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Research Article
Development of Europe's gas hubs: Implications for East Asia
Shi Xunpeng
Energy Studies Institute, National University of Singapore, 29 Heng Mui Keng Terrace, Block A, Singapore 119620, Singapore
Received 25 May 2016; accepted 25 November 2016
Available online 24 February 2017
Abstract
Gas trading hubs have been initially developed in the US in 1980s, UK in 1990s, more recently in European in the 2000s and mulled in
East Asia now. Due to its freshness and diversification in nationality, governance and culture, the European hub experience can offer valuable
lessons for East Asia. This paper seeks to advance understanding of gas hub development in Europe and provide lessons for East Asia. The
European experience highlights that market liberalization and transition of gas pricing mechanism are necessary in creating the competitive
markets that are needed for functional gas hubs. Political will and regulations further safeguard the competition environment needed for hub
development. Natural factors, such as significant domestic production and culture could have a significant impact on the hub development and
transition of pricing mechanism. In East Asia, the path to gas trading hubs might be more difficult than in Europe but a growing market
creates an opportunity to start new terms with new contracts. Nevertheless, East Asian needs to work hard to development its indigenous gas
or LNG trading hubs.
©2016 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND
license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
JEL: Q41; Q48; L1
Keywords: Natural gas; Hub; Europe; East Asia; China; Japan
1. Introduction
With the development of independent natural gas markets,
the oil indexed pricing mechanisms for natural gas are
increasingly challenged [1,2].Asalternatives,thegas-on-gas
competitive pricing mechanisms through gas trading hubs
have become increasingly popular in Europe, although they
took a few decade time to reach their current status [2].The
gas trading hub model was first developed in the United
States (US) in 1980s ewith its Henry Hub (HH) as the
leading example eand the United Kingdom (UK) being the
first in the Europe in 1990s and then by Continental Europe
in 2000s.
Despite differences in their performance and national
contexts, European hub development experiences provide
important lessons for building gas hubs in East Asia. In the
past few years when the oil was about $80 per barrel and when
the gap between Asia's oil indexed LNG prices and US and
European hub prices are beyond cost of arbitrage, Asian
buyers have looked to move away from oil indexed to
hubeindexed LNG imports [3]. It is also believed that the
creation of a gas hub would consolidate regional demand and
thus increase the ability of East Asia to bargain from a position
of strength for lower gas prices [4].
Even though hub-indexed prices in Europe and North
America have been indirectly used by Asia gas buyers
1
[5],
there are concerns that Henry Hub prices may not reflect the
market fundamentals in East Asia as perfect arbitrage is not
possible, and the unique characteristics of regional supply and
demand ‘de-couple’regional commodity market prices from
global prices [6]. Factors such as geographical risks and
E-mail addresses: xunpeng.shi@gmail.com,shi@nus.edu.sg.
Peer review under responsibility of Sichuan Petroleum Administration.
1
LNG buyers have used contracts indexed to the Gulf Coast's Henry Hub
natural gas price benchmark to hedge their price exposure in Asia, and buyers
are demanding new terms for renewal of contracts.
Available online at www.sciencedirect.com
ScienceDirect
Natural Gas Industry B 3 (2016) 357e366
www.elsevier.com/locate/ngib
http://dx.doi.org/10.1016/j.ngib.2016.11.001
2352-8540/©2016 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license
(http://creativecommons.org/licenses/by-nc-nd/4.0/).
foreign exchange risks as a result of using pricing benchmarks
from outside the region will encourage the development of
East Asian benchmark prices.
This paper investigates the European experience and
draws lessons for East Asia in developing its domestic
competitive gas markets and gas hubs. Questions to be
answered are: What learning points from the European
experience can be applied towards creating a gas hub in East
Asia? What role did governments play in the development of
the competitive markets and hubs? Were there common
regulatory mechanisms and key infrastructure put in place to
facilitate the development of the markets and hubs? What the
likely scenario for hub development in East Asia based on the
EU experience?
This major contribution of this paper is to offer a
comprehensive analytical framework that enables hub devel-
opment and draw implication for East Asia. Most studies on
gas hubs in Europe focus on pricing and price correlation
[7e9]. The previous studies on gas hubs in Europe examine
either specific country case studies [4,10], or technical details,
such as balancing issues [11,12], flexibility and tariff issues
[13], pricing discovery [14], or determinants of gas prices and
the role of market integration [15]. There are also a few studies
on the pricing patterns in a competitive market [16,17], on the
impact of different pricing mechanisms [3], and other studies
that deal with the impact of European integration on gas
markets [8,9,18,19]. The issues of spot markets and trading
hubs have been intensively discussed in the Chinese literature
[4,10,20e23]. The consensus is that China needs to build a
spot gas market that can offer benchmark prices for China and
even Asia and the Pacific. While the European experience in
hub development may be mentioned in some studies, none of
them have dedicated to study the European case in details.
