the daily JKMTM price assessment considers 

information that is not directly reported but that affects market supply or demand fundamentals, such 

as current shipping costs (including fuel prices), production maintenance, tender issues, and weather 

data.101

7.2.4 SGX LNG Index Group (SLInG)

The SGX LNG Index Group is a joint venture of Energy Market Company (EMC), which operates 

Singapore’s electricity market and Singapore Exchange Limited (SGX), that has developed a Singaporebased spot LNG index, called SLInG index. The SLlnG relies on a survey of market participants for its price 

assessments, an average price that LNG traders, exporters, and importers report. The number of market 

participants contributing to the SLInG index has increased since its inception. In September 2014, the 

Index received input from only 5 participants.102 By June of 2016, SGX estimates that approximately 50 

market participants provide the input used to calculate the Index.103

Participants provide half-monthly spot price assessments for the upcoming 3rd through 6th half-calendar 

months, based on the expected value of an LNG cargo slated for delivery at a given location during that 

timeframe.104 The SLInG price assessment applies to vessels on the water in the vicinity of Singapore 

that are not destination limited. The standard cargo size for ships eligible for SLInG consideration is 

between 135,000 m3 LNG (2.9 Bcf) and 175,000 m3 LNG (3.7 Bcf). The index value—based on the 

calculated average of the half-monthly prices for the first full month of price assessments—is currently

published twice weekly.

In 2016, SGX expanded service offerings to include swap and futures contracts. As the spot LNG market 

in Asia Pacific continues to develop, SGX and EMC expect to see greater volumes of spot LNG traded. 

With greater spot volumes and a larger number of bilateral deals, the SLInG Index operators expect to 

see greater opportunity for index-based LNG OTC trading. Starting in September 2016, SGX LNG also 

provides price assessment for a North Asia LNG price series alongside the SLlnG Index. The first reported 

data show the North Asian index being approximately $0.25/MMBtu higher than the Singapore-based 

SLInG index.

7.2.5 Other LNG Indexes

The SLInG index tracks free on board (FOB) prices for LNG, assessed as if being shipped from Singapore. 

The three other indexes tracking Asia Pacific LNG prices conduct their price assessments for LNG DES. 

Comparing SLInG with other indexes requires accounting for transportation costs in addition to the 

SLInG price assessment. With the expansion of liquefaction capacity, some PREs are now reporting FOB 

prices in producing markets. Platts reports FOB prices for the Middle East and Australia, where the latter 

 100 Ibid.

101 Ibid.

102 Energy Market Company and SGX, “SLInG FAQs” (accessed September 3, 2016), 

https://www.emcsg.com/f1415,106648/FAQ_for_LNG_Nov_2015_Final.pdf.

103 Notes from call with SGX on Asia Pacific Gas Markets, 21 June 2016. 

104 Energy Markey Company, “Methodology and Specifications Guide: SGX LNG Index Group” (accessed September 12, 2016), 

https://www.emcsg.com/f1415,99779/SLInG_Methodology_and_Specifications_Guide.pdf.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 44

is derived by subtracting current tanker rates from the JKMTM index. (Australia LNG is largely stranded, 

with little internal market for the gas and only an export market. Australia inaugurated a gas supply 

market hub in 2014 in Queensland to facilitate the marketing of gas to Australia’s southern domestic 

markets and its east coast LNG export facilities.)105 Other PREs also report various FOB prices for LNG, 

including U.S. Gulf Coast (by ICIS), African locations (by Argus), and Europe for reloads (by Argus). 

Other DES indexes remain in early stages of maturity. In February 2016, the CME Group introduced the 

LNG DES Japan futures contract trading through the Japan OTC Exchange (JOE) and other OTC brokers. 

The contract is based on the price settlements index developed by RIM Intelligence Co. of Japan. The 

LNG DES Japan (or RIM) futures standard contract is for 10,000 MMBtu and uses the spot LNG price 

assessments for LNG Japan DES for price settlements by RIM Intelligence. Based on a review of the CME 

website, there appears to be no trading in this contract.

7.2.6 Comparison of Asia Pacific LNG Indexes

While the value of price discovery at individual hubs is determined by market factors, including the 

number of participants and the volumes of pipeline gas and LNG exchanged at a given location, price 

discovery for the entire Asia Pacific region is most readily conducted by examining a core group of 

indexes tracking LNG pricing. These include the indexes charted in Figure 8 and sourced from EAX, METI, 

Platts, SGX and other regional price assessments, e.g., Argus Media (ANEA index), RIM Intelligence (for 

Japan, South Korea, and Singapore), and Platts JKMTM. 

Table 7-1 summarizes selected price indexes in Asia Pacific. All indexes are quoted in U.S. dollars per 

MMBtu. 