None of these studies have summarized the European hub
experience from an East Asian perspective.
The paper proceeds as follow: Section 2introduces the
methodology used in this study. Section 3presents a brief
overview of the development of gas hubs in Europe. Section 4
summarizes key lessons learned from the European case study.
Section 5discusses the implications of hub development in
East Asia through a comparative study. The last section con-
cludes the paper.
2. Methodology
This research was conducted through desk study, fieldwork
to Europe and interviews conducted in China, Japan and
Singapore. The experience and arguments in the literature
were reviewed and analysed, and comparative studies between
the Europe and East Asia were conducted. The European
views and debates were collected through field interviews
conducted in the UK, France, Germany and the Netherlands
during 24 June to 3 July 2015. The institutions interviewed
include gas/LNG traders, Exchanges, hub operators, infor-
mation providers, academic researchers, IEA, and industrial
players. Further discussion and debates was conducted during
a workshop held on 28e30 August 2015 in Singapore.
3. Overview of gas hub development in Europe
Gas hubs in Europe originated in the UK in 1996 and
proliferated throughout Continental Europe beginning in the
2000s, but the level of development has been uneven. The
National Balancing Point (NBP) is Europe's first gas trading
hub, having been established in the UK in 1996. Following the
lead of the UK, gas trading hubs mushroomed across the EU
throughout the 2000s. The first continental gas trading hub is
the Belgium Zeebrugge (ZEE), which emerged after the con-
struction and start of the Interconnector pipeline in October
1998 linking it to the UK NBP market.
Europe is more interested in building a virtual trading hub
(rather than a physical one) as it has more flexible trade ar-
rangements and is more open to participants, in particular,
financial players [2]. Most European hubs are virtual hubs,
with the exception of Zeebrugge in Belgium. Zeebrugge is a
physical hub, where the Interconnector meets the Belgian
distribution system [1]. The physical hub requests traders to
bring their gas there and thus discourages the interests of
many traders.
The level of development is quite different among the
active hubs in Europe. Northwest Europe has the most
advanced hubs, followed by Central Europe, while gas hubs
are still at their early stage in Southern Europe. According to a
European Commission Report, as of 2013, the share of gas hub
trading varied significantly among these regions. In Northwest
Europe, it accounted for 80% of all natural gas consumed. In
Central Europe, the number was lower and stood at around
50%. Southern Europe, however, had only about 15% of its
gas consumption based on gas-to-gas competition. Southeast
Europe is 100% dependent on oil-indexed contracts [24].
While some European gas hubs represent cases of suc-
cessful experience, others have failed to be mature and even
ceased to exist. The UK's NBP, the Netherlands'Title
Transfer Facilities (TTF), and Germany's Net Connect Ger-
many (NCG) are the examples of successful hubs. Based on
the assessed performance of European gas hubs in 2014 and
2015 (Fig. 1), the two most developed European hubs are the
British NBP and the Dutch TTF. The assessment also give
high scores to the two German hubs and the two Belgian hubs
(Zeebrugge and virtual hub ZTP) in the latest assessment.
The two Belgian hubs recorded significant improvement.
German Gaspool and the Net Connect Germany (NCG) are
the latecomers to hub-based trading, but are already known
for their quick growth rates of trading volumes (liquidity).
While the other hubs are less active. The PEGs, CEGH, PSV
and GTF also relatively good.
Assessed by churn rate,
2
a popular indicator of hub per-
formance, the difference among hubs is more significant.
According to Heather [25], in 2014, both NBP and TTF has a
churn rate of more than 20, well above the minimum of 15
which is reportedly required by Gazprom as the requirement
2
“Churn rate”refers to the ratio between traded volume and physical gas
throughout and is a widely used indicator for spot market liquidity.
358 Shi X.P. / Natural Gas Industry B 3 (2016) 357e366
for a creditable (liquid) hub. In contrast, the German,
Australian and Belgian hubs had a churn rate of 3e5 while the
rest hubs only had a churn rate of less than 2. The French and
Italian hubs have performed poorly (Fig. 2). In the European
continental gas markets, TTF is the only pricing benchmark,
while other hubs are priced as spreads with TTF prices.
Although ZEE has good performance, it does not offer a
benchmark because its prices are dependent on those of NBP.
Although many hubs are more or less successful, only two
of them, NBP and TTF, are benchmark hubs. Although the
Netherlands'TTF is developed after NBP, it became the
benchmark to which prices in European end-consumer con-
tracts are pegged. TTF has developed quickly and steadily in
the past few years, and is considered a success story. NBP had
a good start and was successful but was overtaken by TTF by
annual traded volume in 2014 [26]. In July 2015, TTF over-
took NBP as the most liquid gas hub in Europe based on
monthly trades [27].