 105 Australian Energy Market Operator, “Gas Supply Hubs” (accessed August 18, 2016), https://www.aemo.com.au/Gas/GasSupply-Hubs.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 45

Table 7-1. Characteristics of Asia Pacific LNG price indexes

Index Japan/METI JKMTM RIM Japan ANAE EAX SLInG

Publisher METI Platts RIM 

Intelligence Argus Media ICIS SGX & EMC

Start of Stats Mar. 2014 Feb. 2009 Feb. 2016 2012 Jan. 2014 Sept. 2014

Ship (Cargo) 

Size Any 2.9–3.7 Bcf 2.9 Bcf tankers & 

partial cargoes

2.9–3.3 Bcf & 

partial cargoes 

normalized

0.6–5.6 Bcf & 

partial volumes 2.9–3.7 Bcf

Index 

Coverage Area

LNG delivered to 

Japan

Spot physical 

cargoes delivered 

into Japan and 

South Korea

Japan, South 

Korea, Taiwan 

and China

Japan, South 

Korea, Taiwan, 

China

Physical cargoes 

to Japan, South 

Korea, Taiwan & 

China 

Vessels on the 

water with 

potential to 

deliver to 

Singapore

Assessment 

Type

Census sent from 

METI to market 

players

Daily phone or 

electronic survey 

of market players

Trading info from 

OTC market; 

Price assessment 

from JOE LNG 

market deals & 

bids/offers

Daily phone or 

electronic survey 

of market 

participants

Daily phone or 

electronic survey 

of bids, offers 

(first-hand or 

observed)

Survey of select 

market 

participants

Assessment 

Frequency

Monthly price 

assessments

Daily, with 

market close 

prices

Assessed & 

published daily

Assessed & 

published daily

Assessed & 

published daily

Half-monthly 

assessments, 

published twice 

weekly

Sale or 

delivery 

DES contracted 

and arrival DES DES DES DES FOB

Assessment 

Forward 

Range

Any forward 

period for LNG 

delivery 

(contract-based); 

within-month 

(arrival-based)

Prompt delivery; 

3rd & 4th or 4th 

& 5th half-month 

forward

Half-monthly 

assessments for 

the 3rd–5th halfmonths forward

Prompt delivery; 

2nd–5th halfmonths forward

3rd–6th halfmonths out3rd–6th halfmonths out

Index 

Calculated

Contract-based 

(for deals made 

in-month) and 

arrival- based (for 

cargoes arriving 

that month)

Prompt or 

deferred spot 

prices averaged 

for assessed halfmonths

Monthly average 

price for halfmonths 

calculated daily

Physical and 

forward swap are 

assessed daily for 

forward halfmonths

Daily front and 

second month 

ahead prices for 

all countries 

averaged

Half-monthly 

prices are 

averaged for the 

first full month

Types of 

Trades 

Included

Spot LNG to be 

delivered

Spot LNG to be 

delivered

Deals done and 

bids/offers on 

LNG cargoes

Spot LNG to be 

delivered in 6–12 

weeks

Global prompt & 

mid-term charter 

LNG

Spot LNG able to 

be shipped to 

Singapore

Number of 

Contributors ~ 15 Not specified in 

Methodology

Not specified in 

Methodology

Not specified in 

Methodology

Varies daily; no 

minimum data 

threshold

50

Contributor 

Requirements

Companies/ 

consumers of 

spot LNG

Any market 

participant; buy/ 

sell prices must 

pass the 

”repeatability”

test

None; market 

prices assessed 

from OTC market 

trading 

information

All credible 

market sources,

market 

participants and 

brokers/trading 

platforms

Active or past 

LNG industry 

participants, not 

only the physical 

market

Active in the 

physical LNG 

market

Data Cleaning N/A

Data aligned with 

standard 

assessment 

specifications

Higher bids & 

lower offers are 

prioritized as 

closer to market 

values

Market condition 

adjustments if 

assessment 

hierarchy would 

skew results

Data verified with 

trading 

counterparty; 

technicalpurpose cargoes 

excluded

Top 15% and 

bottom 15% 

removed as 

outliers
November 2016

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 46

The lack of data makes estimations of the churn rate for LNG trading in Asia Pacific very difficult. A 

reasonable estimate is that it is probably just over 1.0. There is not a substantial amount of trading on 

the exchanges for derivative products and information on re-trading of physical volumes is based on 

anecdotes. Trading in JKMTM futures has been modest in volume and has grown from 201 trades in 2012 

to 270 trades in 2013, 1,654 trades in 2014, and 2,791 trades in 2015.106 This represents 28 trillion Btu 

of futures trading in 2015, about 0.5% of recent annual LNG consumption in Japan and South Korea.

Figure 7-3. Comparison of price indexes for spot LNG in Asia Pacific, 2014–16

Sources: Japan Ministry of Energy, Trade, and Industry, Singapore SGX, and Platts. 

As shown in Figure 7-3, LNG price indexes in Japan and Singapore can vary, but generally track each 

other. Note that the Singapore SLInG Spot LNG index reflects a price assessment for FOB LNG. The three 

other indexes track DES LNG pricing, which includes insurance and transportation costs in the sales 

price.107 The indexes reflect both reported deals and expert judgment from the index participants, which 

may influence their congruity. In large part, the indexes follow one another as expected. The two METI 

indexes are post-delivery summaries of prices paid in the previous month. The SLlnG and JKMTM track 

quite closely. There is no price assessment for the China Shanghai index that reflects day-to-day market 

transactions. 