TTF's ascent to the top of gas trading hubs has brought by
some chances. When Germany renegotiated its long term
contracts with Gazprom in 2009, Gazprom did not agree with
Germany's hub prices because Gazprom argued that Germany's
hub prices could be manipulated by the German utilities,
which are the major owners of German gas hubs. For the same
consideration, the German hubs were not accepted even by the
domestic counterparts. According to interviews with an expert,
NBP prices, as the most liquid market at that time, were also
not accepted by Gazprom and the German parties because
0
2
4
6
8
10
12
14
16
18
20
NBP (UK)
TTF (NH)
ZEE (BE)
ZTP (BE)
NCG (DE)
Gaspool (DE)
PEGs (FR)
CEGH (AT)
PSV (IT)
AOC (ES)
Mibgas (ES)
Czech Republic
Slovakia
Greece
Turkey
GTF (DK)
HVP (HU)
Poland
Romania
Bulgaria
2014 2015
Fig. 1. Scores of individual European hub assessments. Source: EFET, 2015. Review of gas hub assessments, published on 7 January 2015.
0
5
10
15
20
25
30
35
40 2004 2008 2011 2013 2014
Fig. 2. Net churn rate of European hubs, 2004e2014. Note: The net churn considers trade volume only and exclude swaps volume. Source: [25].
359Shi X.P. / Natural Gas Industry B 3 (2016) 357e366
NBP is priced in Pence and thus creates exchange risks for
continental companies. Instead, TTF prices are acceptable to
both Russia-German parties as reference prices for the Russia-
German contracts despite of its considerably low churn rate of
3.3 at that time [25] because TTF was the most developed
trading hub in Continental Europe after ZEE
3
and TTF is
priced in Euro. Furthermore, TTF prices are neutral to both
parties: German companies were not significant in TTF, and
thus could not manipulate the TTF prices. After the TTF is
used in the long term contact, companies started to hedge in
TTF which further boosted its liquidity. Nowadays, since TTF
has been developed, other European hub owners have no in-
terest to make their hubs better because they think market
liquidity is not enough.
Despite the successful development of various hubs, there
is no cross-country regional hub yet. As of 2012, none of these
European hubs are transnational, all are national (the United
Kingdom, the Netherlands, or Italy), or sub-national (France,
Germany) and there were over 30 entry-exit zones in the EU
[18]. Although the boundaries of the market areas do not
necessarily coincide with the boundaries of a member-state,
one member country often has one market area and one
operator is appointed as the area's Transmission System
Operator (TSO). However, with the development of infra-
structure and the rolling out of market liberalization, gas pri-
ces in different European wholesale markets are converging.
Different performance in Europe's hubs reflects challenges
of uniform application of the EU-wide framework of liber-
alization and provide lessons for developing existing and
future gas hubs in Europe and future hubs in East Asia.
4. Key factors for successful hub development
The experience of numerous European gas hubs demon-
strates that there are a few essential factors for gas hub
development. Unbundling of vertically integration gas com-
panies creates the necessary market players. Market liber-
alization and pricing transition create the need of trade and the
liquidity. Hub and transition of gas pricing formation are
interconnected. On the one hand, a key outcome of the pricing
transition is the emergence of gas trading hubs, which produce
the benchmark prices as alternatives to oil indexed prices. On
the other hand, hub creation is a key enabling factor for the
pricing transition as hubs can facilitate trade, and enable
competitive markets to function [2].
In addition, the liberalization and pricing transition requires
political determination, and changes of cultures, regulations
and governance practices. Strong political will is needed to
fight with the power of those incumbents that will suffer from
the market liberalization and pricing transition. Legislative
changes are often required to force incumbents to release
infrastructure capacity and gas market shares. While gover-
nance is needed, domestic production will facilitate pricing
transition and trading tradition is beneficial in accepting gas
hub pricing model.
4.1. Market liberalization and competition
The comprehensive process of gas market liberalization is a
precondition for hub development. These could be demon-
strated by three reasons. First, market liberalization is neces-
sary to create the competitive environment. The lack of market
competition is a major barrier for hub development. In Italy
and France, the hubs were not developed well due to a lack of
government will to liberalize their gas markets. A liquid hub
was delayed in Italy due to the failure of creating a competi-
tion in middle and downstream sectors to the extent seen in the
Northwest European liberalised market in the 2000s [28].It
was argued that there was no real desire for an effective
commercial and liquid PSV gas hub in Italy until very recently
[25]. For example, despite the Italian government is enforcing
antitrust ceiling and gas releases, ENI is still the dominant
player who owns storage, a majority of production and import
infrastructure [28], and did not trade at the PSV at all until
recently [25]. Similarly, while the Belgian gas market was
developing in line with the EU liberalization directives, the
lack of competition at early stages of ZEE's development
resulted in delayed implementation of reforms.