 106 Center for Energy Economics, “LNG Supply Outlook 2016 to 2030” (accessed October 20, 2016), 

http://www.beg.utexas.edu/energyecon/thinkcorner/CEE_Advisor_Research_Note-Andy_Flower_LNG_Supply_OutlookAug16.pdf.

107 NatGas.info, “Gas Pricing” (accessed July 11, 2016), http://natgas.info/gas-information/what-is-natural-gas/gas-pricingcontracts.

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

Japan Contract-based Spot LNG Import Price (METI) Japan Arrival-based Spot LNG Import Price (METI)

Singapore SLInG Spot LNG Index (SGX) JKM

USD/MMBtu
November 2016

U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 47

Looking across the prospective hubs and pricing indexes in Asia Pacific, the following conclusions can be 

drawn: 

• Japan does not have the physical infrastructure or TPA to transport natural gas between 

domestic market participants. If Japan could solve its infrastructure limitations and gas quality 

issues (different gas specifications at different points of entry due to LNG sourced from multiple 

countries), then it could increase liquidity. METI’s “Strategy for LNG Market Development” 

provides high-level details but little information on concrete steps that need to be taken to 

overcome existing limitations for the hub development. The government is committed to 

supporting private sector initiatives focused on development of a trading regime for natural gas 

that could lead to the establishment of a reliable natural gas market hub. METI’s stated goal is 

to become the “internationally recognized hub by the early 2020s.”108

• China (Shanghai) has a developed infrastructure; however, the Chinese government’s close 

involvement with price setting and market control may be viewed as a deterrent by potential 

participants. There is no meaningful TPA as of yet.

• Singapore is considered a strong candidate for an Asia-wide market hub because its price 

reporting is transparent. It may be acceptable as an independent location to both Chinese and 

Japanese buyers. However, it does not have integrated physical infrastructure or storage 

capabilities for a liquid hub, is a small market, and is distant geographically from both Japan and 

China. 

• Proposed FOB price indexes in the U.S. Gulf Coast (USGC) and Eastern Australia as price setters 

for Asia Pacific markets may be useful in special circumstances. For example, a buyer of gas 

priced at a USGC liquefaction terminal (and typically tied to Henry Hub) may resell the gas in 

Asia Pacific at a USGC price, plus or minus some cost adjustment. It is unlikely that these FOB 

prices would have a major influence on Asia Pacific market prices given the size of the consumer 

markets and the variety of alternative supply sources available to the region. 

• LNG price indexes for Asia Pacific offered by the various competing PREs provide a degree of 

price discovery. The indexes strive to provide accurate and vetted price assessments and appear 

to be reliable. Absent a market hub, these indexes provide actionable price information. That 

said, the market will decide which index prevails when a sufficient number of market 

participants begin using one or another index exclusively. 

7.2.7 Prospects for an Asia Pacific Gas Market Hub in Japan

The best prospect for a liquid physical hub expected to develop in the foreseeable future in Asia likely 

would be centered in Tokyo and would extend as far as there are gas pipeline connections with 

adequate capacity. The creation of the Tokyo-centered physical hub for natural gas would conceivably 

evolve into the trading of spot physical gas on a variety of time bases such as month-ahead, half-monthahead, day-ahead and intraday. Forward and futures markets would also be expected to evolve with 

products available for several months and half-months into the future. In a future scenario with robust 

trading of spot and financial products on a Tokyo hub, one would expect that the pricing of gas in the 

 108 Ministry of Economy, Trade and Industry, “Strategy for LNG Market Development” (accessed September 13, 2016), 

http://www.meti.go.jp/english/press/2016/pdf/0502_01b.pdf.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 48

hub would reflect LNG spot price indexes for future time periods for which incremental spot LNG 

deliveries are taking place and are being surveyed (that is, approximately the 3rd to 6th half-months 

forward from the present). The forward/futures hub gas prices for a specific future period would be 

expected to equal the LNG index of the corresponding time period adjusted as necessary for entry/exit 

fees109 and fuel retainage for regasification. The reason that the hub prices (after adjustments) would be 

expected to converge with spot LNG indexes is that marketers at the Tokyo hub would be able to 

sell/buy gas at the hub and balance their physical positions by bringing in incremental LNG shipments or 

by diverting shipments to other Asian market locations. 

Initially, this price arbitrage process would be subject to the practical limits of LNG transaction size (that 

is, a full ship load of roughly 3.4 bcf or a partial ship load if available of “new” LNG or a volume of 

“remarketed” LNG shuttled to/from surrounding markets). The making of the Tokyo hub as large as 

feasible by interconnecting surrounding markets would make it easier to change LNG flows to balance 

the market without overwhelming the hub’s ship offloading and LNG storage capacity and the ability of 

market to absorb or make available incremental volumes. If a close correspondence between the Tokyo 

price and the Asian LNG indexes were to take place, the Tokyo hub futures market could be used to 

hedge LNG transactions throughout Asia, in the same way that Henry Hub futures are used to hedge 

natural gas transactions throughout North America.

Short-term spot natural gas prices on a Tokyo hub (i.e., prices for spot sales today and for the next 

month or so) would reflect local market conditions and would potentially differ from short-term prices 

in any other similar hub that might develop in Asia. The short-term natural gas hub prices would reflect 

local weather, electricity demand, power plant availability and alternative fuel availability and prices. 

However, even the hub’s short-term gas prices for the next 30 days would be related to spot LNG prices 

for the next 3rd to 6th half-months in so far as marketers can change their short-term regasification 

volumes and balance those volumes with incremental LNG purchase and sales/diversions. Having a large 

hub with large LNG storage capacity will help to arbitrage prices across time periods. In this way a large 

Asian hub with large storage capacity relative to market demand would be expected to see less volatile 

short-term gas prices that correspond well with spot LNG indexes. On the other hand, smaller Asian gas 

hubs with little storage might be expected to have more volatile short-term natural gas prices. 

Which Asia Pacific countries develop liquid natural gas hubs with reliable price indexes will depend in 

part on the trading activities of buyers and sellers. While the governments of Japan and China have 

indicated a preference for the private sector to lead the way in establishing a gas trading regime, it is 

 

109 The Tokyo hub might use an entry/exit fee approach similar to what is used in European systems wherein entering gas pays 

an entrance tariff and gas exiting the system pays an exit tariff. (There would also have to be a storage fee for LNG stored 

within the hub beyond the nominal storage period included in the “entry fee” tariff.) If a transaction in the hub were based on 

an “in hub” basis then such gas would reflect the spot LNG index plus the hub entrance tariff. If the gas where sold on an “out 

of hub” basis then the hub gas prices would reflect the spot LNG index plus the hub entrance tariff, plus the hub exit tariff, plus 

the value of gas used for regasification.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 49

clear from the experience of the United States and Europe that an active government effort to 

overcome obstacles will be required. These obstacles include:

• the need to allocate the cost of restructuring legacy contracts with pricing formulae yielding 

higher-than-market prices

• resistance from franchise utilities unwilling to give up captive customers

• reluctance of infrastructure owners to make new investments to expand interconnectivity or to 

operate their systems under open access rules

• slow acceptance by market participants of the competitive rules (e.g., affiliate information 

sharing) and market monitoring requirements

• preferences of regulators for administered prices

• popular resistance to a new market system where some restructuring cost that will be socialized 

and recovered from customers is known and certain, but long-term efficiency savings for 

customers are promised but less certain

7.3 Summary Observations

The history of gas market development in the United States and Europe offers insight into the possible 

evolution of a functional gas market hubs in Asia Pacific where prices are tied to supply and demand of 

natural gas rather than to alternative fuels. In both the United States and Europe, government 

regulators initiated policies that created the opportunities for competitive gas markets to develop. The 

principal changes were the unbundling of natural gas from transportation and delivery services, the 

guarantee of non-discriminatory third-party access to transportation services, and the deregulation of 

natural gas prices. Regulators in the United States were responding to an excess supply of gas that had 

major consuming segments of the economy calling for wider access to lower-cost supply. In the United 

Kingdom, privatization of the national gas sector led to the creation of a competitive market and 

establishment of the NBP. In Europe, the desire for a U.S.-like large, internal competitive market 

precipitated EU directives to implement changes. Because the European Union is a collection of 

sovereign states, each with its own legal and institutional structures that require considerable effort to 

harmonize, producing a coordinated response to these directives took substantial international 

collaboration. Key to these experiences in Europe and the United States was the role of regulators with 

authority to make changes. Looking ahead to the anticipated development of a gas market in Asia 

Pacific, the lack of a centralized regulatory body for the region as a whole as well as a lack of legislatures 

and regulators within each country may impact the advancement of market liberalization. 

This report has attempted to distinguish between gas market hubs and gas market indexes. 

Traditionally, the operation of hubs has preceded generation of the reliable gas price information, which 

in turn evolved into reliable price indexes. 

In Asia Pacific, this traditional relationship between market hubs and price discovery may not necessarily 

hold. LNG price indexes—based on monthly and half-month delivery periods—are being established 

before any of the markets described here (China (Shanghai), Japan, and Singapore) will develop

operational natural gas hubs with reliable price indexes. Despite a lack of substantial Asia Pacific gas 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 50

transport infrastructure, of the total 4,057 global LNG voyages in 2015,

110 57% went to Asia Pacific.111

Therefore, the virtual pipeline system made up of LNG ships is heavily concentrated in the Asia Pacific 

region. Additionally, the number of trading parties is significant across the region: approximately 25 

active sellers of LNG and about 40 active buyers, including aggregators.112 Meanwhile, LNG contract 

terms are becoming increasingly flexible, buyers and sellers are seeing fewer traditional long-term deals,

prices are becoming more hybridized and creative, and actual spot market sales, while modest, appear 

to be increasing.

Table 7-2 compares Asia Pacific region with the United States and Europe in terms of the development 

of gas market hubs and reliable price indexes. 