Second, market liberalization is a necessary measure to
create the demand for wholesale trade, which in turns is the
key incentive and fundamental role of a hub [12].Ina
monopolistic industry, the integrated company can manage
most of the injections and withdrawals, and balance the ex-
post shocks in supply or demand, through adjustments
within its portfolio of contracts, and thus has no demand for
trade. In contrast, deregulation in the gas sector creates frag-
mentation and thus demand for trade. Liberalization of final
gas pricing prevents costs to be passed on to consumers, thus
creates the need of trade and competition. Unbundling en-
courages market participants to utilize hubs in order to balance
their contracts, manage their portfolio risks and even specu-
late, and thus increase liquidity of the markets. The estab-
lishment of NBP followed national gas market liberalization
with the privatization of the British Gas Corporation (1986)
and implementation of the Gas Act (1995), which effectively
introduced competition. Liberalization of gas markets in the
EU achieved a milestone that supplier dominated gas markets
have been rebalanced to better meet consumers'needs. This is
a relatively recent achievement because as recent as
2005e2006 observers criticized market arrangements where
pipeline owners and traders used to be the same companies
capable of manipulating the market [29]. These worries were
addressed by the 3rd Energy Package.
Additionally, liberalization of national electricity markets
also plays a major role in gas hub development, as utilities are
major gas consumers who are less likely to participate in
wholesale gas trading if they can pass costs to consumers.
The importance of liberalization on hub development is
testified by the experience of TTF. Unlike NBP, TTF and its
development did not take off until 2009, when a number of
3
ZEE is priced in pence and thus has the same currency conversion risk as
the NBP.
360 Shi X.P. / Natural Gas Industry B 3 (2016) 357e366
necessary market changes were implemented. First, in July
2009, the TSO standardized traded natural gas effectively
erased the difference between high and low calorific gases.
Second, in April 2011, the TSO implemented “Market Based
Balancing,”a real time balancing regime [30,31]. Third,
suppliers of the Dutch gas market including GasTerra, Exxon
and Shell, have actively supported hub-based trading. As a
result of these comprehensive liberalization measures, TTF
trade volumes skyrocketed from 2009 to 2011, rising at about
62% annually. By 2012, TTF could be referred to as a mature
market [31].
The process of liberalization involves organizational
restructuring of concerned industries, and implementation of a
regulatory reform program. Miriello and Polo [12] proposed
an evolutionary path for the wholesale natural gas market:
development of wholesale trade for balancing need in a frag-
mented market, a second source of gas supply as an alternative
to long term gas in the liquid market, and traded financial
instruments to manage risks. The key factors of success are
liberalized wholesale markets and final prices, the unbundling
of vertically integrated gas companies, open and transparent
third party access (TPA), through the introduction of a com-
mon network code, proper competition legislation, and hands-
off government policy [2]. The workable third part access and
transparent hub prices make consumers, in particular, large
consumers, access to various suppliers and thus the competi-
tion for large consumers become fierce [32].
4.2. Pricing transition for long term contracts sustains
competition and generates liquidity
The transition to hub pricing is another important factor to
create demand for hub trading and increase liquidity of gas
hubs. After liberalization, the local hub prices may be
significantly lower than the oil indexed import prices at least at
some times.
4
For example, a combination of unexpected
availability of new LNG on the markets and reduced demand
due to global financial crisis created the significant price
discrepancy between the oil indexed long term contract prices
and the spot prices [1] and motivated the European gas pricing
transition. With this price difference, and the freedom to
choose their suppliers by consumers in a liberalized market,
the traditional utilities that signed oil-linked long terms con-
tract were often bypassed and consequently suffered financial
loss as well as failure to meet the minimum take-or-pay levels.
The price gap and retailing market liberalization lead to un-
sustainable financial exposure of the midstream utilities which
have to seek arbitration and negotiated price reductions in
their long-term gas contracts [33].
Supply surplus is a key market condition that enables the
pricing transition. On the one hand, the surplus will create a
lower spot prices than oil indexed prices. The price difference
and liberalization caused financial loss to incumbents, who
could not survive and have to resort to renegotiation of their
long term contracts. In North America, the Henry Hub gas
trading hub was adopted in the late 1980s when interstate gas
trades became less difficult than before, supply became
abundant and production became competitive [34]. The
development of continental European hubs only effectively
started from 2009, when a surplus of LNG supply catalysed
hub liquidity and development [25]. In the few years after
2009, the European market was over supplied by the unex-
pected availability of new LNG due to the US shale gas boom,
soaring oil prices, depressed demand due to the global finan-
cial crisis, and the commissioning of new LNG liquefaction
terminals in Qatar, Yemen, Russia and Indonesia [32].
On the other hand, the surplus shifts the bargaining power
to buyers and make the transition possible. The pricing tran-
sition was made possible by the shift to a consumer-dominated
market and reconfiguration of market players which gradually
led to the formation of a ‘hybrid price’market since the mid-
2000s. Since most of the failure of take-or-pay happened with
Gazprom, the European utilities have renegotiated their con-
tracts with Gazprom by reducing prices and level of take-or-
pay by 2012 [32]. Gazprom is a strong support of oil index-
ation and did not accept hub prices initially, but instead gave
discounts to bring the oil indexation prices close to hub prices
[25]. However, in September 2015, Gazprom Export con-
ducted gas auctions for the first time, symbolizing its accep-
tance of a partial move away from the traditional long-term oil
indexed contracts towards a market (hub) pricing mechanisms
given the current over supplied market situation [35].
The transition to spot marking is not an easy job in the
business sector. The breakdown of long term oil indexed
contracts is a dramatic change to the mode of commercial
practice and creates winners and losers. The transition of gas
pricing formation in Europe was achieved by the re-negotiation
of some long-term oil indexed contracts by introducing spot
indexation and more flexibility on the take-or-pay quantities
that occurred from 2010 onwards [1] and increased use of
shorter-term contracts (IGU, 2011). Some of the changes of
long term contracts are completed through arbitration, which is
not desirable for business partnership. Due to the fact of sig-
nificant financial loss from the importer side, arbitration was
often successful. Since the financial loss in European gas
companies is too heavy to be sustained, arbitration was the
only chance for the European utilities to survive.
4.3. Political will and regulations
The liberalization and pricing transition has been very
costly for many participants, in particular, the incumbents.
Market liberalization means that the incumbent monopolistic
companies had to give up their vertical integration, market
power and market share. The dominant integrated gas com-
panies such as in UK (British Gas) and the Netherlands
(GasTerra), were unbundled and forced to relinquish their
market share to make room for new players. The liberalization
of the retail gas sector caused a progressive loss of monopoly
4
Such low spot prices, however, will not be always the case because spot
prices could be higher than oil indexed prices. The function of the market is
supposed to form prices, while not reduce them.
361Shi X.P. / Natural Gas Industry B 3 (2016) 357e366
for the traditional utilities. These incumbents are often
nationalised companies (or only recently privatised) with
strong ties to governments, and thus have the incentives and
capability to lobby for delays in the process of market liber-
alization demanded by European law.
Strong political will is needed to fight with the power of
those incumbents that will suffer from the liberalization. UK
was able to succeed in liberalization due to the aggressive
nature of the government. The process of change was led by
the strong political will to ‘privatise’the nationalised British
Gas by the government [12]. The change was also boosted by a
strong alignment of interest from all the key market players
[31]. On the contrary, a poor political and regulatory frame-
work to encourage trading contributed to the failure of Italian
PSV [25]. Similarly, TTF was only kick-started after the
implementation of the ‘Gas Roundabout’in the mid-2000s
[36]. The gas market liberalization in Continental Europe
was driven by the EU's political ambitions to create both a fair
market for all consumers and an integrated energy market [2].
Government regulations is a necessary instrument to safe-
guard the hub development. In Europe, the illegalized “Desti-
nation Clause”which limits the essential flexibility that a
functioning gas market needs provides the legal foundation for
importers to request destination free. The opening-up of Ger-
many's end-user market through legal decisions kicked off the
change in attitude towards traded gas markets. Firstly, in June
2006, long term contracts between E.ON and its distributors
were declared to be illegal, and limitations on the duration of
any future supply contracts were imposed. Subsequently, in
March 2010, the prices for natural gas for private clients were
no longer allowed to be immediately linked to the prices for
heating oil with the declaration from the German Federal Court
of Justice [25]. In contrast, Italy and France lagged behind in
hub creation and hub pricing development due to their regu-
lations that place restrictions on both cross-border trade and
their strong incumbents [28]. In Austria, only after the
implementation of a new Austrian Gas Act in October 2011
and the start of the new VTP hub in January 2013, there have
been noticeable improvements in the liquidity of that hub [25].
It has been argued that in the European gas market liber-
alization experience indicates that the successful development
of a liquid wholesale gas market required the following ef-
forts: clear rules and mechanism that address the choice of a
transmission system model, the design of the balancing rules,
and presence of transparency requirements [12].
4.4. Natural factors: domestic production and culture
Some natural factors can affect the gas hub development
and the much needed market liberalization and pricing tran-
sition. First, multiple sources of supply can facilitate the
transition to hub indexation. Additional factors such as supply
by several pipelines plus possible LNG, large demand by
several buyers, and storage of gas are considered valuable to
the pricing transition [37]. For example, when there is an
alternative in Western Europe, Russia reduces its gas prices in
the western European markets, but maintains the oil indexation
in the Eastern Europe. The British transition also has the
advantage of multiple suppliers. Diversified supply sources,
improving interconnections between and within markets and
the European Commission's favouring gas-to-gas competition
as an alternative to oil indexation, are also key factors promote
the transition (IGU, 2011).