Table 7-2. Comparison of Asia Pacific gas markets with the U.S. and European markets

Development Stage United 

States

United 

Kingdom

European 

Union Asia Pacific

1 Gas prices deregulated and gas sales unbundled 

from gas transmission Yes Yes Largely yes Not in all countries

2 Third-party access to transport facilities, 

terminals Yes Yes Yes No

3 Bilateral trading predominates Yes Yes Yes Yes in LNG, not so for gas 

in all countries

4 Transparency in pricing and volumes traded Yes Yes Yes Not in all countries

5 Standardization of trading rules and contracts Yes Yes Yes No

6 Over-the-counter brokered trading Yes Yes Yes Yes

7 Price indexation Yes Yes Yes Yes for LNG

8 Non-physical traders enter Yes Yes Yes Yes

9 Futures Exchange Yes Yes Yes Yes

10 Liquid Forward Price Curve Yes No No No

Looking at the churn rate for these markets, the United States has an estimated churn rate of between 

60 and 90 and the United Kingdom of about 22. The churn rate estimate for the European Union is 

about 5.2. The estimate for Asia Pacific is just over 1. 

The LNG trade generally, and in Asia Pacific in particular, presents a number of complications to the 

development of a market hub with a location and time-specific price index that yields price discovery for 

LNG and natural gas. The size of LNG cargoes and the uneven nature of LNG cargo delivery schedules is 

one confounding factor. Pipeline receipts and deliveries are by contrast continuous and almost 

instantaneous (i.e., a daily price at Henry Hub for next day delivery is propagated throughout the North 

American network and reflected in prices at other locations on the same day). The geographic size of the 

Asia Pacific LNG market and the distances between ports also contribute to pricing uncertainties. In 

 110 International Gas Union, “World Gas LNG Report” (accessed October 4, 2016), http://www.igu.org/publications/2016-worldlng-report.

111 Ibid, p. 9.

112 International Group of Liquefied Natural Gas Importers, The LNG Industry (accessed October 4, 2016), 

http://www.giignl.org/sites/default/files/PUBLIC_AREA/Publications/giignl_2016_annual_report.pdf.
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 51

addition, variations in gas quality among cargoes affect the comparability of prices reported at different 

locations and times. These discrepancies are not generally a problem in pipeline systems where calorific 

standards are maintained through limitations on the specification of the gas that can enter the pipeline 

system. 

All other gas market hubs have been based on pipeline models of delivery. Asia Pacific, with its heavy 

dependence on LNG, has unique characteristics. Progress towards market hub-based price discovery will 

depend on a number of developments: more spot trading of LNG, removal of destination clauses, full 

TPA to LNG facilities, and other institutional and regulatory reforms in individual countries. 

Interviews with several market participants trading LNG in Asia have provided relevant information 

about the ongoing evolution of the Asia Pacific LNG market. The general consensus is that LNG trading 

norms are undergoing many changes, with substantial variability and uncertainty developing in the 

market regarding pricing and contract terms. Legacy long-term contracts still prevail in the market. 

However, these contracts are likely to be modified in the near future. Contract terms may be reduced 

from the 20+ year average that now prevails, while in some cases the inclusion of destination clauses in 

contracts may be eliminated or modified. Futures contracts offered for Asian LNG, meanwhile, continue 

to be thinly traded at present. Short term and spot contracts are increasingly more common, but pure 

spot trades appear to account for a small percentage of the total trading. Today, pricing in most 

contracts still appears to be based on oil indexes: the JCC and Brent are most commonly mentioned. 

However, hybrid pricing that uses a combination of oil indexes and, rarely, Henry Hub or NBP, is 

beginning to appear in contract terms more frequently. 

Despite earlier discussion of the various Asian LNG price indexes that have been developed, it is unclear 

to what extent these are being used to price LNG deals. A promising development is that although the 

specific prices examined for this report from the various LNG indexes for Asia Pacific differed from each 

other due to definitional and methodological differences, their general trends track closely. The 

persistence of LNG trades linked to oil prices is understandable given the novelty and uncertainty 

around the published LNG indexes, the remoteness and disconnection of many buyers’ markets, and the 

fact that the oil indexes can be hedged in a much more liquid market. Where LNG is traded using LNG 

indexes, trades involving Japan and South Korea, which accounts for the largest share of the market,

tend to favor those indexes linked more closely to those markets. 

Based on conversations with market participants, several large LNG producers and aggregators do not 

provide market information or prices to PREs since the large market participants cannot be seen to 

influence indexes. The price assessment methodologies mentioned in this report undoubtedly include 

prices of actual transactions from parties, who do engage with the reporting agencies. However, 

participation is selective and not all transactions are reported, so estimates have to be made given the 

limited amount of reportable and reported transactions. The various indexes are perceived by the 

market to be useful indicators, but not necessarily fully reflective of all actual spot prices. 