The availability of domestic production facilitated the Eu-
ropean market transition. It would be easier for regulation to
force domestic producers to change their behaviour (move to
hub trading), and thus create spot trading, through hubs. This
is particularly true in the UK and the Netherlands, where the
governments initially unbundled the vertical gas companies,
and created domestic competition without incurring dispute
with foreign companies. Such a trading hub revealed prices
that can be used as a benchmark to force foreign suppliers to
change their behaviour at a later stage. In the Netherlands, the
transition to hub pricing was boosted by full commitments
from the domestic incumbent producer, GasTerra (after some
political pressure to ‘use the hub’), from the TSO and from the
market participants [25].
Cultural factors could influence the gas market changes.
Countries such as Great Britain, the Netherlands and the
Nordic countries are benefiting from their long tradition of
trading, hence both gas market liberalization and hub devel-
opment progressed well in those countries. The Dutch and
Norwegian suppliers were quickly open to the hub pricing
model, and offer alternative contracts with indexation to hub
prices [25]. In contrast, France, Italy and other southern Eu-
ropean countries have traditionally been more defensive of
their trading environments, selecting ‘national champions’
rather than allowing markets to decide. For example, the
prevailing attitude in both France and Italy is much in favour
of strong national ‘flag bearing’companies, and thus liber-
alization of the gas sector is slow. The lack of pricing liber-
alization is the reason behind the slow development of hubs in
those countries. In between the two ends of the spectrum are
the Germanic countries, which have developed their own
trading systems and are resistant to changes that would argu-
ably improve performance, due to confidence of their own
system [25]. Traditional utilities are also adverse to change,
preferring to keep their franchise and control of consumers [2].
As part of the broader cultural factors, government
administration tradition also matters. Liberalization and tran-
sition to competitive markets also challenges the ways of
governance. Countries that value energy security more than
market efficiency will find it difficult to adjust to the new
model. The role of government in the economy has to be
changed from the command and control model to an indirect
market based model. Such transitions are complicated and
often a challenge for governance capability.
However, cultural change is possible. The dominant culture
of oil linked long-term contracts was fractured by the restruc-
turing gas companies under the utilities umbrella. Even the
employees in the old gas sector will be impacted by the transition
of pricing mechanisms. The European experience has shown
that the market players in the previous oil indexed world have
gone, and the old paradigm has disappeared with the change of
362 Shi X.P. / Natural Gas Industry B 3 (2016) 357e366
executives in the gas trading industry. The latter do not share gas
companies'ties and ways of doing business with non-European
suppliers [7]. They do not hesitate to question the value of oil-
linked prices and long-term contracts [7]. As a result, the
terms of some contracts have been renegotiated and now include,
or solely consist, of spot price indexation. New contracts also
reduced take-or-pay levels [24]. With such changesin Northwest
Europe, others will more or less be affected.
5. Implications for East Asia
5.1. A comparative study between Europe and East Asia
The significant difference between East Asia and Europe
should be examined before taking any lessons from the Eu-
ropean experiences considering the potential impact of natural
factors.
First, East Asian gas markets are fragmented and lack local
(domestic) supply in most countries. In contrast, the European
gas markets are interconnected. Most East Asian countries,
such as Japan, Korea and Singapore, have no domestic pro-
duction, which makes their unbundling easier but the creation
of competition more difficult than in the UK and the
Netherlands. Such natural conduction lead to over-reliance on
LNG, insufficient gas market liquidity and a lack of gas-on-
gas competition and the dominance of LNG makes liquidity
harder to be created in East Asia than in Europe.
Second, the long term oil indexed contract arrangement
causes the gas prices to not reflect the region's own market
fundamentals. While gas prices in the US and some European
markets are set by hubs based on gas-on-gas competition,
pipeline gas and most LNG into East Asia are traded under oil-
indexed contracts. The share of oil indexed gas (both LNG and
pipeline) in East Asia was 88%, much higher than the global
average of 65% [38]. The prevailing destination clauses in
long term contracts further limits the development of liquidity
in the East Asian market [3].
Third, a lack of gas market liberalization in East Asia limits
the prosperity of hub development. In contrast to relatively
liberalized European markets, in particular those in Northwest
Europe, all East Asian gas markets share similar characteris-
tics, including a lack of wholesale competition, monopoly, and
a limited number of market players. The Chinese gas markets
are dominated by three major national oil companies (CNPC,
Sinopec and CNOOC) and 70% of pipelines are owned by
CNPC [36]. Japanese and Korean companies often purchase
their LNG under long-term, mostly oil-indexed, contracts, and
thus require limited competition in the downstream sector to
secure the distribution to end users [1]. While in Korea,
KOGAS is the only importer with access to the domestic gas
market [39]. None of these major markets have well-
functioning energy trading platforms and derivatives mar-
kets. Without a competitive spot market for natural gas, there
is little incentive to change current commercial practices in
East Asia, especially from the suppliers'side. Thus, the
adjustment to a competitive gas markets would be very diffi-
cult and impossible without government's determination.
Fourth, the interdependence power liberalization and gas
markets is another challenge for East Asia. The liberalization
of the electricity sector, as the major gas user, will create
competition in the electricity markets and thus force genera-
tors to change their business model from fully passing through
the price risks in the gas markets to consumers to managing
their fuel risks and thus creating demand for risks mitigation
trade. The absence of power market liberalization can affect
the evolution of gas consumption since power sector is one of
the key drivers for gas demand. In the EU, the liberalization of
power markets has usually been a step ahead of gas markets
[1]. While in East Asia, power markets are largely regulated in
the majority of countries, except Singapore. Even though the
electricity market is liberalized in Japan, the Japanese utility
companies have regional monopolies and rely on fixed and
long term trading for security concerns [2].
Lastly, the different mind-set between Asia and Northwest
Europe could discourage the process of market liberalization.
East Asian countries often put security of supply at the top of
their policy agenda, and thus prefer state interventions through
big companies. The traditional energy security culture that is
willing to pay a higher price for stable supply will be chal-
lenged by the unbundling of incumbents, as the higher prices
cannot be passed through to final consumers in an unbundled
sector. This concern is particular serious in Japan and Korea
where the import dependence is high. Similar to the lack of
enthusiasm in Southeast Europe [25], whether East Asian
policymakers really want to have an open gas market is still
not clear. Similar to both France and Italy, at least in China,
the prevailing feeling is much in favour of strong national
energy companies [25], and thus liberalization of the gas
sector may not be as full as those in Northwest Europe.
East Asia also cannot replicate the European transition
because of some other unique factors, such as the vertically
integrated industry structure, which prevents the justification
of contract renegotiation based on financial loss, since the loss
incurred in downstream can be compensated by upstream, or
the higher costs will be passed on to consumers.
However, the future growth in East Asia allows new model
for newly added volume. The East Asian market is growing
quickly, particularly in China, while the European market only
develops slowly. The Asian natural gas market is the fastest
growing gas market worldwide and the trend of growth is
expected to continue. The IEA [2] predicts that Asia may
absorb 80% of the incremental LNG imports over the medium
term, among which China alone will absorb 30%.
5.2. Market liberalization
If some East Asian countries want to create a liquid gas
hub, it will have to go through tough and challenging market
liberalization process in the electricity and gas sector. The East
Asian gas and electricity sector needs to go through a tough
liberalization process. The European experience shows that the
creation of hub indexation poses significant challenges to in-
cumbents, who might be against the liberalization. Given the
nascent status of market liberalization in both gas and
363Shi X.P. / Natural Gas Industry B 3 (2016) 357e366
electricity sectors, the East Asian governments need to take
measures to promote market liberalization if they want to
realize a local gas hub.
Liberalization in the gas and electricity sectors needs to be
deepened in China and Japan, and extended to other countries.
China has started to liberalize its gas market, including pro-
moting TPA [40]. Japan has announced in February 2015 that
its gas and electricity sectors will be liberalized from 2017
[41]. The further liberalization of Japan's gas and electricity
markets in the next decades may make Japan better prepared
for a gas hub. But South Korea and Chinese Taipei have given
no indication of whether they intend to pursue liberalization
yet. The liberalization process, however, does not need to be
developed simultaneously across East Asian importers.
Political will and strong leadership are needed to contest
with the power of incumbents and restructure the gas market.
Existing market participants do not like liberalization. As
shown in the British case, the privatisation of nationalised
industries, and their effective implementation have led to a
liberalized gas market.
An alternative way to create an East Asian benchmark
prices without demand of market liberalization is to create a
regional LNG hub [42]. Such a regional hub could be building
on trading and liquidity out of any national boundary through
LNG spot markets. Eliminating destination restrictions in
current LNG contracts could be a way to enhance trade flex-
ibility and create an East Asian spot LNG market. However,
such efforts of creating a LNG hub is unprecedented and
whether it can succeed remains to be seen.
5.3. Pricing transition
East Asia cannot replicate the European experience of
creating flexible gas markets by breaking rigid long-term
contracts through renegotiation and arbitration. Unlike in the
European transition, arbitration is not likely an option for East
Asian market players to initiate the transition for a number of
reasons. First, there is no critical situation, such as heavy
financial loss. In particular, due to the current low oil prices,
the need for change in pricing mechanisms is largely muted.
Second, to have arbitration, there must be a hub trading to
provide market reference, and the gap between the hub prices
and the oil indexed prices are not reasonable. Since arbitration
is not an option, the only way to change the practice of oil
indexation is through negotiations, which must be agreed by
both producers and consumers.