Despite certain questions about inconsistencies among the development of LNG price indexes for the 

Asia Pacific region, it could be expected that for the near future the various published indexes will be the 

most reliable indicators of the market value of natural gas in Asia Pacific. As existing LNG price surveys 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 52

continue to improve in accuracy and increase their significance as indicators of the market price for LNG, 

indexes will be more reliably used, not only to set the pricing for sales and purchase contracts, but also 

to serve as the basis for greater volumes of futures and derivatives trading. 

Price indexes arising from physical gas trading in Japan, China (Shanghai), Singapore, or other locations 

will follow to the degree that those hubs can gain physical and financial trade volume. This is most likely 

to occur in Japan, given the size of the gas market and the policies of the government to encourage the 

development of trading in both the electricity and natural gas, infrastructure enhancements, and other 

policies to promote market development led by the private sector. It is also in the interests of Japan’s 

largest commercial LNG importers to support a market for spot trading of natural gas. However, it could 

take five to ten years to develop a natural gas hub in Japan that would provide reliable and transparent

prices. Such hub-based price indexes would reflect the monthly and half-month Asia Pacific LNG price 

indexes and potentially would expand to include hub-specific daily price discovery as well. 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 53

Appendix A. Acronyms 

ACER Agency for the Cooperation of Energy Regulators

AECO Alberta Energy Company (Canada)

AGCS Austrian Gas Clearing and Settlement

ASEAN The Association of Southeast Asian Nations

Bcf/d Billion cubic feet per day

Btu British thermal unit

CEGH Central European Gas Hub

CIF Cost Insurance and Freight

CME Chicago Mercantile Exchange

CNMC Spanish National Commission for Markets and Competition

COP Conference of the Parties

DES Delivery Ex-Ship

EAX East Asian Index

EEX European Energy Exchange

EFP Exchange for Physical Gas

EFS Exchange for Swap

EMC Energy Market Company

EU European Union

FERC Federal Energy Regulatory Commission

FOB Free on Board

GCA Gas Connect Austria

GIIGNL International Group of LNG Importers

GME Gestore dei Mercati Energetici (Italy)

GPL Germany Gaspool

ICE Intercontinental Exchange

IEA International Energy Agency

IGH Iberian Gas Hub (Spain)

IOCs International Oil Companies

JCC Japanese Customs-Cleared Crude

JKM Japan South Korea-Marker

JOE Japan OTC Exchange

LEBA London Energy Brokers Association

LNG Liquefied Natural Gas

LPG Liquefied Petroleum Gas

METI Japan’s Ministry of Economy, Trade and Industry

MIBGAS Iberian Gas Market (Spain)

MMBtu Million British thermal units

NAESB North American Energy Standards Board

NBP National Balancing Point (U.K.)

NCG National Connect Germany

NDRC The National Development and Reform Commission (China)
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NGPA Natural Gas Policy Act

NYMEX New York Mercantile Exchange

OCM On-day commodity market

OFGEM U.K.’s Office of Gas and Electricity Markets

OIES The Oxford Institute for Energy Studies

OTC Over-the-Counter

PEG Nord Point d’Exchange Nord (France)

PEG Sud Point d’Exchange Sud (France) – now part of Trading Region South

PRE Price Reporting Entity

PSV Punto di Scambio Virtuale (Italy)

SGX Singapore Exchange Limited

SHPGX The Shanghai Petroleum and Natural Gas Exchange

SLInG Singapore Exchange LNG Index

SPEX The Shanghai Petroleum Exchange (China)

TIGF Transport Infrastructures Gaz France – now part of Trading Region South

TPA Third-party access

TRS Trading Region South (France)

TTF Title Transfer Facility (Netherlands)

UNC

USD

Uniform Network Code (United Kingdom)

U.S. dollar

VTP Virtual Trading Point

ZEE Belgium Zeebrugge Hub
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Appendix B. Key Terms and Definitions

Below, key terms are organized as they appear in the report. 

A gas market hub is a physical location with interconnecting pipelines, and possibly other natural gas 

transportation and storage infrastructure that provides receipt and delivery capabilities between 

pipelines, allowing parties to exchange gas and transfer title to gas at minimal cost. Because of this 

interconnectivity, buyers and sellers of gas transact business at these hubs. Gas market hubs are 

sometimes referred to as “Market Centers” to emphasize their role in market balancing and price 

formation. 

A notional hub (also called a virtual hub) is a type of gas market hub that has all of the 

characteristics of a gas market hub, but encompasses market activities over a wide area rather 

than a single point or small area. Notional hubs are always associated with transmission

networks within which physical transfer costs are minimal. Examples of notional hubs are the 

U.K.’s NBP, Canada’s AECO-C, and the Dutch TTF. 

A transit hub is a physical location with interconnecting pipelines where gas custody transfers 

take place, but where there is little trading activity. PREs may report prices at transit hubs. 

Price Reporting Entity (PRE) regularly surveys buyers and sellers within a region or at various gas hubs 

and reports prices, volumes, and number of trades, usually on a daily basis. The PRE typically does not 

reveal who the buyers and sellers are. The PRE has protocols for ensuring the reliability of the 

information it receives from market participants and may adjust reported prices for consistency. The 

PRE publishes prices regularly to paying subscribers or (for public agencies) by posting results on the 

internet. 