In order to balance benefits between importers and ex-
porters and to find workable solutions for sustainable LNG
market development, both exporters and importers must
cooperate. Collaboration between consumers and producers
are needed in order to change international trade practices for
creating the demand for flexible LNG, and even pipeline gas
trade. However, as spot prices have been lower than contract
prices in recent years, discussions on the pricing mechanism
have been incorrectly conflated with the ones on the associa-
tion between gas trading hubs and low prices [14,43]. Dia-
logue forums for both producers and consumers should be
maintained and strengthened to discuss such contract flexi-
bility issues. While the price gap is a key driver for pricing
transition, the low gas price period is an window for initiating
the pricing transition because the difference between alterna-
tive pricing mechanism are minimal [44].
5.4. Regulation and roles of government
The East Asian governments will have to enhance its
governance capability in creating competitive markets, moni-
toring its operation, and regulating financial markets. Govern-
ments must maintain and supervise competitive market
conditions instead of focusing on price regulation along the
value chain. The governments'role is to put together the
framework for the ease of trading, regulatory environment,
infrastructure and transparency [45].
Governments also need to create the liquidity through
mandating the sale of gas to the hub. In Italy, the government,
through the Decree Law 7 (2007), mandates importers and do-
mestic producers to sell certain amount of gas at the PSV [28].
East Asian government should promote cooperation among
themselves and between producers and consumers. Importers
can come together to share their experience in creating mean-
ingful gas trading hubs [46]. Regional gas market integration
would also be useful to increase the total liquidity in the LNG
and gas markets. Pipeline interconnection, either through the
existing pipelines in Southeast Asia, or through pipelines in
Northeast Asia, could overcome the fragmentation and form
regional gas trading hubs. For example, integrating the
Singapore, Malaysia and Indonesia markets could form a gas
trading area with diversified supply sources and increase
liquidity of gas hubs in these three countries, if any.
Regulation of financial market players is important for the
sustainable development of gas markets. The financial market
players could be powerful because they hire the best minds
and distort the gas markets. In the case of crude oil prices,
even major OPEC members are complaining because they
have difficulty in understanding oil pricing formation. If the
government is not well prepared for the coming regulations, it
is better to have a mixture of government (socialism) and the
market (capitalism).
Although the roles of governments have been emphasized,
it however does not mean that government is the creator.
Trading hubs are not created by policy or regulation, but are
created by trade and traders. For countries that have traditions
of government intervention in the markets, even if the gas
market is liberalized, creditability has to be established for a
market of free from intervention. Credible state commitments
to regional gas market competition can instil confidence,
encourage new market participants, and promote the use of
transparent hubs to balance producer portfolios.
6. Conclusion
The European experience highlights that market liber-
alization and transition of gas pricing mechanism are neces-
sary in creating competitive markets that are needed for
364 Shi X.P. / Natural Gas Industry B 3 (2016) 357e366
functional gas hubs. Political will and regulations further
safeguard the competition environment needed for hub
development. Natural factors, such as domestic production and
culture could have a significant impact on the hub develop-
ment and pricing transition.
In contrast to the European experience, the lack of indig-
enous production and inter-connectivity, vertically integrated
industrial structure, the traditional preference of supply secu-
rity, and unclear political signals, suggest that the development
of regional LNG trading hubs in East Asia might be more
difficult than in Europe. However, the potential of gas demand
growth offers East Asia an additional opportunity that does not
exist in Europe: East Asia can apply new models for new
contracts and thus start the transition with little effect on
vested interests.
In order to creating functional hubs and transiting to hub
indexation, East Asian governments will have to develop in
such areas as gas and electricity market liberalization, transi-
tion of oil indexation pricing formula to hub indexation, and
readjustment of government roles to boost competition.
Enhancing flexibility in LNG markets to create a regional
LNG trading hub and integrating gas markets to create gas
trading hubs should be tried. Regional cooperation among
consumers and between consumers and producers are should
be enhanced.
Even if some East Asian countries are determined to
develop their hubs, there is little chance to have one by 2030.
The market liberalization and transition to hub indexation
often take more than decade and the process is costly and
challenging.
Acknowledgement
The author is grateful for those institutions and experts who
were interviewed in Europe, China, Japan and Singapore. The
institutions that were interviewed include gas/LNG traders
(EDF Gas), Exchanges (ICE, Powernext, and ICE-ENDEX),
hub operators (Gasunie), information providers (Thomson
Reuters), IEA, industrial players (Nexant and Team Consul-
tant), and academic institutes (Clingendael International En-
ergy Programme (CIEP), Delft University of Technology, and
Universit
e Paris-Dauphine). Some leading scholars such as
Jonathan Stern and Keunwook Paik (Both from Oxford Insti-
tute of Energy Studies) were also interviewed. The report is
also benefits from comments from Christopher Len, Melissa
Low, Hari MP, Elena Reshetova, Jacqueline Tao and Monique
Taylor. Thanks also go to the Singapore Ministry of Trade and
Industry for sponsoring the research.
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