A price index is an average of the gas prices reported by a PRE or exchange for a specific location over a 

defined period of time (day, week, or month) and may be a simple average or a volume-weighted 

average of all reported trades. Typically an index is associated with a specific location, such as a market 

hub, but it also can be more broadly associated with a region, depending on how the index is 

constructed. For example, an index could represent the average of all gas traded across several hubs or 

locations that do not, in themselves, constitute market hubs. In this report, a price index at a gas market 

hub is a reliable indication of market conditions at the hub. Because of this, buyers and sellers are willing 

to set prices for future deliveries at whatever price the index indicates. Derivative contracts (futures, 

swaps, options) also refer to the index price for the underlying gas value.

A benchmark price index as reported by a PRE is used to price physical and financial trades 

within the geographic location and for the commodity specification for which the index is 

defined, as well as for other locations and commodity specifications. A price index can reach 

benchmark status when it is widely referred to as a true representation of the market. A 

benchmark index is associated with a gas market hub strategically located relative to consuming 

or production markets, where there is a high volume of physical trading. A benchmark index will 

be used in the pricing of derivative financial instruments, like futures contracts, options, and 

swaps. Prices for gas at other gas market hubs or locations are quoted in reference to the 
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benchmark index. Similarly, other financial derivative products will be based on the benchmark 

index.

 Synthetic price index is based on calculations intended to represent the actual sales prices 

when direct observations are infrequent and inadequate. A synthetic price index may be the 

result of adjusting observed prices and averaging these across a variety of locations and time 

frames. PREs develop and report synthetic indexes when there is no operating gas market hub 

to generate sufficient price information. The adjustments are intended to “correct” the reported 

prices for differences in transportation cost, volume, fuel specifications, etc. 

Price discovery in this report refers to the quality of the pricing information at a hub that reveals the 

value of gas in commerce at a specific time and place based on the supply and demand for gas. Price 

formation at a market hub arises through bilateral arms-length trades between parties or through 

market clearing mechanisms at exchanges. PREs and exchanges report volumes and prices traded. 

Indexes based on these reported prices are useful indicators of market conditions. Prices for contracted 

future deliveries provide information on market expectations.

Exchanges serve as market-clearing agents where offers of gas and bids for gas are posted under the 

rules of the exchange and trades are executed on the exchange without buyers and sellers knowing the 

identity of the counter parties. Exchanges enforce standard contract terms (quantity, delivery 

conditions, quality, etc.). Exchanges also offer derivative products based on the underlying gas trading; 

these products include futures contracts, swaps, and options that facilitate financial hedging of the 

underlying physical trades. 

Third-party access (TPA) is a characteristic of all liberalized gas markets where there is no discrimination 

in access to gas pipeline, storage, and related facilities. Owners of the facilities are required to grant 

access to their facilities and services to any third party (including competitors) on commercial terms 

similar to those of their existing customers. TPA is an essential feature of gas market hubs and the 

networks in which they operate. 

Over-the-Counter (OTC) or bilateral trading refers to arm’s-length agreements to buy and sell gas 

between two parties negotiating directly with one another or through a broker or agent. PREs canvas 

parties to bilateral trades to develop price series and price indexes. 

On-the-day Commodity Market or OCM is a United Kingdom gas exchange-based anonymous trading 

platform that provides a framework for same-day trading to minimize system imbalances caused by 

shippers’ injections/withdrawals that deviate from their nomination schedules. Ideally, transactions in 

these two markets between shippers lead to bids that reflect the true short-run marginal cost of gas in 

the system. 

Liquidity describes a market hub where significant volumes of gas are traded involving many 

independent participants, and many individual transactions, all of which indicates that the prices 

revealed at the hub are accurate indicators of the value of gas based on supply and demand. A liquid 

market is one where a seller or buyer can be reasonably assured that trades can be consummated 

quickly without greatly affecting the prices within the market. One indicator of a market’s liquidity will 
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U.S. Energy Information Administration | Perspectives on the Development of LNG Market Hubs in the Asia Pacific Region 57

be the spread between the bids and ask prices: a narrow spread indicates a more liquid market than 

one with wider spreads. 

Churn rate or churn ratio is an indicator of market liquidity and refers to the number of times a package 

of gas is traded before final physical delivery in the hub and includes both physical re-trades and 

financial derivative trades. More detail provided in Appendix C.

Free on board or FOB means that the buyer takes delivery of goods being shipped to it by seller once 

the goods leave the seller's shipping dock; buyer pays shipping and all other costs associated with 

transporting the cargo.

Delivered ex ship (DES) means that the buyer takes delivery at the destination port for the cargo, i.e.,

the buyers shipping dock. 

CIF (cost, insurance, and freight) is the same as DES when seller has arranged for the carriage of goods 

by sea to a port of destination and paid all associated transportation costs.
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Appendix C. Churn Rate Analysis

The terms “churn rate” or “churn ratio” refer to a measure of market liquidity calculated as the volume 

of trades (measured in units of a commodity rather than number of contracts) in a time period divided 

by the units of that commodity finally delivered or consumed in the market during that same time 

period. Depending on who is making the calculations and what data are available, trades going into the 

calculation may include monthly, daily, and intra-day spot; forward market; futures market; swaps; and 

option trades—wherein all products (that is, any contract type and any future delivery date) with 

publicly available volume statistics are typically counted. For example, the U.K. Office of Gas and 

Electricity Markets (OFGEM)113 calculates the churn ratio for the U.K. gas market as:

Intercontinental Exchange (ICE) traded futures + OTC contract trades + ICE Endex On-the-day commodity 

market day-ahead and within-day trades

natural gas consumption in the country

The average of 12 monthly churn ratios computed by OFGEM came to an annual average churn ratio of 

22 for the year 2015. This is roughly 58,245 Bcf of trades versus 2,648 Bcf of annual consumption in U.K. 

According to a source cited by OFGEM,

114 a churn ratio of 10 or more is indicative of a “mature market.” 

However, comparison of churn ratios among markets is made difficult by the fact that readily available 

trade data that goes into the calculations may not include all relevant trades (e.g., OFGEM excludes both 

spot trades not going through ICE Endex and non-brokered bilateral deals, both for which data are 

presumably not readily available). Comparisons of churn ratios among markets are also problematic 

because the geographic area used to aggregate market deliveries/consumption data may not exactly 

correspond to the trade data if such trade data excludes trades related to commodity imports into that 

geographic area or includes trades related to exports. Also it is possible that hedging for physical trades 

in geographic market X may take place in forward and futures markets in nearby geographic market Y

because there might be no liquid forward and future markets within X itself. 

In estimating the churn rate for the U.S. FERC Form 522, data were used to estimate the percentage of 

trades that are reported verses those that are not reported. The table below presents that analysis. 

 113 OFGEM, “Wholesale Power Market Liquidity: Annual Report 2016,” (accessed September 3, 2016), 

https://www.ofgem.gov.uk/publications-and-updates/wholesale-power-market-liquidity-annual-report-2016.

114 OFGEM, “Continental European Gas Hubs: Are they fit for purpose?” (accessed September 3, 2016), 

https://www.oxfordenergy.org/wpcms/wp-content/uploads/2012/06/NG-63.pdf.
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Table C-1. Physical gas trades reported for 2015 to FERC and PREs

Contract Type Quadrillion Btu 

per Year Bcf/d Percent 

Fixed Price, Next Day [r] 1.86 4.9 3.00%

Fixed Price, Monthly [r] 7.37 19.6 11.90%

Indexed, Next Day 20.06 53.4 32.40%

Indexed, Monthly 28.3 75.3 45.70%

Physical Basis [r] 3.71 9.9 6.00%

Price Trigger 0.62 1.6 1.00%

Sum of Physical Trades 61.92 164.7 100%

"Reportable" to PREs -- [r] above 12.94 34.4 20.90%

Reported to PREs 6.38 17 10.30%

Fraction of "reportable" actually reported to PREs 49.3%

Source: FERC Form 552: Annual Report of Natural Gas Transactions, 2015.
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Appendix D. Gas Price Formation in Japan and China 

D.1 Japan Customs-Cleared Crude (JCC) formula

PLNG = a * JCC + B

PLNG is the CIF price in Japan

a is the slope of the curve or discount rate 

JCC is the basket of crude prices published by the government

B is a constant value 

In this formula, the “slope” typically has been less than the 0.172 to 0.167 (the crude equivalent price 

for 5.8 MMBtu per barrel or 6 MMBtu per barrel, respectively) under long-term contracts. The slopes 

have occasionally been higher for short periods when new contracts were negotiated in years when 

limited new LNG supply exceeded new contract demand. Also, there have been modifications to the 

slope to create a floor and a ceiling price for LNG to protect the parties from market disruptions. 

D.2 China Pricing Formula

The National Development and Reform Commission (NDRC) regulates prices at each step along the value 

chain to recover the costs of production through distribution. China has begun implementing a pricing 

reform that ties the price of incremental supplies of gas to the prices of alternative fuels—fuel oil and 

liquefied petroleum gas (LPG). The pricing formula below solves for the price of gas in Shanghai—all 

other prices are calculated off of this price.115 

PCGPIN is the city gate price for the incremental natural gas in Shanghai 

K is a constant NDRC uses to discount the final price (85% at present) 

α and β are the energy share weights for fuel oil and LPG respectively within China’s energy supply 

PFO and PLPG are the average prices for imported fuel oil and LPG 

HNG, HFO, and HLPG are the heating value of natural gas, fuel oil and LPG 

R is the value-added tax (VAT) rate for natural gas116

 115 Sergey Paltsev and Danwei Zhang, Natural Gas Pricing Reform in China: Getting Closer to a Market System? MIT Joint 

Program on the Science and Policy of Global Climate Change, July 2015, pp. 9-10. This paper offers an in-depth description and 

evaluation of the effects of the policy. 

116 Ibid, p. 10.